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 source 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 Assessment 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 Backstop (WEB) Emissions & Allowance 

Tracking Systerm (EATS) Analysis 

Appendix A-8c. Recommendations for Making 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 Status of Incorporating Smoke Effects 

into Fire Planning and Operation” 

Appendix A-10b. EPA’s “Interim Air Quality 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 Related to the Promulgation of Revised 

Arizona R18-2-602, “Unlawful Open Burning” and Article 15, 

“Forest and Range Management Burns” 

Appendix A-10e. WRAP “Policy on Fire Tracking Systems” 

Appendix A-10f. WRAP report “Nonburning Alternatives for Vegetation and 

Fuel Management” 

Appendix A-10g. WRAP report “Burning Management Alternatives on 

Agricultural Lands in the 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 Prevention Work Group Review of WRAP 

Policy on Renewable Energy and Energy Conservation 

Appendix A-12b. Details of Renewable 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 Discussions with Federal Land Managers on 

Emissions In-and-Near the Four Arizona GCVTC Class I 

Areas 

APPENDIX A-14. PROJECTION OF VISIBILITY 

Appendix A-14a. Arizona Technical Review Memoranda of WRAP Emission 

Inventories and Technical Support Document 

Appendix A-14b. Summary of Emission Inventories used in WRAP Modeling 

APPENDIX A-18. PUBLIC PARTICIPATION 

Appendix A-18a. Notices of Public Hearings 

Appendix A-18b. Hearing Agendas, Sign-in Sheets, Transcripts, and 

Certifications 

Appendix A-18c. Written Comments Received During Comment Period 

Appendix A-18d. Responsiveness Summary 
Appendix A-1. Background Arizona Regional Haze SIP

APPENDIX A-1. BACKGROUND

This appendix contains work products and references relied upon by Arizona in the 

development of Chapter 1 of the Regional Haze SIP. 
Appendix A-1. Background Arizona Regional Haze SIP

Appendix A-1a. Definitions
Appendix A-1. Background Arizona Regional Haze SIP

Applicable definitions from 40 CFR 51.301:

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

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, which is emitted by an existing stationary facility. The emission 

limitation must be established, on a case-by-case basis, taking into consideration the technology 

available, the costs of compliance, the energy and non-air quality environmental impacts of 

compliance, any pollution control equipment in use or in existence at the source, the remaining 

useful life of the source, and the degree of improvement in visibility which may reasonably be 

anticipated to result from the use of such technology. 

Deciview means a measurement of visibility impairment. 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 entire range of conditions, from pristine to highly 

impaired. The deciview haze index is calculated 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 1ne (bext/10 Mm-1). 

Where bext = the atmospheric light extinction coefficient, expressed in inverse megameters (Mm1

). 

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. 

Fossil-fuel fired steam electric plants of more 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 charging more than 250 tons of refuse per day, 

Hydrofluoric, sulfuric, and 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 facilities 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 classified or reclassified Class I. 

Federal Land Manager means the Secretary of the department 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-Campobello 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 any applicable State Implementation Plan, and any 

permit requirements established pursuant to Sec. 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 Native village, which is federally recognized as eligible for the 

special programs and services provided by the United States to Indians because of their status as 

Indians. 

In existence means that the owner or operator has 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 the facility or (2) entered into binding agreements or contractual 

obligations, which cannot be cancelled or modified 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 calendar year with the lowest amount of visibility 

impairment. 
Appendix A-1. Background Arizona Regional Haze SIP

Major stationary source and major modification mean major stationary 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 impairment (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 that 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 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 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 observation 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 caused 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 sources, mobile sources, and area sources. 

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

Stationary Source means any building, structure, facility, 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 natural 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 Wilderness, Petrified Forest National Park, 

Mount Baldy Wilderness, San Pedro Parks Wilderness, Mesa Verde National Park, Weminuche 

Wilderness, Black Canyon of the Gunnison Wilderness, West Elk Wilderness, Maroon Bells 

Wilderness, Flat Tops Wilderness, Arches National Park, Canyonlands National Park, Capital 

Reef National Park, Bryce Canyon National 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 Transport 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 conducted and occurring on Federal, State, and private wildlands and 

farmlands. 

Milestone means the maximum level of annual regional sulfur dioxide emissions for a given 

year, assessed annually consistent with paragraph (h)(2) of this section beginning in the year 

2003. 

Mobile Source Emission Budget means the lowest level of VOC, NOx, SO2, 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 suspended 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 suspended during the year 2000, (ii) The same 

smelter in the event of a change of name or ownership. 

Definitions for the Fire Programs 

Land Manager means any federal, state, local, or private entity that owns, administers, directs, 

oversees or controls the use of public or private land, including the application of fire to the land. 

Prescribed fire or prescribed 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 wildland 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 SO2 WEB allowance allocated to tribes on an annual basis. 

The tribes will decide how to distribute the allowances 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 SO2 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 SO2

emissions are reduced. 

Western Regional Air Partnership (WRAP) means the collaborative effort of tribal 

governments, state governments, and federal agencies to promote and monitor implementation of 

recommendations from the Grand Canyon Visibility Transport Commission authorized under 

Section 169B(f) of the Clean Air Act, and to address other common Western 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 Charts
Appendix A-2. Descriptions of Arizona Arizona Regional Haze SIP








Appendix A-2. Descriptions of Arizona Arizona Regional Haze SIP

APPENDIX A-2. DESCRIPTIONS OF ARIZONA

This appendix contains work products and references relied 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 2
Appendix 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 likely 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 Security. David Lillie. August 1986. A Demographic 

Guide To Arizona 1985. Population Statistics 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/kai/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/grcan 
Appendix 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/geos256/azgeology/pwood/parkintro 

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

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

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

APPENDIX A-5. ATTRIBUTABLE IMPAIRMENT

This appendix contains work products and references relied upon 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 rule
Arizona 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 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.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 any

existing 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 available

retrofit 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 Register first 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 and 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 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 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 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 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 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 addition of acid plants for the reduction of SO2 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 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 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 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), 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
Arizona Administrative Register / Secretary of State

Notices of Final Rulemaking

October 24, 2003 Page 4543 Volume 9, Issue 43

for 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 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 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 NOx, 141,036 tons per year for SO2, 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 to

install 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 visibility
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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 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 through the 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, 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 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 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

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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. 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 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.
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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 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 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 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 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 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,

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

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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 CONTROL
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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 change
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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 change
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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 change
Arizona 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 change
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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 change
Arizona 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 change
Volume 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. 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 through 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 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 shall

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 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 the name
Volume 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 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,

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, 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 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 to

impairment 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 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-5b. Notification letters to FLMS on contact person, and 

Public Comment Period
3033 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 visibility 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 Division
3033 North Central Avenue, Phoenix, Arizona 85012, (602)207-2300

cc: Mike George, ADEQ

 Theresa Pella, ADEQ

 Pete Lahm, ADEQ
 

ARIZONA DEPARTMENT

OF

ENVIRONMENTAL QUALITY

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 recycled paper

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 accordance with 40 CFR 51.302(a)(2)(ii), 

regarding the availability of a draft Regional Haze State Implementation Plan (SIP) for Arizona. 

In April 2000, I sent notices to the federal land managers that Arizona was beginning to develop 

a state implementation plan to address visibility impairment in the Class I areas. Arizona’s 

Regional Haze SIP will address visibility impairment 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, Petrified 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 comment period and dates/locations of the public hearings will be 

sent separately. The SIP must be submitted 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 
 

ARIZONA DEPARTMENT

OF

ENVIRONMENTAL QUALITY

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 recycled paper

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 accordance with 40 CFR 51.302(a)(2)(ii), 

regarding the availability of a draft Regional Haze State Implementation Plan (SIP) for Arizona. 

In April 2000, I sent notices to the federal land managers that Arizona was beginning to develop 

a state implementation plan to address visibility impairment in the Class I areas. Arizona’s 

Regional Haze SIP will address visibility impairment 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, Petrified 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 comment period and dates/locations of the public hearings will be 

sent separately. The SIP must be submitted 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 

 
 

ARIZONA DEPARTMENT

OF

ENVIRONMENTAL QUALITY

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 recycled paper

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 accordance with 40 CFR 51.302(a)(2)(ii), 

regarding the availability of a draft Regional Haze State Implementation Plan (SIP) for Arizona. 

In April 2000, I sent notices to the federal land managers that Arizona was beginning to develop 

a state implementation plan to address visibility impairment in the Class I areas. Arizona’s 

Regional Haze SIP will address visibility impairment 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, Petrified 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 comment period and dates/locations of the public hearings will be 

sent separately. The SIP must be submitted 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 
 

ARIZONA DEPARTMENT

OF

ENVIRONMENTAL QUALITY

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 recycled paper

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 accordance with 40 CFR 51.302(a)(2)(ii), 

regarding the availability of a draft Regional Haze State Implementation Plan (SIP) for Arizona. 

In April 2000, I sent notices to the federal land managers that Arizona was beginning to develop 

a state implementation plan to address visibility impairment in the Class I areas. Arizona’s 

Regional Haze SIP will address visibility impairment 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, Petrified 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 comment period and dates/locations of the public hearings will be 

sent separately. The SIP must be submitted 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 
 

ARIZONA DEPARTMENT

OF

ENVIRONMENTAL QUALITY

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 recycled paper

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 accordance with 40 CFR 51.302(a)(2)(ii), 

regarding the availability of a draft Regional Haze State Implementation Plan (SIP) for Arizona. 

In April 2000, I sent notices to the federal land managers that Arizona was beginning to develop 

a state implementation plan to address visibility impairment in the Class I areas. Arizona’s 

Regional Haze SIP will address visibility impairment 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, Petrified 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 comment period and dates/locations of the public hearings will be 

sent separately. The SIP must be submitted 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 
 

ARIZONA DEPARTMENT

OF

ENVIRONMENTAL QUALITY

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 recycled paper

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 accordance with 40 CFR 51.302(a)(2)(ii), 

regarding the availability of a draft Regional Haze State Implementation Plan (SIP) for Arizona. 

In April 2000, I sent notices to the federal land managers that Arizona was beginning to develop 

a state implementation plan to address visibility impairment in the Class I areas. Arizona’s 

Regional Haze SIP will address visibility impairment 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, Petrified 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 comment period and dates/locations of the public hearings will be 

sent separately. The SIP must be submitted 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 
 

ARIZONA DEPARTMENT

OF

ENVIRONMENTAL QUALITY

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 recycled paper

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 accordance with 40 CFR 51.302(a)(2)(ii), 

regarding the availability of a draft Regional Haze State Implementation Plan (SIP) for Arizona. 

In April 2000, I sent notices to the federal land managers that Arizona was beginning to develop 

a state implementation plan to address visibility impairment in the Class I areas. Arizona’s 

Regional Haze SIP will address visibility impairment 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, Petrified 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 comment period and dates/locations of the public hearings will be 

sent separately. The SIP must be submitted 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 
 

ARIZONA DEPARTMENT

OF

ENVIRONMENTAL QUALITY

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 recycled paper

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 accordance with 40 CFR 51.302(a)(2)(ii), 

regarding the availability of a draft Regional Haze State Implementation Plan (SIP) for Arizona. 

In April 2000, I sent notices to the federal land managers that Arizona was beginning to develop 

a state implementation plan to address visibility impairment in the Class I areas. Arizona’s 

Regional Haze SIP will address visibility impairment 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, Petrified 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 comment period and dates/locations of the public hearings will be 

sent separately. The SIP must be submitted 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 
 

ARIZONA DEPARTMENT

OF

ENVIRONMENTAL QUALITY

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 recycled paper

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 accordance with 40 CFR 51.302(a)(2)(ii), 

regarding the availability of a draft Regional Haze State Implementation Plan (SIP) for Arizona. 

In April 2000, I sent notices to the federal land managers that Arizona was beginning to develop 

a state implementation plan to address visibility impairment in the Class I areas. Arizona’s 

Regional Haze SIP will address visibility impairment 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, Petrified 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 comment period and dates/locations of the public hearings will be 

sent separately. The SIP must be submitted 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 
 

ARIZONA DEPARTMENT

OF

ENVIRONMENTAL QUALITY

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 recycled paper

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 accordance with 40 CFR 51.302(a)(2)(ii), 

regarding the availability of a draft Regional Haze State Implementation Plan (SIP) for Arizona. 

In April 2000, I sent notices to the federal land managers that Arizona was beginning to develop 

a state implementation plan to address visibility impairment in the Class I areas. Arizona’s 

Regional Haze SIP will address visibility impairment 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, Petrified 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 comment period and dates/locations of the public hearings will be 

sent separately. The SIP must be submitted 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 
 

ARIZONA DEPARTMENT

OF

ENVIRONMENTAL QUALITY

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 recycled paper

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 accordance with 40 CFR 51.302(a)(2)(ii), 

regarding the availability of a draft Regional Haze State Implementation Plan (SIP) for Arizona. 

In April 2000, I sent notices to the federal land managers that Arizona was beginning to develop 

a state implementation plan to address visibility impairment in the Class I areas. Arizona’s 

Regional Haze SIP will address visibility impairment 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, Petrified 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 comment period and dates/locations of the public hearings will be 

sent separately. The SIP must be submitted 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 
 

ARIZONA DEPARTMENT

OF

ENVIRONMENTAL QUALITY

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 recycled paper

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 accordance with 40 CFR 51.302(a)(2)(ii), 

regarding the availability of a draft Regional Haze State Implementation Plan (SIP) for Arizona. 

In April 2000, I sent notices to the federal land managers that Arizona was beginning to develop 

a state implementation plan to address visibility impairment in the Class I areas. Arizona’s 

Regional Haze SIP will address visibility impairment 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, Petrified 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 comment period and dates/locations of the public hearings will be 

sent separately. The SIP must be submitted 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 
 

ARIZONA DEPARTMENT

OF

ENVIRONMENTAL QUALITY

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 recycled paper

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 accordance with 40 CFR 51.302(a)(2)(ii), 

regarding the availability of a draft Regional Haze State Implementation Plan (SIP) for Arizona. 

In April 2000, I sent notices to the federal land managers that Arizona was beginning to develop 

a state implementation plan to address visibility impairment in the Class I areas. Arizona’s 

Regional Haze SIP will address visibility impairment 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, Petrified 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 comment period and dates/locations of the public hearings will be 

sent separately. The SIP must be submitted 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 
 

ARIZONA DEPARTMENT

OF

ENVIRONMENTAL QUALITY

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 recycled paper

August 22, 2003 

Mr. Mike Williams, Federal Land Manager 

Sycamore Canyon Wilderness 

800 S. 6th 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 accordance with 40 CFR 51.302(a)(2)(ii), 

regarding the availability of a draft Regional Haze State Implementation Plan (SIP) for Arizona. 

In April 2000, I sent notices to the federal land managers that Arizona was beginning to develop 

a state implementation plan to address visibility impairment in the Class I areas. Arizona’s 

Regional Haze SIP will address visibility impairment 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, Petrified 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 comment period and dates/locations of the public hearings will be 

sent separately. The SIP must be submitted 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 
 

ARIZONA DEPARTMENT

OF

ENVIRONMENTAL QUALITY

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 recycled paper

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 accordance with 40 CFR 51.302(a)(2)(ii), 

regarding the availability of a draft Regional Haze State Implementation Plan (SIP) for Arizona. 

In April 2000, I sent notices to the federal land managers that Arizona was beginning to develop 

a state implementation plan to address visibility impairment in the Class I areas. Arizona’s 

Regional Haze SIP will address visibility impairment 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, Petrified 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 comment period and dates/locations of the public hearings will be 

sent separately. The SIP must be submitted 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 Williams 

 
Appendix A-5 – Attributable Impairment Arizona Regional Haze SIP

Appendix A-5c. Supporting Documents Related To The Promulgation 

Of Arizona’s RAVI Rule
ARIZONA DEPARTMENT

OF

ENVIRONMENTAL QUALITY

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, formerly 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 the 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 state 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/environ/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 14th. If you have any questions regarding the meeting,

please call me at (602) 771-2308 or Corky Martinkovic at (602) 771-2372, or by e-mail at

martinkovic.deborrah@ev.state.az.us. If you are in Arizona, but outside of the Phoenix area, call

1-800-234-5677, then dial extension 771-2372. Copies of the draft NPRM will also be available

at the January 14th 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 stationary sources emitting 250 tons per year or more of 

visibility impairing air pollutants in or near Arizona’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 Rulemaking will be held on Wednesday, April 7, 2003, 

at the Coconino Library, 300 W. Aspen, Flagstaff, 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 (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 stationary sources emitting 250 tons per year or more of 

visibility impairing air pollutants in or near Arizona’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 Rulemaking will be held on Wednesday, April 8, 2003, 

at the Arizona Department of Environmental Quality, 1110 W. Washington Street, Room 145, 

Phoenix, 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, 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 stationary sources emitting 250 tons per year or more of 

visibility impairing air pollutants in or near Arizona’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 Rulemaking will be held on Wednesday, April 9, 2003, 

at the State Office Building, 400 W. Congress, Room 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) 628-6902 
ADEQ 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:

Notice 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 Washington 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.us
ADEQ 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 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 any existing 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 available 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 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 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 determination of possible source attribution will be performed by the states. Therefore, Arizona needs 
ADEQ 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 possible 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 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 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 addition of acid plants for the reduction of SO2 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 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 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 areas 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 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 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), 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 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 any 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, 

all data underlying each study, and any analysis of each study and other supporting

material:

Not Applicable
ADEQ 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 Managers (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 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. 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 those 

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 sources. 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 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 proposed rule. The combined potential to emit 
ADEQ RAVI NPRM, 2/4/03 6

from these sources totaled 94,287 tons per year for NOx, 141,036 tons per year for SO2, 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 proposed rules become 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 proposed R18-2-1605(A) 

and will be moderate, but less expensive than the attribution analysis. These costs will be primarily born 

by the Permits 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, unlike 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 found 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 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 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 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.
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 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 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 requirements 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 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 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 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 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 establish 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 requests 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 consumer 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.

Location: 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 applicable

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

Section

R18-2-101 Definition of “visibility impairment” .................................Amend

ARTICLE 16. VISIBILITY; REGIONAL HAZE

Section

R18-2-1601 Definitions ...............................................................New Section

R18-2-1602 Applicability .............................................................New Section

R18-2-1603 Certification 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 Section

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
ADEQ 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 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 change

27. No change

a. No change
ADEQ 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 change
ADEQ 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

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 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
ADEQ 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

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
ADEQ 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 change
ADEQ 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. No change

87. No change

88. No change

89. No change

90. No change

91. No change

92. No change

93. No change

94. No change
ADEQ 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 change

b. No change

100. No change

101. No change

102. No change

103. No change

104. No change

a. No change

b. No change
ADEQ 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 change
ADEQ 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 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
ADEQ 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 impairment” 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. No change

v. No change
ADEQ 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 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. 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 
ADEQ 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 accordance 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 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, 
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 ascribable 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 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 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 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 
ADEQ RAVI NPRM, 2/4/03 24

Class I area, 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 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 analysis, 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 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.

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 Director 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 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 

draft attribution finding should be reviewed. A final attribution finding shall 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 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 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, and shall clearly set 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 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 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 source 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 the 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 

install 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 impairment 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 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 this Article, 

may apply to the Administrator for an exemption from that requirement by obtaining prior written 

concurrence 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

ARIZONA DEPARTMENT

OF

ENVIRONMENTAL QUALITY

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 hearing did follow verbatim the text of the 

public hearing officer script; therefore, that script has 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 afternoon, thank you for coming. This oral 

proceeding is on the proposed Reasonably Attributable 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 emissions 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 been appointed by the Director of the 

Arizona Department of Environmental Quality 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 argument, data and views regarding the 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 available 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 comment period are required by law to be 

considered by the Department in the preparation of the final rulemaking. This is done 

through the preparation of a concise explanatory statement in which the Department 

responds in writing to written and oral comments made during the formal comment 

period. 

The agenda for this hearing is simple. First, 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 period. 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 Impairment Rule, or RAVI for short, will, 

upon approval, become a new section in the 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 pollution that can reduce visibility in national 

parks and wilderness areas. This type of pollution 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 operations, 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 wilderness areas are managed by Federal Land 

Managers. Federal Land Managers are able to “certify” for the national park or 

wilderness area for which they have jurisdiction 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 receives 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 sources 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 the rule, is “reasonably attributable.” 

If the source is eligible for emission controls 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 application and operation of emission 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 under 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 BART 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 federal- 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 submitted 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 the 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, written 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

ARIZONA DEPARTMENT

OF

ENVIRONMENTAL QUALITY

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

ARIZONA DEPARTMENT

OF

ENVIRONMENTAL QUALITY

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 personnel with whom persons may communicate 

regarding the rulemaking. 

 Name: Deborrah “Corky” Martinkovic 

Address: ADEQ, Air Quality Planning Section, 1110 West Washington Street, 
ADEQ RAVI NFRM, 8/11/03+ 2

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.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 any existing 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 available 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 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 
ADEQ 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 visibility impairment for 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 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 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 addition of acid plants for the reduction of SO2

emissions, these emission controls would not themselves trigger a BART review.”1

 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 

 

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 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 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 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 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), 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 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 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 or 
ADEQ RAVI NFRM, 8/11/03+ 5

justification for the rule, 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 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 to 
ADEQ 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 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 NOx, 141,036 tons per year for SO2, 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 to install 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 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 not 
ADEQ 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 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 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 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 through the 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, 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 rule 
ADEQ 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 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 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 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: 
ADEQ RAVI NFRM, 8/11/03+ 9

 123124. “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. 

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,;
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 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. 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 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 
ADEQ 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 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 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 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, 
ADEQ RAVI NFRM, 8/11/03+ 12

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 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 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 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 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). 

 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
ADEQ RAVI NFRM, 8/11/03+ 14

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 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 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 
ADEQ 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 BART
ADEQ 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, 49-421, 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 

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 f. No change 

 11. No change 

 a. No change 

 b. No change 

 c. No change 

 12. No change 

 13. No change 

 14. No change 
ADEQ RAVI NFRM, 8/11/03+ 18

 a. No change 

 b. No change 

 15. No change 

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 36. No change 

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 40. No change. 

 41 No change 

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ADEQ RAVI NFRM, 8/11/03+ 19

 b. No change 

 c. No change 

 d. No change 

 e. No change 

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ADEQ RAVI NFRM, 8/11/03+ 20

 d. No change 

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 58. No change 

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 ix. No change 

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ADEQ RAVI NFRM, 8/11/03+ 21

 64. No change 

 a. No change 

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 c. No change 

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ADEQ 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 

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 ii. No change 

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 73.74. No change 

 74.75. No change 

 75.76. No change 

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 77.78. No change 

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ADEQ RAVI NFRM, 8/11/03+ 23

 81.82. No change 

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 98.99. No change 

 a. No change 

 i. No change 
ADEQ RAVI NFRM, 8/11/03+ 24

 ii. No change 

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ADEQ RAVI NFRM, 8/11/03+ 25

 116.117. No change 

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 cc. No change 

 dd. No change 

 ee. No change 
ADEQ 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 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 
ADEQ 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 change 
ADEQ 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 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; 
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 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 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 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 
ADEQ 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, 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 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 shall 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; 
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 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 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 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 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
ADEQ RAVI NFRM, 8/11/03+ 32

 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 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, 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, 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 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.
ADEQ RAVI NFRM, 8/11/03+ 33

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 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 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 - R18-2-410
R18-2-410. Visibility Protection 

A. For any new major source or major modification subject to the provisions of this Chapter, no permit or permit 

revision under this Article shall be issued 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 purposes and by such means as 

the Director determines is necessary and appropriate. 

B. A determination of an adverse impact on visibility shall 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 conditions in the area that reduce visibility; 

3. All of the following visibility 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 modification 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 permit 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 anticipated 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 provided 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 provided by the Federal Land Manager 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 Article 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 Section R9-3-410 renumbered without 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 and references relied upon 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. EMISSIONS TRACKING – §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.

POINT SOURCES. 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.

AREA AND MOBILE SOURCES. 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. BOUNDARY OF THE CLEAN AIR CORRIDOR – §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 air

quality 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. IDENTIFICATION OF EMISSIONS INCREASES – §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 SO2 were emitted in 1990 and 73,756 were emitted in 1996;

232,704 tons of NOx 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. PM10 and PM2.5 emissions are expected to increase about 7%

and 18%, respectively. NOx and VOC emissions, however, are expected to decrease about 15%

and 26%, respectively. SO2 emissions are expected to increase about 5% within the corridor,

even with the declining milestones of the backstop emissions trading program. Overall, SO2

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 SO2 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 SO2.

 

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, SO2 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. IF IMPAIRMENT OF AIR QUALITY IN THE CORRIDOR IS IDENTIFIED – §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. DO OTHER CORRIDORS EXIST? – §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 SO2 Milestones Are Met).

Point Area On Road Non Road Paved Unpaved Total

SO2 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

PM10 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

PM2.5 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: 1406601 
EA 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 Exchange 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 ............................................................................................................... 31 

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 PARTICIPANTS 
EA Engineering, Science, and Technology FINAL TECHNICAL REPORT

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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 BONDARIES
EA Engineering, Science, and Technology FINAL TECHNICAL REPORT

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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. Human-caused haze sources include industry, 

motor vehicles, agricultural and forestry burning, 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 wilderness 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 across 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 strategies 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 Mexico, Oregon, Utah, and 

Wyoming - and the two hundred eleven (211) Tribes 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 the 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 (SO2) stationary sources, fire sources, mobile sources, and 

windblown dust sources among other requirements. 

1.2 Consolidated Emission 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 (PM2.5), regional haze, and statewide reporting of area 

and mobile source emissions. In fact, new inventories will add PM2.5 and ammonia (NH3). 

Currently area and mobile sources are reported 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 years or one-third of the sources every year. 
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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 consistent and model-independent nature. Therefore, it seeks to 

develop data exchange formats and naming conventions so that emissions modelers from the five 

RPOs and states and tribes have common datasets from which to pursue regulatory modeling of 

ozone (O3), regional haze, and PM. It includes nine different protocols: 

Industrial point source protocol 

Area source protocol 

Temporal allocation and profile assignment protocol 

On-road mobile sources protocol 

Off-road mobile sources protocol 

Continuous emissions monitoring and day-specific protocol 

Spatial surrogate 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, state governments, and various federal agencies to 

implement the recommendations of the GCVTC and 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 emissions 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 subject to state jurisdiction. 

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

implement CAA programs, including visibility regulation, or "reasonably severable" 
EA Engineering, Science, and Technology FINAL TECHNICAL REPORT

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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. 

The RHR 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 FR 35756), and 

that the authority to implement Section 309 TIPs extends to all tribes within the GCVTC 

region (40 CFR 51.309(d)(12)). 

The EPA has indicated that under the TAR, tribes 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 basis in developing tribe-specific or generally 

applicable TIPs where necessary (63 FR 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. 

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

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

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

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

this equality of representation on the Board, tribes are very differently situated than states. There 

are over four hundred (400) 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, it is 

anticipated that the tribal participants will join the 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 regional 
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haze implementation plan (SIP/TIP) development. The system is to be capable of receiving and 

storing emissions data in EPA-compliant emissions reporting formats commonly used by various 

agencies and sources with little or no additional effort, producing user-specified reports, 

performing user-selected quality control and assurance tests, allowing data queries and graphic 

display, and presenting this information in geographic information system (GIS) format. 

The EF contracted with EA Engineering, Science, 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 operation of the recommended data management 

system, by integrating information gathered in Tasks 1 and 2. 

This report presents the results of Task 3 and represents the final technical report of the project. 

It provides the documentation from the two workshops and questionnaires, the findings based on 

the input received from the two workshops and questionnaires, an evaluation of existing EDMS, 

and the system recommendations. 
EA Engineering, Science, and Technology FINAL TECHNICAL REPORT

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2.0 WORKSHOP AND QUESTIONNAIRE FINDINGS 

2.1 Description of the Workshops 

The WRAP EDMS needs assessment survey consisted of two interview workshops. The first 

workshop took place in Santa Fe, New Mexico, on March 20th, 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 presentation of the conceptual WRAP EDMS, and the 

conceptual timeline of the development and population 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 7th, 2003 and was planned in 

order to provide an opportunity for state, tribe, and local (STL) air pollution control agencies 

staff and other stakeholders to participate in the project. Prospective attendees were notified by 

email several weeks prior to the meeting, and via an online questionnaire. Thirteen (13) people 

attended this day long workshop. The session included 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 timeline 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 Fire Emission Joint Forum (FEJF) and specific 

discussions on the WRAP EDMS needs were brought up during and after the presentations. 

Appendices B1, B2, and B3 present the EA presentation, 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 interview workshop, a web-based questionnaire was 

posted on http://wrap.eaest.com for a period of three months. All potential users of the WRAP 

EDMS, stakeholders, and interested 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. Furthermore, 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 intent 
EA Engineering, Science, and Technology FINAL TECHNICAL REPORT

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to accommodate several distinct user groups. The WRAP EDMS will not only be a repository of 

the WRAP regional emissions inventories but will also be able to be used to implement the 

emissions tracking and reporting requirements of the RHR. The WRAP EDMS would be located 

either at the WRAP regional modeling center (RMC) or at a university center as is the 

monitoring database. Moreover, it will be made publicly accessible through the internet and will 

contain online training manuals. 

The WRAP EDMS will track all the visibility-impairing pollutants: volatile organic compounds 

(VOC), nitrogen oxides (NOx), SO2, PM10, PM2.5, elemental carbon (EC), organic carbon (OC), 

carbon monoxide (CO), and NH3 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 sources 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 estimated 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 inclusion 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 phases. In Phase I, the system will include the core database 

architecture, including all of the functioning modules and all of the 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 reporting requirements of both Sections 308 and 309. The focus will 

be on the implementation of the emissions tracking and reporting requirements of the CAC, fire 

sources, stationary SO2 sources, and mobile sources. The minimum spatial resolutions of the 

emissions data will be the county 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 incorporate new and updated technical functionality 

that would allow for storage, tracking, and reporting of hourly, daily, seasonal, and annual 

emissions data as necessary. The system would include others pollutants (e.g. methane (CH4), 

mercury (Hg), etc) and their emissions data. It may be used to track other RHR requirements 
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(e.g. annual emission goals) and other regulations (e.g. Clear Skies, Greenhouse Gas, etc) 

requirements. 

There was general agreement that the WRAP EDMS will be built and tested 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 for both Sections 308 and 309. From 2005 to 2007, annual emissions 

will be generated from the 2002 comprehensive emissions 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 strategies 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 submitted by tribal agencies may be from any given 

inventory year. Moreover, wherever tribal emissions data are available, the state should adjust 

its inventory taking into account these tribal data. 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, processing, 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 years' 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 inventories representing the effect of control strategies in 

2018 

3. Provide training and user support 

4. Populate the WRAP EDMS with annual emissions 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 include six major modules representing the sources 

(point, area, fire, mobile, windblown dust, and biogenic) in addition to the GIS, QA/QC, and 

database administrator (DBA) modules. The submission formats will be similar to that of the 
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NEI format (NIF) and the minimum submission cycle would coincide with the submission cycle 

of the NEI (annual and triennial cycles). However, 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), and eXtended Markup Language (XML). The results of the 

questionnaire indicated that, across the WRAP region, 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 all 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. 
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3.0 COMPARATIVE ANALYSIS 

3.1 Conceptual WRAP EDMS 

The conceptual WRAP EDMS was developed based on the findings of the interview workshops 

and the web-based questionnaire. 

3.1.1 Data Tracking 

The WRAP EDMS should contain all visibility-impairing pollutants: VOC, NOx, SO2, PM10, 

PM2.5, EC, OC, CO, and NH3. The WRAP EDMS should also track 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 validation of the format of the submitted data files. 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 STL 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 ranges 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 standard summary reports broken down by source 

type, geographic location, and pollutant. It should also include a series of reports designed 

specifically to meet the RHR emissions tracking and reporting requirements. The RHR reports 

will include special reports for CAC, pre-trigger SO2 stationary sources, mobile sources, fire 

sources, and windblown dust sources. The WRAP EDMS 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 to 
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select data that is of importance to them and display the data in a fashion that is easily 

understood. The WRAP EDMS should include the following GIS functionality: pan, zoom, 

query layer information, ability to add/remove multiple 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 should 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 separate, non-public interface for submitting their data to a central 

submission area. The user interface for the WRAP EDMS should be easy and intuitive to use 

while providing all necessary 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 emissions 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 required pollutants or sources. Without 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 Group (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 District of Columbia. The NEI has a public website 
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(http://www.epa.gov/air/data/index.html) where users 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, NOx, SO2, PM10, PM2.5, CO, and NH3. The pollutants 

are tracked for four source types: point, area, mobile, and biogenic sources. All data is tracked at 

the county level for all sources, and also individually 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 summary reports broken down by source category, 

geographic location, and pollutant. The NEI also includes a data export feature 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 navigate 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 for all data sources, except for fire sources. 

The submission format captures the required emissions and activity data for all pollutants except 

OC and EC, which can be calculated by the WRAP system, based on the PM2.5 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 defined 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 WRAP EDMS could adopt a 
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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 could make recommendations for replacing 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 detailed 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 exhaustive, 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 the general data gathering and 

reporting capabilities of its system. 

3.3.2 Tribal Emissions Inventory Software Solution – TEISS 

Northern Arizona University is currently developing 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, NOx, SO2, PM10, PM2.5, CO, and NH3. The pollutants 

are tracked for three source types: point, area, and mobile sources. All data is tracked at the 

reservation level for all sources, and also individually for point sources. 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 reports 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 includes several advanced GIS features including: pan, zoom, query 

layer information, ability to add/remove 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 layers 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. 
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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 the 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 exporting functions to allow for multiple data export 

formats. The WRAP EDMS could include a comparable set of exporting features to 

accommodate the need of multiple formats 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 for the state of California. The CARBEI has a 

public website (http://www.arb.ca.gov/emisinv/eib.htm) where users can query the emissions 

database and produce reports based on their specific needs. 

3.3.3.1 System Details 

The CARBEI tracks five pollutants: NOx, SO2, PM10, PM2.5, and CO. The pollutants are tracked 

for three sources 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 

in the California Air Resources Board’s standard 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 level 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 reports broken down by source category, geographic 

location, and pollutant. The CARBEI also includes 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. 
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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 for the state of Colorado. The CAPI has a public 

website (http://emaps.dphe.state.co.us/APInv/viewer.htm) where users can query the emissions 

database and produce reports 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, NOx, SO2, PM10, 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 module that provides multiple tools to visually 

display data. The CAPI includes several advanced GIS features including: pan, zoom, query 

layer information, ability to add/remove 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 state boundaries, and various attainment 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 created in the system. Although the CAPI does not 

have the capability of mapping data from the emissions database, it does represent a good 

example of internet-based GIS functionality. The WRAP EDMS could include this functionality 

in its GIS module to provide its users internet-based GIS capability. 
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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 monitoring 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 produce reports based on their specific needs. 

3.3.5.1 System Details 

At the air emissions level, the DEN tracks five pollutants: VOC, NOx, SO2, PM10, 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 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 advanced 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 polygon. 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 navigate 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 conjunction 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 included 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. 
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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 queries, graphic display, and GIS 

presentation. The sections below explain the different parts of this flow chart. 

4.2 Point Source Module 

For point sources, at a minimum, the emissions data listed below should be submitted, stored, 

and tracked for each inventory. The data file should 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 operation 
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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 resolution basis. According to the CERR, the minimum point source 

reporting thresholds are 100 tons per year (tpy) for VOC, NOx, SO2, PM10, PM2.5, and NH3 and 

1000 tpy for CO. Many states have different 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 discrepancies in order to avoid double counting emissions. 

4.3 Area Source Module

Based on input and discussion, it appears that area sources represent all other stationary sources 

not included in the point source category, excluding fire and windblown dust sources. These 

sources also include open burning activities on residential, commercial, and industrial properties. 

For area sources, at a minimum, the emissions data 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/throughput level (annual) 

11) Total capture/control efficiency (%) 

12) Rule effectiveness (%) 
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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 level 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 categories: onroad and nonroad mobile sources. 

Onroad mobile sources are motor vehicles licensed for use on highways or roadways (i.e. 

automobiles, trucks, etc). Onroad mobile source 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 represented by the vehicle mile 

traveled (VMT). Dust from paved and unpaved 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 sources represented for instance by construction 

equipment, lawn and garden equipment, snowmobiles, 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 Modeling 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 mobile 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. 
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For mobile sources, the emissions data 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 

onroad and nonroad mobile source files contain three and five records 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 emissions 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/throughput 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 operation 
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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 resolution will be the county level and the temporal 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 emissions 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 emissions data 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 biogenic source file contains 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 region-wide through modeling. The emission 

inventories will then be submitted to STL agencies for review and approval before inclusion in 

the final database. The spatial resolution will be the county level 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 (PM10 and PM2.5) are 

currently being estimated using wind data as emissions per grid square. Therefore they will need 

to be converted to a county level before being sent to STL agencies for review and subsequent 

inclusion in the WRAP EDMS. 

For windblown dust sources, at a minimum, the emissions data listed below should be submitted, 

stored, and tracked for each inventory. Windblown dust source is not included in the NEI as a 
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separate source category. Therefore, the data file 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 anthropogenic 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, prescribed fire, wildland fire use include rangeland. Fire sources 

such as open burning activities on residential, commercial, and industrial properties 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 appropriate emissions factors and emission calculation 

techniques. The FTS also identified optional data (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 should 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 burn 
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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 the following standard reports 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. 

A summary report of the annual WRAP emission inventory, compiled at the county and 

reservation levels and totaled for each state, tribe, and the WRAP region, for all 

pollutants, broken down by point, area, mobile, fire, biogenic, and windblown dust source 

categories, and by summed total emissions for all six source categories. 

A summary report of the annual WRAP emissions 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 emissions 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 emissions from the “Top 10” stationary point 

sources in each county and reservation and the “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 emissions from the “Top 10” stationary point 

sources in each county and reservation and the “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 emissions from the “Top 10” area sources in 

each county and reservation and the “Top 10” area sources for each state, tribe and the 

entire region (broken down by SCC code), for each pollutant. 
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A summary report of the annual WRAP emissions from on-road mobile sources in each 

county and reservation and on-road mobile sources 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 emissions from non-road mobile sources in each 

county and reservation and non-road mobile 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 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 emissions 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 Version 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 NEI file format stack parameters (STKHGT, 

STKDIAM, STKTEMP, STKFLOW, STKVEL), production rates (BOILCAP, 

CAP_UNITS, THRUPUT, MAXRATE, NETDC), fuel parameters (HEATCON, 

SULFCON, ASHCON), standard industrial classification 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 actual emission rates of each pollutant, on an 

annual (tpy) and on a short term (pounds per hour) basis. This emission 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 the regional visibility modeling efforts. 

4.9. Special Section 309 Tracking

Section 309 of the RHR requires that the first 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 for the clean air corridors (CAC), stationary 

SO2 sources, mobile sources, fire sources, and windblown dust based on annual emissions. 

4.9.1 Clean Air Corridors (CAC) 

The preamble of the RHR defines a CAC 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 state that the Section 309 SIP/TIP must describe and 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: 
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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, significant 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 identification 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 and 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 examined emissions growth in areas outside the 

corridor and found 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. 

Since impairment of air quality in clean air corridors 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 other clean air corridors 

beyond the corridor identified in Appendix H. 

Consequently, the EDMS should have the capability to produce the following special reports 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 addition to the standard reports. 

A summary report of the annual 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 annual 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 for the same types of political boundaries, as 

well as the entire CAC and the corresponding base year total emissions. 
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4.9.2 Pre-Trigger SO2 Annex 

The SO2 Annex program, as proposed by WRAP and adopted by EPA, requires the tracking of 

SO2 emissions from eligible stationary sources within states or tribal reservations participating in 

Section 309, to determine if the regional SO2 emissions cap has been exceeded. This is known 

as “pre-trigger” tracking. Beginning with the 2003 calendar year and continuing through 2018, 

each state and tribe participating in the program will submit an annual SO2 emissions report to 

the WRAP EDMS for the sources covered by the program. These annual reports will contain the 

following information: 

Identification and explanation for new/additional SO2 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 variations at any covered source that exceeds +/- 20% from the 

previous year. 

Identification and explanation of new emissions reporting methods at any source. 

WRAP will compile the annual emissions reports submitted by the states and tribes participating 

in the program into a regional emission report for SO2 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 SO2 emissions (tpy). 

Identification of any paper emission increases 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 milestone has either been met, or has been exceeded thereby 

triggering the backstop trading program. 

Consequently, The EDMS should have the capability to produce the following special reports 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 addition to the standard reports. 

A summary report of the annual WRAP emissions from the stationary sources emitting 

more than 100 tpy of SO2 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 SO2 that 

were not contained in the previous year’s inventory for each state, tribe and the entire 

region. 

A summary report of the stationary sources emitting more than 100 tpy of SO2 that are 

retired compared to the previous year’s inventory for each state, tribe and the entire 

region. 
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A summary report of the regional average SO2 emissions from stationary sources 

emitting more than 100 tpy of SO2 for the last three years and comparison to the regional 

milestone for the compliance period. 

A summary report of the stationary sources emitting more than 100 tpy of SO2 which 

emissions exceed +/- 20% compared to the previous year’s inventory for each state, tribe 

and the entire region. 

A summary report identifying all the stationary sources emitting more than 100 tpy of 

SO2 that choose to opt in the program for each state, tribe and the entire region. 

A summary report identifying all the stationary sources emitting more than 100 tpy of 

SO2 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, NOX, SO2, PM2.5, 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 capability to produce the following special 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 addition to the standard reports. 

A summary report of the comparison of annual WRAP total (on-road plus nonroad) 

emissions from the mobile sources (VOC, NOx, SO2, PM2.5, EC, OC, and paved and 

unpaved road dust) for each state, tribe and 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 specifically calls for a statewide inventory and 

emissions tracking system (spatial and temporal) of VOC, NOX, EC, OC, and PM2.5 emissions 

from fire. The WRAP inventory will add SO2, PM10, CO, and NH3 emissions. 

Under Section 309, states and tribes must identify 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, adoption, and implementation of enhanced smoke 

management programs, the establishment 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 type of data provided by other WRAP region state, tribal, and 
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local air agencies, and federal/state/private sources using prescribed and/or agricultural burning 

techniques. The WRAP EDMS will calculate the resulting emissions for fire source types 

including prescribed fire, wildfire, wildland fire use, and agricultural burning. 

The EDMS should have the capability to produce a special 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 report 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 organization 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 importance 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 could 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 the 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 polygons 
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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, monuments, forest, and refuges) 

CAC polygons 

International area polygons 

WRAP modeling domain grid system 

Dynamic/Data driven layers 

Select and display emissions sources and associated emissions levels by geographical 

area. 

4.11 DBA Module

All major applications and systems include an administrative 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 administrator(s) and can easily be automated through a 

graphical user interface. Often times there are tasks 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, which will provide the necessary functionality 

required to perform several administrative tasks. During Phase I of development, the WRAP 

EDMS should include the following DBA Functionality. 

User account maintenance – maintain 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 version of all data. 

Data gap filling triggered from a QA/QC check, 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. 
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Data warehousing/archiving – ability to move historical data out of the production 

database and into a WRAP 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 levels 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 should 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 checks 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 widths, begin/end position, data types). 

Are mandatory data elements reported? - The 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 coverage for geographic area, pollutants, source 

categories, and temporal information. 

WRAP will keep a log of errors and problems encountered 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 checked, 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 the following data augmentation processes: 

Calculate EC and OC emissions. 
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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 emissions from tribal reservations that are 

within the county’s boundaries. 

The QA/QC module should perform the following types of data integrity checks. 

Conditional fields - fields required by other fields in the same table. For example, if there 

is a PCT Capture Efficiency in the Control Equipment (CE) table, then there should also 

be a Primary Device Type in the CE Table. 

Acceptable codes - the Pollutant Code (and all acceptable codes) should be consistent. 

Numeric values in acceptable range - For example, 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 largest sources, out of range stacks, stack 

location. 
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5.0 CONCLUSIONS 

Under contract with the WRAP EF, EA performed an EDMS needs assessment that included two 

interview workshops, a web-based questionnaire, 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 results indicated that the WRAP EDMS should be used as the 

repository of WRAP regional emissions 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 sources 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 developed to meet the requirements 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. 
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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), Emission 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), User’s Guide to Mobile6.1 and Mobile6.2: Mobile 

source Emission Factor Model, 2002. 

US Environmental Protection Agency (EPA), Draft User’s Guide to PART5: A Program for 

Calculating Particle Emissions from Motor Vehicles, 1995. 

US Environmental Protection Agency (EPA), Draft NONROAD Model for 2007 HD Highway 

Rulemaking, June 2000. 

US Environmental Protection Agency (EPA), Biogenic Emission Inventory System Version 2.3, 

1998. 

US Environmental Protection Agency (EPA), Compilation 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 and references relied upon 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 SO2 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 opportunity to see how Arizona has currently interpreted 

the Model Rule for state-specific 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 Governors’ 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 SO2 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 for WEB Sources ........................ New Section 

R18-2-1615 Registration ............................................................ New Section 

R18-2-1616 Allowance Allocations .............................................. New Section 

R18-2-1617 Establishment of Accounts ......................................... New Section 

R18-2-1618 Monitoring, Recordkeeping 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 for the 2018 Milestone ............... New Section 

 

ARTICLE 16. VISIBILITY; REGIONAL HAZE 

R18-2-1607. Reserved 

R18-2-1608. Reserved 
R18-2-1609. Reserved 

R18-2-1610. Western Backstop SO2 Trading Program; Definitions 

A. This rule implements the Western Backstop SO2 Trading Program (“WEB Trading 

Program”) provisions required under the federal Regional Haze Rule, 40 CFR 51.309, and 

the SO2 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 requirement otherwise in effect or subsequently 

 required under another program, including 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 regard 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 Rule, 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 authorization under the WEB Trading Program to 

emit one ton of SO2 during a specified control period or any control period 

thereafter subject to the terms and conditions for use of unused allowances as 

established by this Rule. 

7. “Allowance limitation” means the tonnage of SO2 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 noncompliance with this Rule. 

13. “Control period” means the period beginning January 1 of each year and ending 

on December 31 of the same year, inclusive. 

14. “Emissions tracking database” means the central database where SO2 emissions 

for WEB sources as recorded and reported 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 submitted 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 other 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” means any person who is an owner 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 years 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 technologies; 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 referring 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. “SO2 emitting unit” means any equipment that is located at a WEB source and 

that emits SO2. 

30. “Stationary source” means any building, structure, facility or installation that 

emits or may emit any air pollutant subject 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 is 
submitted, 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 any control period, any fraction of a ton 

equaling 1000 pounds or more shall be treated 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 source that meets the applicability requirements 

of Section 1613 of this Rule. 

35. “Western Backstop SO2 Trading Program (“WEB Trading Program”)” means in 

reference to this Rule, the program triggered as a backstop, if necessary, to ensure 

that regional SO2 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 provisions 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 SO2 emissions, beginning with the 2003 emission 

 inventory. 

 a. A source that emits 100 tons per year or more of SO2 in a later year shall 

 continue to submit an SO2 inventory for tracking compliance with the 

 regional SO2 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 report of sulfur input in tons per year 

 with the submission of the annual emissions inventory. 

 2. Utilize appropriate emission factors and estimating techniques, and document the 

 emissions monitoring or estimation methodology used. 

 3. Include emissions from start up, shut down, and upset conditions 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 emissions, the specific installation that is the 

 sources of the air pollution, composition of air contaminant, type and efficiency of 
 the air pollution control equipment, and 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 Trading 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 persons under common control, belonging to the 

same industrial grouping, and that are described in paragraphs (1) through (4) of this 

subsection. A stationary source or group of stationary sources shall be considered part of a 

single industrial grouping if all of the pollutant emitting activities at such source or group 

of sources on contiguous or adjacent properties 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 SO2 emissions. 

2. All stationary sources not meeting the criteria of 1613(A) of this Rule that have 

actual SO2 emissions of 100 tons or more per year in the Program Trigger Years 

or any subsequent year. The fugitive emissions 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 combination 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 category, 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 SO2 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 SO2 emissions of less than 

100 tons per year; and 

b. Had actual SO2 emissions of 100 tons or more in a single year due to a 
temporary 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 failure 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 and 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 may only be considered retired if all SO2

emitting units at the source are retired. The application shall contain the following 

information: 

1. Identification of the WEB source, including 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 source 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 exemption 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 SO2 after the date the retired source exemption 

is effective. 

3. A source shall submit SO2 emissions reports, as required by Section 1618(H) of 

this Rule for any time period the source was 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 SO2 emissions 

prior to the date the source was permanently retired. 

 4. A retired source that is still in existence but no longer emitting SO2 shall, for a 

period of five years from the date the 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 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 with the application 

required under [refer to applicable new source permitting rule]; 

2. If the source is not required to obtain 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 automatically 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 the date that the source is retired shall 

forfeit any unused and future allowances. 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 allowances 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. This 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 allowances may be forfeited so this 

provision does not lead to forfeiture just because the deadline was missed 

Arizona will draft the appropriate notification 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 representation, action, inaction or submission by 

the Account Representative. 

B. Identification and Certification of an Account Representative. 

1. The Account Representative and any Alternate 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 the emission tracking system database in 

accordance with the Implementation Plan. 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 the 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 Representative 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 shall 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 established, 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, SO2 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 submission is made. 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 amaware that there are 
 significant 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 Representative; 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 submitted 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 source, 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 Certificate 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 year 
 in 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 the 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 [state’s New Source 

Review Rule] at any time after this Rule becomes effective must at all times 

possess a permit that includes the requirements 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 

 SO2 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 SO2

valid only for the purpose of meeting the requirements 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 SO2 emissions to a level that is 

below the floor level allocation established 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 referenced below for a minimum of five years 

after the early reduction bonus allowance is certified. 

3. The application for an early reduction bonus allocation must contain the following 

information: 

a. Copies of all permits or other enforceable documents that include annual 

SO2 emissions limits for the WEB source during the period the WEB 

source was generating the early reductions. Such permits or enforceable 

documents require monitoring for SO2 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 equipment 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 SO2 emissions 

and demonstrates that the actual annual SO2 emissions were below the floor level 

allocation established for that source. 

 c. Demonstration that the floor level established for the source was calculated using 

 data consistent with the new monitoring methodology. If new monitoring 

 techniques change the floor level for the 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 SO2 emission limit for that source after the source 

has commenced operation. 

 b. An existing WEB source is eligible to apply for an annual allocation equal 

to the permitted annual SO2 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 the 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 open a compliance account. Any person may 

open a general account for holding and transferring allowances. To open either 

type of account, an application that contains the following information shall be 

submitted: 

 a. The name, mailing address, e-mail 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 required in Section 1614(B)(2) of this 

Rule. For a general account, include the Account Certificate of 

Representation of the Account Representative 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, certification 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 identified and 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 representation, action, 

inaction or submission by the Account Representative. 

C. Identification and Certification of an Account Representative for General Accounts. 
1. The Account Representative shall be appointed by an agreement that makes the 

representations, actions, inactions or submissions of the Account Representative 

binding on all persons who have an ownership 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 the Account Representative or alternate 

Account Representative, as applicable, by an agreement binding on all 

persons who have an ownership interest in allowances in the general 

account with regard to matters concerning the general account. I certify 

that I have all the necessary authority 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 Director 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 with regard in all matters concerning the 

general account. Such persons shall be bound 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 Representative 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 person 
who 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 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 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 required in the application for an existing account 

under Section 1617(A) of this Rule shall 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 necessary. 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 SO2 emitting unit at a WEB source the owner or operator shall comply 

with the following, as applicable, to monitor and record SO2 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 contained 
in Part 75 with respect to monitoring, recording and reporting SO2 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 unit shall use one of the following 

monitoring methods, as applicable: 

i. A continuous emission monitoring system (CEMS) for SO2 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 SO2 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 source 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 Section, 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 SO2 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 paragraph (b), the Account Representative 

shall submit a notice to request that this paragraph (b) apply to one or 

more SO2 emitting units at a WEB source. The notice shall be submitted 

in accordance with the compliance 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 reducible 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) covered 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 SO2 emitting unit(s). The modified notice shall be 

submitted in accordance with the compliance 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 under 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 paragraphs (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 is 
permanently 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 emissions 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 SO2 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 Representative 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. The 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 system, alternative reference method or 

another alternative for the required monitoring method without having 

obtained prior written approval in accordance with Section I8(e) of this 

Rule (relating to petitions); 
b. Operate an SO2 emitting unit so as to discharge, or allow to be 

discharged, SO2 emissions to the atmosphere without accounting for these 

emissions in accordance with the applicable provisions of this Section; 

c. Disrupt the approved monitoring method or any portion thereof, and 

thereby avoid monitoring and recording SO2 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 provisions 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 method approved under this Section 

for use at the unit that provides data 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 SO2 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 paragraph 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 SO2 emissions are monitored and reported. The plan shall be 

submitted in accordance with the compliance 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 will 
contain the applicable information required 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 monitoring 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 SO2 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 SO2 emitting unit (or group of units sharing a common 

methodology) that, except as otherwise specified in an applicable provision in 

Appendix A, contains the following information: 

a. For all SO2 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 sulfur containing process materials used 

in the SO2 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 SO2 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, substitute data approach for the 

methodology, and general identification of quality assurance procedures. 

If the proposed methodology is a site-specific methodology submitted 

pursuant to Section I1(a)(2)(D) of this Rule, the description under this 

paragraph shall describe fully all aspects of the monitoring equipment, 

installation locations, operating characteristics, certification testing, 

ongoing quality assurance and maintenance procedures, and substitute 

data procedures. 

c. If the WEB source intends to petition for a change to any specific 

monitoring requirement otherwise required 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 specified 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., SO2 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 perform emission calculations or store 

data for quarterly reporting 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 emissions. 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, deleted, 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 (ft2

) at flow monitoring location (for units with 

flow monitors, only). 

e. If using CEMS for SO2 and flow, for each parameter monitored: scale, 

maximum potential concentration (and method of calculation), maximum 

expected concentration (if applicable) (and method of calculation), 

maximum potential flow rate (and method of calculations), span value, 

full-scale range, daily calibration units of measure, span effective 
date/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 SO2 or 

flow component monitors. 

f. If the monitoring system or excepted methodology provides for use of a 

constant, assumed, or default value for a parameter under specific 

circumstances, then include the following 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 longer effective (if applicable); and 

viv. For units using the excepted methodology under section 75.19 of 

40 CFR Part 75, the applicable SO2 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 information; calibration gas levels (percent of 

span) for the calibration error test and linearity check; calculations for 

determining maximum potential concentration, maximum expected 

concentration (if applicable), maximum potential flow rate, and span; 

j. If applicable, apportionment strategies 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 documentation 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 used to describe groups of units 

using a common stack. 

ii. Stack and duct engineering diagrams 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 information in paragraphs (c) and (d) above, the 

owner or operator of an SO2 emitting unit using either of the methodologies in 

paragraph I.1(a)(2)(B) of this Section shall include the following information in 

its monitoring plan for the specific situations described: 

a. For each gas-fired or oil-fired SO2 emitting unit for which the owner or 

operator uses the optional protocol in appendix D to 40 CFR Part 75 for 

SO2 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 fuel 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 SO2 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 appendix 
D 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 SO2 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 include 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 SO2 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 SO2

emissions; and 

vi. Any unit historical actual, estimated and projected SO2 emissions 

data and calculated SO2 emissions data demonstrating that the 
unit 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 Account Representative shall include the 

following in the monitoring plan: current 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 issued 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 shall constitute certification under the WEB 

Trading Program. 

2. The owner or operator of an SO2 emitting unit not otherwise subject to 40 CFR 

Part 75 that monitors SO2 mass emissions in accordance with 40 CFR Part 75 to 

satisfy the requirements of this Section shall 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 application within 45 days after testing is 

complete. A monitoring system will be considered provisionally certified 

while the application is pending, and the 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 applicable quality assurance and quality control 

requirements of Part 75 or, if the WEB source is subject to a WEB protocol in 

Appendix A, the applicable quality assurance 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 specified in this Rule, missing or invalid 

data shall be replaced with substitute data 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 SO2 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 SO2 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 potential 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 SO2 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 shall 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 becomes a WEB source after the Program 
Trigger Date, the monitoring plan shall 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 installed, 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 becomes 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 submissions 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 Certificates 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 SO2, 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 records specified in 40 CFR Part 75 for any 

SO2 emitting unit that uses a Part 75 monitoring method to meet the requirements 

of this Section. 

H. Reporting. 

1. Quarterly Reports. For each SO2 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 in 
a 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, that the Director may require that a copy 

of that report (or a separate statement of quarterly and cumulative annual SO2

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 SO2 emissions for all SO2 emitting units at the 

source. The annual report shall contain four 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 accordance with Section I1(b) of this Rule; 

the number of tons, if any, of SO2 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 SO2 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. Any 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 SO2 emitting unit(s); 

b. A detailed explanation of why the proposed alternative is being suggested 

in lieu of the requirement; 

c. A description and diagram of any equipment and procedures used in the 

proposed alternative, if applicable; 

d. A demonstration that the proposed alternative is consistent with the 
purposes of the requirement for which the alternative is proposed and is 

consistent with the purposes of this Rule 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 Representative 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 Representative’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 purpose 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 Representative’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 deducted 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 control period have been triggered, then the use 

 of allowances that were allocated for any 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 deadline 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 were 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 required 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 Section 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 SO2 emissions for the control period from the 

WEB source, as determined under the monitoring 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 SO2 emissions exceeded the 
 milestone. 

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 SO2 

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 the 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 allowance transfer deadline for the current 

control period.

3. Compliance with allowance limitations shall be determined by comparing the 

following two numbers: 

a. The monitored SO2 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 Section 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 compliance account from another compliance 

account or general account. The allowances held by the Director for compliance at 
a 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 report 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 report according to subpart 3 of this 

 section. 

3. In the Compliance Certification report, the Account Representative shall certify, 

based on reasonable inquiry of those persons 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 SO2 allowance 

limitation; 

b. Whether SO2 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 SO2 Allowance Tracking System for recording; 

c. Whether the monitoring plan that governs the WEB source has been 

maintained to reflect the actual operation and monitoring of the source, 

and contains all information necessary to attribute SO2 emissions to the 

source, in accordance with Section 1618(A) of this Rule; 

d. Whether all the SO2 emissions from the WEB source if applicable, were 

monitored or accounted for either through the applicable monitoring or 

through application of the appropriate missing data procedures; 

e. If applicable, whether any SO2 emitting unit for which the WEB source is 

not required to monitor in accordance with Section 1618(A)(1)(c) of this 
rule 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 compliance status subsequent to the 

change, and specifically, the method to determine SO2 emissions. 

C. Penalties for any WEB source exceeding 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 accordance 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 required number of allowances will be 

deducted from the WEB source’s compliance account regardless of the 

control period for which they were 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 obligation 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 SO2 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 automatic penalties assessed for allowance 

deduction penalty and financial 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 SO2 emissions in excess of a source’s 

allowance limitation is a separate violation. 

R18-2-1622. Special Penalty Provisions for the 2018 Milestone 
A. 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, and 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 Administrator 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 allowances as provided in Section 1619(A) of 

 this Rule until the allowance transfer deadline. 

 4. A WEB source must hold allowances allocated for 2018 including those 

 transferred into the compliance account by an allowance transfer correctly 

 submitted by the allowance transfer deadline, in an amount not less than the WEB 

 source’s total SO2 emissions for 2018. Emissions are determined using the pre 

 trigger monitoring provisions in Section 1611 of this rule. 

 5. An allowance deduction penalty 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 SO2 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 implemented, 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 an 
allowance transfer correctly submitted by the allowance transfer deadline, in an 

amount not less than the WEB source’s total SO2 emissions for the specific 

emissions year. Emissions are determined using the pre-trigger monitoring 

provisions in Section 1611 of this rule. 

 4. An allowance deduction penalty 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 SO2 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: SO2 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 H2S) 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 

H2S. 

(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 the 
relative 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 SO2 emissions rate for all the fuel 

gas combustion devices monitored by this approach 

shall be calculated using the following equation: 

Et = (CS)(Qt)(K) 

where: Et = Total SO2 emissions in lb/hr 

from applicable fuel gas combustion 

devices 

CS = Sulfur content of the fuel gas as H2S(ppmv) 

Qt = 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 SO2 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 SO2 emission rate (lb SO2/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 SO2, 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 SO2 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: 

Et = (Em)(Qt)/(Qm) 

where: Et = Total SO2 emissions in lb/hr from 

applicable fuel gas combustion devices 

Em = SO2 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 Qt = Fuel 

gas flow rate (scf/hr) to the applicable fuel 

gas combustion devices 

Qm = 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 SO2 - diluent CEMS at only one location, if the 

CEMS monitoring at that location is representative of the SO2

emission rate (lb SO2/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 SO2-diluent CEMS shall comply with the applicable 

provisions for SO2 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 SO2 emission 

rate (lb/mmBtu) by substituting the term SO2 for NOx in 

that section, and using a K factor of 

1.660 x 10-7 (lb/scf)/ppmv instead of the NOx 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 SO2 hourly mass emissions rate for all the fuel 

gas combustion devices monitored by this approach 

shall be calculated by using the following equation: 

Et = (Em) (Qt)(GCV)/106

where: 

Et = Total hourly SO2 mass emissions in lb/hr

from the applicable fuel gas combustion devices 

Em = SO2 emission rate in lb/mmBtu from the 

CEMS - monitored fuel gas combustion device 

 Qt = Fuel gas flow rate (scf/hr) to 

the applicable fuel gas combustion devices 

GCV = Fuel Gross Calorific Value (Btu/scf) 

 106

 = 

Conversion from Btu to million Btu 

(d) Calculate total SO2 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 SO2 and flow or each SO2-diluent CEMS shall 

comply with the testing and calibration requirements 

specified in 40 CFR Part 75, section 75.20 and Appendices A 
and B, except that each SO2-diluent CEMS shall meet the 

relative accuracy requirements for a NOx-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 SO2 and flow or the SO2-

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 SO2 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 SO2-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 SO2 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 SO2 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 SO2

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 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. 

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 47
Appendix 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 those states may opt to develop regional 

haze SIPs following the recommendations of the Grand Canyon Visibility 

Transport Commission (GCVTC). If implemented, the GCTVC recommendations 

satisfy the requisite showing of “Reasonable Progress” toward meeting the 

national visibility goal. Transport 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 analyses 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 relationships already established under the WRAP. 

Likewise, tribes that choose 309 would also benefit greatly from this ongoing 

collaboration. This would better enable each participant to take advantage of the 

work done by the other participants on their initial submittals, with higher 

assurance that the SIPs and TIPs would meet all requirements of the Regional 

Haze Rule and the Annex. Over the longer term, a coordinated approach 

provides a forum to facilitate ongoing communications among the participants, 

and a mechanism to meet particular implementation requirements, such as 

milestone tracking, monitoring information and data exchange. 

Proposal:

The 309 states propose that the WRAP board create a standing committee, 

called the “309 Coordinating Committee.” This committee would be formed 

according to the WRAP Bylaws, II. E., which allows the formation of additional 

standing committees (see attachment). The committee would be organized as 

follows: 
 Membership – 

One designated representative from each state and tribe that submits a plan 

under §309 (in the case of tribes, a declaration of intent to move ahead with 

submission of a plan would warrant membership). Additional state and tribal staff 

may participate in meetings of the committee, 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 extend membership to such federal 

representatives and stakeholders as appropriate. The WRAP will make these 

appointments for limited duration as long as the issue requiring federal or 

stakeholder membership is active. 

Charge of the Committee – 

To provide an ongoing forum for 309 states and tribes to facilitate 

communications and information exchange. 

To provide a mechanism to achieve consistency in implementing requirements of 

§309 of the regional haze rule, including but not limited to implementation of: the 

emissions tracking system to evaluate stationary source compliance with the SO2

milestones; the backstop market-trading program for stationary sources, if 

required; and emission tracking in clean air corridors, for fire and enhanced 

smoke management programs, and for mobile and area sources. 

The committee will also make recommendations to the WRAP Board, as needed, 

toward improving implementation of programs contained in SIPs and TIPs 

adopted under §309, and evaluate the value and appropriateness of WRAP 

involvement in resolving disagreements between states or between 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 vehicle 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. It 
is 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 delegation1 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 (SO2)

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 sources1

 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 SO2 have not yet been identified2

 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 nitrates3

 that

probably cause about 2 to 5 percent of the impairment on the Colorado Plateau4

 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 PM10 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 (NO2). This may be important in urban hazes and in some

coherent plumes, but is typically negligible for regional haze.7

 For this reason, NO2 is not

included in the light extinction budget in the EPA’s guidance for tracking reasonable progress.

Stationary source PM10 emissions8

 are currently 6 percent of the WRAP PM10 inventory and may

grow 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 PM10 emissions. PM10 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 PM10 emissions.
I-6

primary PM10 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 PM10 is roughly equal to their proportion

of the PM10 emission inventory, then stationary source PM10 emissions might be expected to

contribute to less than 2 percent of the region’s light extinction. Coupled with the fact that

stationary source PM10 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.

PM10 emissions, however, appear to have a greater visibility impact per ton than NOx emissions,

as shown in Section V. Also, some PM10 emission co-benefits may result from multi-pollutant

technologies described in Section VI, so reductions in stationary source PM10 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 PM10 (98,000 tpy).

Current modeling results indicate that the stationary source NOx and PM10 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 PM10 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/m3

. 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/m3), 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 SO2 backstop

emissions trading program, or Annex. In the case of the Annex, an SO2 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 produced

a 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

SO2 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 SO2 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 PM10 emission reductions had a maximum impact of about 0.1 to 0.5 ug/m3, or about 4 to

8 percent. Compared to the NOx reduction scenario, reductions in ambient PM10 are more

dispersed, with a greater number of local maximums. This may reflect the fact that there are a

fewer number of large PM10 sources than large NOx sources and that much of the PM10

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 PM10 emissions. The increase in nitrate formation was

approximately half the magnitude of the decrease resulting from the NOx reduction scenario.

However, the increase in PM10 (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

SO2 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 PM10 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). PM10 was chosen over PM2.5 because PM10 includes PM2.5 and because all

particles less than 10 microns have visibility impairing attributes. Moreover, many of the PM2.5

emission estimates are derived from PM10 emission factors as opposed to direct PM2.5

measurements – i.e., a certain fraction of the PM10 is assumed to be PM2.5.

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 PM10 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 PM10, 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 PM10 emissions in the

WRAP region with emissions of PM10 greater than 100 tpy on a plant-wide basis. The WRAP

1996 inventory contains over 6,500 point sources of PM10. Approximately 5 percent of these

(338 plants) emitted 100 tpy or more of PM10 and were responsible for 82 percent of total

stationary source PM10 emissions.

Figures II-3 and II-4 identify and compare emissions from the major stationary source

categories of NOx and PM10, respectively. External combustion boilers (utility and industrial)

are the largest source categories for both NOx and PM10. 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 PM10 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 PM10 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

Utility Boilers

Utility ICEs

Industrial ICEs

Industrial Processes

Industrial Boilers These sources

comprise 91% of the

emissions > 100 tpy
II-6

Figure II-4. Categorization of Stationary Source PM10 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

Utility 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/m3

, with some areas in southern CA

and the Columbia River Gorge exceeding 1.5 ug/m3.

Figures III-3 and III-4 show the percent of aerosol-caused10 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 Extinctiona

(Mm-1)

NH4NO3

Contribution

2001 Average

Light Extinctiona

(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 PM10 concentrations in 1996 and 2001,

respectively. Specifically, the values are reconstructed total mass – that is, speciated fine mass

plus gravimetrically-determined coarse mass (PM10 - PM2.5). (Gravimetric PM10 was not

available from the VIEWS website.) PM10 concentrations are typically below 8 ug/m3

, with

some areas in the Columbia River Gorge, Northern Plains, and southern CA exceeding 10 ug/m3

.

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 PM10 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) PM10 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 for

1993 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 PM10 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. Annual Average NH4NO3 Concentrations at IMPROVE Sites (1996).

Figure III-2. Annual Average NH4NO3 Concentrations at IMPROVE Sites (2001).
III-5

Figure III-3. Percent of Annual Average Aerosol Light Extinction Due to NH4NO3 at

IMPROVE Sites (1996).

Figure III-4. Percent of Annual 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. Annual Average PM10 Concentrations at IMPROVE Sites (1996).

Figure III-7. Annual Average PM10 Concentrations at IMPROVE Sites (2001).
III-8

Figure III-8. Percent of Annual Average Light Extinction Due to Coarse Particulate

Matter at IMPROVE Sites (1996).

Figure III-9. Percent of Annual 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 PM10 Concentrations at Western IMPROVE Sites on Days with

Average Visibility.

0

2

4

6

8

10

12

14

1993 1994 1995 1996 1997 1998 1999

PM10 on 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 1999

PM10 on 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 1999

PM10 on 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 1999

PM10 on Days with Poor Visibility (ug/m3

)

BADL

BAND

BRCA

BRID

CANY

0

5

10

15

20

25

1993 1994 1995 1996 1997 1998 1999

PM10 on Days with Average Visibility (ug/m3

)

MEVE

MORA

PEFO

PINN

PORE
III-12

Figure III-11. Trends in PM10 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 1999

PM10 on 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/m3

 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/m3

. In the Los Angeles basin, nitrate

levels can exceed 25 ug/m3

, 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/m3

 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/m3

. Elemental carbon levels are low, typically below 0.5 ug/m3 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 (~1015 m3

), and

multiply (~1 hr) by the lifetime. This leads to an average contribution of large point sources to

PM of 0.005 ug/m3

, 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/m3

. 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/m3

. 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. SO2(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 NOx

which was emitted from a combustion process. NOx, 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,

NO2 is oxidized by the hydroxyl radical:

NO2 + OH →HNO3

This reaction is responsible for most of the nitric acid formation. A second route takes place

mostly at night. First, NO2 is oxidized by ozone to the nitrate radical, NO3:

NO2 + O3 →NO3 + O2

(The nitrate radical should not be confused with the nitrate ion, NO3

-

). Next, the nitrate radical

reacts with NO2 to form dinitrogen pentoxide, N2O5:

NO2 + NO3 →N2O5

N2O5 then reacts with water to form two nitric acid molecules:

2 5 2 3 N O + H O →2HNO

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. NO3 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 (NH3):

HNO (g) NH (g) NH NO (aerosol) 3 + 3 → 4 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:

NH NO (aerosol) K HNO (g) NH (g) 3 + 3 ←→ 4 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, NOx

reductions will reduce ozone because NO2 is needed to form ozone. However, locally, reducing

NOx can lead to local increases in ozone for two reasons. The most easily understood is that

NOx is primarily emitted as NO, which titrates ozone. This is important at night. During the

day, NO2 reacts with the hydroxyl radical, significantly lowering OH levels. This decreases the

rate of VOC oxidation, which reduces the rate of NO oxidation to NO2, 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. NOx emissions increases decrease

ozone, decrease OH, and decrease the rate at which NO2 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. SO2 oxidation, which is faster in the summer when hydroxyl levels are

highest, leads to the formation of sulfuric acid, H2SO4. Sulfuric acid reacts with ammonia to

form ammonium bisulfate [(NH4)HSO4], and if enough ammonia is present, ammonium sulfate
IV-11

[(NH4)2SO4]. 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, xv, is often calculated using the Koschmeider formula:

ext

v b

x

3.912 =

where bext 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:

b 3 f (RH)([Sulfate] [Nitrate]) 4 f (RH )[Organic] [Soil] 0.6[CPM ] 10[LAC] ext = T + + org + + +
IV-14

where fT(RH) is a function to account for sulfate and nitrate absorbing water (forg(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%, fT(RH) is greater than one,

going up to above 5. However, forg(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/m3

 average over the

year (Malm et al., 2003). Average levels of nitrate and primary FPM are very low: 0.2-0.8

ug/m3

, 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/m3

 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/m3

, 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 NO2. 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, NOx

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/m3

, 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 will 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/m3

, 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 NH3 emissions are being changed to find areas that are most

sensitive to NH3 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, NOx, NH3, 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 NOx

and SO2 emissions are decreased, but NH3 emissions increase. The interest would be to assess if

there is the possibility of increased nitrate formation due to the higher NH3 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 NOx 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 NOx and NH3

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 NOx 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-25

ammonium 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 NOx 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, NOx 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, NO2 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

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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 PM10 emissions from plants with PM10 emission > 100 tpy, and

 A 25 percent increase in NOx and PM10 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 GCVTR12. 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 robust

meteorological 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) PM10 emission changes.

On a ton-per-ton basis, reductions in stationary source PM10 emissions appear to yield greater

regional haze benefits than reductions in NOx emissions. For instance, when stationary source

PM10 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 PM10

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 PM10 reduction scenario. This is because stationary sources

comprise 33 percent of the total NOx inventory but only 7 percent of the total PM10 inventory.

So even though much of the NOx is never converted to the particulate phase, the sheer volume of

NOx emission reductions relative to PM10 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 PM10

reduction scenario. The fact that stationary source NOx emissions are not as well controlled as

stationary source PM10 emissions in the West actually lends some relevance to the outcome that

NOx emissions are altered more in the sensitivity analysis than PM10 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 SO2 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 PM10, 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 PM10 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/m3

. 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/m3

), 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 SO2 backstop

emissions trading program, or Annex. In the case of the Annex, an SO2 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 produced

a 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 SO2 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 PM10 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 and

0.5 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 PM10

concentrations from a 50 percent reduction in stationary source PM10 emissions from facilities in

the GCVTR greater than 100 tpy. Maximum reductions in PM10 are about 0.1 to 0.5 ug/m3

, or

about 4 to 8 percent. Compared to the NOx reduction scenario, reductions in ambient PM10 are

more dispersed, with a greater number of local maximums. This may reflect the fact that there

are a fewer number of large PM10 sources than large NOx sources and that much of the PM10

emissions are coarse particles, with shorter transport distances.

Figures V-9 and V-10 show the absolute and percentage change, respectively, in PM10

concentrations from a 25 percent increase in stationary source NOx and PM10 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 PM10 changes (additional

areas) are predicted. The largest PM10 increases are about 0.1 to 0.3 ug/m3

, 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/m3

 (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 (μg/m3) – for purposes of

illustrating spatial patterns, not magnitudes.

Figure V-2. Base Case PM10 Concentrations (μg/m3

) – 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 PM10 Emissions.

Figure V-6. Relative Change in Ammonium Nitrate Concentrations Resulting from

a 25% Increase in Stationary Source NOx and PM10 Emissions.
V-8

Figure V-7. Change in PM10 Concentrations Resulting from

a 50% Reduction in Stationary Source PM10 Emissions > 100 tpy.

Figure V-8. Relative Change in PM10 Concentrations Resulting from

a 50% Reduction in Stationary Source PM10 Emissions > 100 tpy.
V-9

Figure V-9. Change in PM10 Concentrations Resulting from

a 25% Increase in Stationary Source NOx and PM10 Emissions.

Figure V-10. Relative Change in PM10 Concentrations Resulting from

a 25% Increase in Stationary Source NOx and PM10 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 ∆ % ∆ μg/m3 ∆ %

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 ∆ % ∆ μg/m3 ∆ %

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 STATIONARY 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 Engineering 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, 2003 
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TABLE OF CONTENTS 

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

1.1 BACKGROUND ................................................................................................................................................1

1.2 OBJECTIVES....................................................................................................................................................1

1.3 DEFINITIONS AND METHODOLOGY.................................................................................................................2

2 NOX AND PM SOURCES IN THE WESTERN UNITED STATES ..............................................................6

2.1 CHARACTERIZATION OF NOX SOURCES ..........................................................................................................6

2.2 COMPARISON WITH OTHER DATABASES FOR NOX CONTROL TECHNOLOGIES ..............................................13

2.3 TRENDS IN NOX EMISSIONS AND CONTROLS FOR COAL-FIRED UTILITY BOILERS, 1995-2000. ....................16

2.4 CHARACTERIZATION OF SOURCES OF PARTICULATE MATTER (PM).............................................................17

2.4 CHARACTERIZATION OF SOURCES OF PARTICULATE MATTER (PM).............................................................18

2.5 COMPARISON WITH OTHER DATABASES FOR PM CONTROL TECHNOLOGIES ...............................................22

3 NOX CONTROL TECHNOLOGIES...............................................................................................................24

3.1 OVERVIEW....................................................................................................................................................24

3.2 COAL-FIRED BOILERS ..................................................................................................................................39

3.3 RECIPROCATING ENGINES ............................................................................................................................42

3.4 CEMENT KILNS.............................................................................................................................................43

3.5 NATURAL GAS AND OIL FIRED BOILERS ......................................................................................................43

3.6 TURBINES .....................................................................................................................................................44

4 PM CONTROL TECHNOLOGIES ................................................................................................................46

4.1 OVERVIEW....................................................................................................................................................46

4.2 PM CONTROL FOR COAL-FIRED BOILERS AND OTHER COMBUSTION SOURCES ...........................................47

4.3 OTHER DEVELOPMENTS ...............................................................................................................................48

4.4 COSTS...........................................................................................................................................................49

5 MULTI-POLLUTANT CONTROL TECHNOLOGIES ...............................................................................51

5.1 PROPOSED MULTI-POLLUTANT EMISSION REGULATIONS FROM UTILITY BOILERS.......................................51

5.2 MULTI-POLLUTANT CONTROL TECHNOLOGIES.............................................................................................52

6 SUMMARY AND RECOMMENDATIONS...................................................................................................56

6.1 NOX AND PM SOURCES ................................................................................................................................56

6.2 CONTROLS FOR NOX AND PM.......................................................................................................................57

6.3 WHAT’S ON THE HORIZON? WHAT TRENDS WILL INFLUENCE EMISSIONS AND CONTROL TECHNOLOGIES?...58

6.4 RECOMMENDATIONS FOR FUTURE WORK ....................................................................................................59

7 REFERENCES ..................................................................................................................................................60

APPENDIX A: BREAKDOWN OF NOX EMISSIONS BY STATE 

APPENDIX B: BREAKDOWN OF PM EMISSIONS BY STATE 

APPENDIX C: NOX CONTROL TECHNOLOGY SUMMARIES 

APPENDIX D: PM CONTROL TECHNOLOGY SUMMARIES 
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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 NOx 

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-NOx burner 

MBtu Millions of British Thermal Units

MTF Market Trading Forum 

NG Natural Gas 

NOx 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

SO2 Sulfur dioxide 

TPY Tons per year 

WGA Western Governors’ Association 

WRAP Western Regional Air Partnership 
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ACKNOWLEDGEMENTS 

We are grateful to Dr. Praveen Amar for providing help in locating 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. 
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1 INTRODUCTION 

1.1 Background 

The Western Regional Air Partnership (WRAP) has undertaken a program to assess emissions 

control technologies and strategies for large stationary sources of NOx and PM emissions in the 

western states region. The WRAP is a collaborative effort of tribal governments, state 

governments, and various federal agencies to implement the recommendations of the Grand 

Canyon Visibility Transport Commission (GCVTC) and to develop the technical 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 Forum (MTF), in large part, to develop and 

recommend emission control strategies for stationary sources of air pollution. A major focus of 

the MTF has been the establishment of regional emission milestones for sulfur dioxide (SO2) and 

a regional backstop cap-and-trade program for SO2 to be triggered if the milestones are not met 

voluntarily. 

The MTF is also responsible for generating a report required in 40 CFR 51.309(d)(4)(v) of the 

Regional Haze Rule. The report must assess emission control technologies and strategies for 

stationary source NOx and PM emissions and the degree of visibility impairment that would 

result from such strategies. It must also evaluate the need for NOx 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 any necessary long-term strategies and Best 

Available Retrofit Technology (BART) requirements for stationary source NOx and PM. 

This project is essentially a starting point for addressing stationary source NOx 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 sources and existing controls. 

1.2 Objectives 

The main objectives of this project are to identify and briefly describe for large stationary 

sources in the western United States: 

• The universe of modern commercially-available or near-available stationary source 

NOx and PM controls (either technologies or best management practices); 

• Trends in such controls; 

• Their approximate capital and operating costs, 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; 
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• Future opportunities for improvements 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 Stationary Sources in the WRAP Region. This task involved a review of 

the 1996 WRAP stationary source emissions inventory (version 3, in MS Access format), as well 

as other recent and relevant databases to determine 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 sources. Two subsets were created for NOx and PM emissions, 

respectively, based on the following criteria: 

• Sources (defined as emission units, or records, in the database) having annual emissions 

of the pollutant of interest greater than 100 TPY; and 

• Sources located in the thirteen-state region: AZ, CA, CO, ID, MT, ND, NM, NV, OR, 

SD, UT, WA, WY (See Figure 1). 

Table 1 lists the fields extracted from the WRAP database. 

Figure 1. Thirteen-state region considered in the technology assessment. 
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The source classification codes (SCCs) used to categorize sources served as general guidelines 

for choosing the categories in Task 1. The similarities (or differences) in the control 

technologies applicable to specific SCCs were also factors in grouping sources. For example, a 

category called “Coal-fired boilers” was created containing emissions data from utility and 

industrial boilers (of different boiler types) burning coal because the same NOx and PM control 

technologies can be applied to most of these sources. With this in mind, Table 2 gives the 

categories created for characterization of the WRAP emissions and a description of the WRAP 

categories (i.e., SCC codes) used to define the categories in this report. 

For electric utility point sources, additional databases were used to determine boiler capacity 

(MBtu/yr), enhance and update information on control technologies in place, 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 discussed 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 group within general category 

SCC6_DESC Specific industry or emission source 

SCC8_DESC Particular emitting process or fuel type 

NOX_ANN Annual NOx Emissions, tons per year 

PM10_ANN Annual PM Emissions, tons per year 

CO_ANN Annual CO Emissions, tons per year 

SO2_ANN Annual SO2 Emissions, tons per year 

NOX_CPRI Primary Control Equipment Code - NOx

PM_CPRI Primary Control Equipment Code - PM 

CONTROL_DEVICE_DESC Control Device Description (either NOx or PM) 

Note: Codes taken from the 1996 National Emission Trends (NET) PC Inventory File Format 
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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 All reciprocating ICE’s 

 NG Natural gas-fired ICE’s, including 2- and 4-cycle 

 Diesel Diesel-fired ICE’s, including 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 drying, 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 bark 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 (Dakota 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 Production Steel foundries 

Turbines, Steam Geothermal power production 
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Task 2. Survey and Documentation of Emission Control Technologies. In this task, we focused 

on the identification and compilation of control technologies for NOx and PM (main focus) and 

for SO2 and Hg (secondary focus). Sources identified in Task 1 that represented minor 

contributions to the emissions profile of the region, either due to their small number, uniqueness, 

or size, were considered in a more cursory fashion if their control technology options fell outside 

of the range of the more common/available technologies. This effort consisted mainly of 

literature reviews, on-line searches and personal (telephone) contacts and interviews. 

The following information was collected on each technology or process: 

• Type and fundamentals of technology or process; 

• Projected performance; 

• Costs (capital and O&M or cost effectiveness in $/ton of pollutant removed) or cost 

projections; 

• Status of development and opportunities for 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 discussion of the many identified technologies was 

conducted. A summary containing 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 NOx or PM emissions from sources greater than 100 TPY 

o Percentage NOx and PM reduction 

o Cost ($/ton or $/ACFM) 

o Development status 

• Detailed descriptions were prepared for the following: 

o Process description 

o Achievable NOx 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 presented 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. 
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2 NOx AND PM SOURCES IN THE WESTERN UNITED STATES 

2.1 Characterization of NOx Sources 

Table 3 gives the annual NOx 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 NOx emissions in the WRAP database 

for the thirteen-state region. Figure 2 shows the distribution of annual NOx emissions (greater 

than 100 TPY) as a function of state. 

The largest source category by far in the thirteen-state 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 NOx emissions. Therefore, this report 

concentrates on control technologies applicable to these major process categories. 

The states with the largest NOx emissions are AZ, CA, ND, NM, UT, and WY. Since all these 

states except ND are in the GCVTR, it is not surprising 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 TPY. Appendix A contains NOx 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 WY

Annual NOx Emissions, TPY

Figure 2. Annual NOx emissions from sources with emissions greater than 100 TPY for the 

thirteen-state region. 
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Table 3. A comparison of annual emissions of NOx from sources with emissions greater 

than 100 TPY between the thirteen-state region and the GCVTR. 

 13-States GCVTR 

Category # Units 

Total NOx TPY 

(>100 TPY) # Units 

Total NOx TPY 

(>100 TPY) 

% NOx 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% 
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With few exceptions, the distribution of NOx 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 expanded to include additional WRAP states at minimal 

cost. 

The achievable NOx emission rate depends on the fuel type. For coal-fired boilers, lower NOx

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 the thirteen-state region. Figure 3 

shows the distribution of coals burned in utility boilers as a function of boiler type and coal rank. 

Most coal burned in the West is burned close to the mine; this distribution 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 AFBC

NOx, tons per year

 Lignite

 Subituminous

Bituminous

Figure 3. NOx emissions from coal-fired utility boilers as a function of boiler type 

and coal rank for thirteen-state region from WRAP 1996 database. 
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For ICE’s, the application of NOx 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 stationary 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 primarily large sources, the cut-off of 100 TPY will 

include most of the NOx emission sources. The 100-TPY cut-off captures 84% of the NOx

emissions in the WRAP database as a whole. However, certain source categories contain a very 

large number of small sources. For ICE’s (reciprocating engines and turbines) 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 category of stationary source NOx emissions. Thus, NOx control 

programs for sources in this category will require careful consideration of population attributes 

(e.g., controlling a large number 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 Turbines

NOx Emissions, tons per year

 Process Gas

 Diesel

 NG

Figure 4. NOx emissions from Internal Combustion Engines as a function of engine 

type and fuel for thirteen-state region from WRAP 1996 database. 
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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/sources

Cumulative NOx Emissions

Figure 5. Cumulative NOx emissions from ICE’s in the thirteen-state 

region as a function of annual 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 NOx emissions from ICE’s in the thirteen-state 

region as a function of number of sources (in order of decreasing 

annual emission per source.) 
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The 1996 WRAP database contains information on control technologies for the pollutants of 

interest. According to the 1996 data for sources greater than 100 TPY, few sources had NOx

controls, as shown in Table 4. Overall, just above 4% of the NOx 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), followed by petrochemical processes (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 does not seem correct (e.g., 

fabric filter or electrostatic precipitator) for NOx control; this is a limitation of the data available 

and it is outside the scope of this program to determine the accuracy of the data in the WRAP 

database. 
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NOx Control Technology (numb

parentheses)

Ammonia Injection(2), Fluid Bed Dry SAir Firing(3) , Modified Furnace Or BuCatalytic Reduction(1), Process Change

Electrostatic Precipitator – High Effici

Low Excess Air Firing(3), SNCR(1)

Steam Or Water Injection(5)

Fabric Filter - High Temperature, i.e. T

Catalytic Afterburner(1), Catalytic AfteExchanger(1), Catalytic Reduction(1), STray-Type Gas Absorption Column(1) None None Ammonia Injection(1)

None None Process Enclosed(1)

None None None None None None None None None 

Avg NOx 

TPY/Unit 

4,025 

204 

1,052 

294 294 478 286 685 257 204 245 360 204 552 407 289 574 163 320 243 127 165 799 

Total NOx

TPY 

607,748 

86,210 41,009 32,910 25,278 16,250 13,719 10,959 10,010 

9,776 9,311 5,033 3,476 3,309 3,256 2,605 2,297 1,140 

961 730 507 165 

886,660 

 Units 

Controlled 

23 

3 2 4 5 1 6 0 0 1 0 0 1 0 0 0 0 0 0 0 0 0 

46 

# Units 

151 423 

39 

112 

86 34 48 16 39 48 38 14 17 

6 8 9 4 7 3 3 4 1 

1,110 

Category Coal-Fired Boilers Reciprocating Engines 

Cement Kilns Oil/NG Boilers Turbines Mineral Processing

Petrochemical NG Compressor Pulp and Paper Wood Boilers Refinery Process Heaters 

Glass Manufacture Primary Metal Production 

Waste Combustion Refinery

In-process Fuel Use 

Jet Engine Testing

Oil and Gas Production Smelting Operations 

Sugar Beet Processing

Secondary Metal 

Turbines, Steam 

Total 

Table 4. NOx Control Technologies in use in 1996 on Sources Greater than 100 TPY from 1996 WRAP da
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2.2 Comparison with Other Databases for NOx Control Technologies 

The level of control for coal-fired boilers in the WRAP database seemed low, even for 1996. 

Therefore, the 1996 WRAP database was compared with the data available for utility boilers in 

the 1996 CEMS and E-GRID databases. The EIA-767 database was also searched for NOx

control technologies. The E-GRID database should contain the information in the other two 

databases since it contains data from 24 different 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 NOx 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 NOx emissions, accounting for 68% of the emissions from sources greater than 

100 TPY. Second, the effectiveness of NOx control technologies on boilers depends on the type 

of the boiler as well as on the fuel burned. 

For this exercise, the EPA databases (CEMs and E-GRID) were queried to obtain information on 

capacity (MBtu per year) and control technologies. Data from 1996 was used in order to 

compare with the WRAP 1996 database. EPA and WRAP records were matched using ORIS 

Plant ID numbers and plant names. For matching records, control technologies not listed in the 

WRAP database were added, capacity (MBtu) entries were added, and NOx 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 that the combination of the WRAP data and the 

EPA and EIA data suggests that 44% of the utility boilers had NOx control (in 1996), as 

compared to only 12% when considering only the WRAP data by itself. The EPA databases 

probably undergo a more thorough 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. 
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NOx Control Technol

Modified Furnace/Burner Design (13), Low Low Excess Air Firing(1)

None Low Excess Air Firing(3)None None None None 

Average 

Emissions 

(Tons/Source) 

4,945 

14,694 

9,844 

392 296 977 299 

3,694 

NOx 

Emissions 

(TPY) 

489,580 

73,468 

19,688 18,813 

1,779 1,954 

598 

605,881 

Controlled 

Units 

14 

1 0 3 0 1 0 

19 

Number of 

Units 

99 

5 2 

48 

6 2 2 

164 

Dry Bottom Cyclone 

Wet Bottom NG Boiler Stoker Coal-fired AFBC Wood Boiler Oil Boilers Total 

Table 5. NOx Emissions and Control Technologies for Utility Boilers in the Thirteen-State Region from W

Table 6. NOx Emissions and NOx Control Technologies for Utility Boilers in the Thirteen-State Region 

Database Combined with EPA and EIA Databases. 

NOx Control Technol

Modified Furnace/Burner Design(13) , Low 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(None Low Excess Air Firing(1), Misc.(1) None None 

Average 

Emissions 

(Tons/Source) 

5,380 

14,706 

7,803 

424 665 977 319 110 

3,963 

NOx 

Emissions 

(TPY) 

538,003 

73,528 23,409 19,917 

3,987 1,954 

957 110 

661,866 

Controlled 

Units 

45 

1 3 

22 

0 2 0 0 

73 

Number of 

Units 

100 

5 3 

47 

6 2 3 1 

167 

Dry Bottom Cyclone Wet Bottom NG Boiler Stoker Coal-fired AFBC Wood Boiler Oil Boilers Total 
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The achievable NOx emission rate depends on the boiler-fuel combination. The largest general 

class of utility boilers (in terms of number and capacity) is the dry bottom boiler. Dry bottom 

boilers can further be subdivided into wall-fired and tangential. Natural gas boilers emit less 

NOx than coal-fired boilers per unit 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-NOx burners or other combustion modifications. Figure 7 

compares the range of NOx emission rates for all boilers and fuels. 

Application of low-NOx burners and other combustion modifications can reduce NOx emissions 

significantly; this can be seen in the large range of NOx emission that is due, in part, to the use of 

NOx controls on some of the boilers in each subset. Substantial NOx reductions can also be 

achieved on coal-fired boilers just with combustion modifications. 

Since 1996, low-NOx burners have continued to improve; currently there are vendors who will 

guarantee NOx emissions as low as 0.15 lb/MBtu from low-NOx burners or low-NOx firing 

systems. Furthermore, options have been developed for other combustion modifications, and 

SCR has begun to be applied to coal-fired boilers. Thus, the potential for NOx 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/MBtu

fraction of occurrences

Natural Gas

Tangential

Wall-fired

Cyclone

Figure 7. Distribution of NOx emission rates for utility boilers in the thirteen-state 

region, combination of WRAP and EPA/EIA databases for 1996. 
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2.3 Trends in NOx Emissions and Controls for Coal-Fired Utility Boilers, 1995-2000. 

The most recent data available from the EPA databases for electric utility boilers are from 2000. 

In this section, we compare the 1996 data on NOx 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 capacity of electric utility 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 NOx

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 units that were controlled. 

The number of sources increased, particularly the number of natural gas boilers, which increased 

from 47 to 82. The percent of natural gas boilers having NOx controls decreased from 47% to 

30%. During the time from 1996 to 2000, low-NOx burners were added to natural gas units; 

there was also a small increase in SCR and SNCR on these types of boilers. 

NOx control on dry-bottom boilers increased from 47% to 71% from 1996 to 2000, resulting in a 

9% decrease in total NOx emissions from these boilers. The number of units with low-NOx

burners doubled. Overfire air (OFA) installations, though small in number, tripled. There were 

no SCR or SNCR installations on coal-fired boilers in 2000. 

Thus, there was a modest reduction in NOx emissions from electric utility boilers from 1996 to 

2000, accompanied by a substantial increase in generating capacity. NOx control increased, 

particularly on coal-fired boilers. The added NOx control technologies were primarily low-NOx

burners and OFA. 
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NOx Control Technolog

Modified Furnace/Burner Design(13), Low ELow NOx Burner(41), OFA(9), Misc.(4) Low Excess Air Firing(1), OFA(1) Low Excess Air Firing(4), Low NOx Burner(SNCR(4) Low NOx Burner(2) Low Excess Air Firing(1), Misc.(1) None None None 

Average 

Emissions 

(Tons/Source) 

5,101 

13,203 

480 

15,519 

1,059 

299 335 216 

3,207 

NOx 

Emissions 

(TPY) 

489,680 

66,013 39,381 14,159 

2,118 

598 335 216 

612,500 

Controlled 

Units 

68 

2 

25 

2 2 0 0 0 

99 

Number of 

Units 

96 

5 

82 

2 2 2 1 1 

191 

Dry Bottom Cyclone NG Boiler Wet Bottom Coal-fired AFBC Wood Boiler Stoker Oil Boilers Total 

Table 7. NOx Emissions and NOx Control Technologies for Utility Boilers in the Thirteen-State Region co

and EIA Databases for 2000. 
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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 region. With few exceptions, the distribution of 

PM sources is similar in the thirteen-state region as compared to the GCVTR. (Primary metal 

production emissions are mostly outside the GCVTR.) As a result of this similarity, the scope of 

this project was expanded to include additional 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 eight categories account for 92% of the 

PM emissions. Therefore, this report will focus 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 shown 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% 
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    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

Boilers

Average Emission per Source, TPY

1996

 2000

Figure 8. Average Annual NOx Emissions (greater than 100 TPY) from Electricity 

Generating Boilers: Comparison of 1996 and 2000 data from EPA Databases. 
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Table 9 lists the control technologies in use in the 1996 WRAP database 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 emissions 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 WY

Annual PM Emissions, TPY

Figure 9. Annual PM Emissions from Sources with Emissions Greater than 100 

TPY for the Thirteen-State Region. 
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PM Control Techn

Centrifugal Collector (Cyclone)(2), ElectFabric Filter(12), Multiple Cyclone(4), MCyclone/Electrostatic Precipitator(2), MuScrubber(1), Wet Scrubber(8) Centrifugal Collector (Cyclone)(2), Dust Stabilizers or Wetting(5), Dust SuppressiFabric Filter(1), Water Curtain(1), Wet SCentrifugal Collector (Cyclone)(3), SulfuProcess(2), Wet Scrubber(2) Centrifugal Collector (Cyclone)(1), Wet Dust Suppression by Water Sprays(2), FaAlkalized Alumina(2), Dust Suppression Scrubber(3), Misc.(1) Centrifugal Collector (Cyclone)(1), Wet None None Electrostatic Precipitator(4) Centrifugal Collector (Cyclone)(1) None None Electrostatic Precipitator(1) None None None None 

Avg PM 

(TPY/Source) 

523 288 258 238 512 235 298 444 

2,456 

276 230 233 419 160 537 267 175 176 357 

Total PM 

(TPY) 

46,010 24,499 10,836 

5,718 5,631 4,697 4,476 3,555 2,456 1,379 1,150 

932 838 641 537 535 525 176 

114,590 

Controlled 

Units 

64 29 

7 3 3 7 3 0 0 4 1 0 0 1 0 0 0 0 

122 

Number 

of Units 

88 85 42 24 11 20 15 

8 1 5 5 4 2 4 1 2 3 1 

321 

Coal-Fired Boilers Mineral Processing Petrochemical Wood Boilers Refinery Emissions Primary Metal Production Pulp and Paper Smelting Operations Miscellaneous Oil/NG Boilers Sugar Beet Processing Cooling Tower Turbines Cement Kilns Secondary Metal Production Jet Engine Testing Reciprocating Engines Refinery Process Heaters Total 

Table 9. PM control technologies in use on sources greater than 100 TPY from 1996 WRAP database. 
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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 database was also searched for PM control 

technologies. The E-GRID database should contain the information in the other two databases 

since it contains data from 24 different federal data sources, including EIA data and other EPA 

data. 

EPA and WRAP records for 1996 were matched using ORIS Plant ID numbers and plant names. 

For matching records, control technologies not listed in the WRAP database were added, 

capacity (MBtu) entries were added, and PM emissions 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 measurement and/or estimation methods. 

The differences, illustrated by a few sample records 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 that 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 the WRAP data by itself. The EPA databases 

probably undergo a more thorough 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 1,063 245 
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PM Control Technology 

Multiple Cyclone(3), Fabric Filter(8), Wet Scrubber(7), Electrostatic Precipitator(12) Electrostatic Precipitator(4) Electrostatic Precipitator(3) None Multiple Cyclone(1) None 

Average 

Emissions 

(TPY/Source) 

615 309 234 190 381 102 554 

PM 

Emissions 

(TPY) 

36,889 

1,235 

702 571 381 102 

39,880 

Controlled 

Units 

30 

4 3 0 1 0 

38 

Number of 

Units 

60 

4 3 3 1 1 

72 

Dry Bottom NG Boiler Cyclone Stoker Coal-fired AFBC Wet Bottom Total 

PM Control Technology 

Multiple Cyclone(3), Fabric Filter(15), Wet Scrubber(8), Electrostatic Precipitator(44), Multiple Cyclone/Electrostatic Precipitator(3), Multiple Cyclone/Wet Scrubber(2), Electrostatic Precipitator(4), Fabric Filter(1) Electrostatic Precipitator(4) Fabric Filter(2) None Multiple Cyclone/Electrostatic Precipitator(1), Fabric Filter(1) 

Average 

Emissions 

(TPY/Source) 

1,093 

327 309 232 190 137 942 

PM 

Emissions 

(TPY) 

84,140 

1,633 1,235 

697 571 274 

88,549 

Controlled 

Units 

75 

5 4 2 0 2 

88 

Number of 

Units 

77 

5 4 3 3 2 

94 

Dry Bottom Cyclone NG Boiler Wet Bottom Stoker Coal-fired AFBC Total 

Table 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-State Region from WRAP 1996 Database Combined with EPA and EIA Databases. 
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3 NOx CONTROL TECHNOLOGIES 

3.1 Overview 

As discussed in Section 2, the NOx emissions greater than 100 TPY in the thirteen-state region 

come predominantly from coal-fired boilers. We have concentrated on obtaining detailed 

information on NOx control technologies for the top five categories, which account for 90% of 

the emission, although in some cases, where information was readily available, we have 

collected information for other source categories (refinery process heaters, glass melters, and 

wood-fired boilers). Table 13 shows that these source categories together account for 92% of the 

NOx 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, these are commercial technologies, in that vendors 

are offering these technologies. Not all technologies listed in Table 14 have demonstrated longterm operation, however. Table 14 gives the following information about each technology: 

• Name of the technology 

• Source categories to which the technology can be applied 

• Was a summary prepared? (Yes/No). If yes, technology summaries are contained in 

Appendix C. 

Second, Tables 15 through 22 summarize the NOx control options for major source categories for 

ease of comparison. More detailed information, particularly on the range of cost and NOx

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 (NOx removal efficiency) 

• Range of costs ($/ton of NOx removed, levelized annual cost) 

• Commercial status 

Table 13. Annual NOx emissions greater than 100 TPY from major source categories. 

Category # Units 

Total NOx

TPY 

% of NOx

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 1,110 886,660 
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Table 14. NOx 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 Y 
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 Technology Applicability 

Summary in 

Appendix C 

(Y/N) 

17 Kiln dust insufflation Cement kilns 

N 

(see O2-

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 NOx Burners Coal-fired boilers, Oil/NG boilers, Glass Melters, 

Pyrolysis furnaces, Process heaters, Cement kilns Y 

22 Low-NOx 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 

Y 
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 Technology Applicability 

Summary in 

Appendix C 

(Y/N) 

33 SNCR 

Coal-fired boilers, Wood/Biomass boilers Oil/NG 

boilers, Glass Melters, Pyrolysis furnaces, Cement 

kilns, Reciprocating Engines, Gas Turbines 

Y 

34 Tempering (Steam, water or air 

injection) Gas turbines, Process heaters, Pyrolysis furnaces Y 
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Cos100500(Hidepon crebu300800500<10200250

Performance 10 to 30% NOx reduction 

20 to 30% NOx reduction for Fuel-Lean Gas Reburning (no OFA), and 30 to 60% reduction for conventional reburning. 50-70% 50 to 90% NOx reduction, de-pending on how much catalyst is installed. 40 to 60% NOx reduction 0 to 30% NOx reduction. 

30-50% NOx reduction. 

20 to 40% NOx reduction. 

Applicability Most units. Most units. Furnace height (residence time) may restrict some applications Same as individual technologies. Same as individual technologies. Most units. Can use more NH3 with less 

slip. Available for all units Most boilers already have LNB. Most units. Furnace height may restrict some applications 

Description Burner air and/or fuel modifications to improve air/fuel interaction Inject portion of the fuel into the furnace downstream of burner zone. Usually requires OFA to complete combustion Co-inject reburning fuel and SNCR reagent. Overfeed reagent into the furnace, and allow ammonia carryover to further reduce NOx over a catalyst 

downstream. Inject small amount of natural gas to create radicals that enhance SNCR effectiveness at 1700 to 2000 °F. Emerging technology. Sensors and software optimize air-fuel ratio to burners. Burners designed to produce lower NOx emissions – “staged” combustion 

Form of “staged” combustion. Divert portion of the air from the windbox to OFA ports installed above the burners. 

Technology Burner Modifications Fuel Reburn Hybrid Reburn + SNCR Hybrid SNCR + SCR Hydrocarbonenhanced SNCR “Intelligent” Controls Low-NOx burners 

(LNB) Overfire air (OFA) 

Table 15. Coal-Fired Boilers. 
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Cos100800150800

Performance 30-50% beyond OFA 20 to 30% additional NOx

reduction beyond OFA. 70 to 90+% NOx reduction 

25 to 50% NOx reduction, 

depending on the furnace temperature and time for reaction. 

Applicability Best applied with new OFA system designed to achieve stoichiometric airfuel ratio < 0.8. Most units. Modeling required to determine injection locations. Most units. Space availability may constrain some options. High sulfur fuels more challenging Most. Residence time and temperature characteristics are important. 

Description Improve effectiveness of OFA operation by injecting O2 into fuelrich flames. Operate more fuel-rich 

without the problems. Emerging technology. SNCR applied to fuel-rich region of OFA system. Ammonia added upstream of catalytic reactor installed upstream of air preheater (conventional), downstream of a hot ESP (low dust), or downstream of the cold ESP (tail end). Inject ammonia-based reagent into upper furnace (1700-2000 degrees F) to destroy NOx. 

Technology Oxygen-enhanced combustion modification Rich Reagent Injection (RRI) Selective Catalytic Reduction (SCR) Selective Non-catalytic Reduction (SNCR) 

Table 15. Coal-Fired Boilers (Continued). 
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Cost115-Not but lLEC190-depeengin$650BHP<500 ~ 10< 50

Performance 80% NOx reduction. Use 

of plasma ignition is new, so there is limited operating experience. ~80% 80-90% NOx reduction 

40-98% NOx reduction, depending on engine speed. Average of 95% reduction is achievable. 90-95% NOx reduction, 60-80% particulate removal, 50-70% CO removal, 90% hydrocarbon removal. 80-95% NOx reduction. 

Applicability For lean-burn engines (to support ignition under very lean conditions) Same as LEC Not available for all engines, some fuel efficiency decrease. Requires turbo-charging or inter-cooling upgrades. Requires rich-burn engine to produce hydrocarbons used for NOx reduction. 

Applicable to all engines, but exhaust must be heated for most engines. For carbureted, rich-burn engines. 

Description Provide continuous electrical discharge at the spark plug gap for 10 to 90 o of 

crankshaft rotation. This extended energy delivery ensures combustion in the leanest of conditions. Enhance mixing of fuel and air under lean conditions Retrofit kits available to implement lean burn for new engines as well as retrofit. Install oxidation-reduction catalyst that uses hydrocarbons in exhaust to destroy NOx. 

Inject chemical reagent into exhaust at temperatures of 1400 to 1500 °F. Inject air into intake manifold so that the piston initially draws in air, followed by a fuel-rich air-fuel mixture. 

Technology High Energy Ignition High-Pressure Fuel Injection Low-Emission Combustion (LEC) Non-Selective Catalytic Reduction (NSCR) NOxTech Pre-stratified Charge 

Table 16. Reciprocating Engines. 
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CostNot < 10

Performance 95% reduction of NOx, CO, and hydrocarbons. 75-90% NOx reduction 

Applicability Theoretically works for all engines. Catalyst regeneration is difficult. Little operating data available. All engine types (especially diesel), but difficult to control if load range is wide. 

Description Add chemical reactor for NOx

sorption, followed by regeneration. Inject ammonia upstream of a catalyst that operates at 300-900 °F. 

Technology SCONOX SCR 

Table 16. Reciprocating Engines (Continued). 
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Cost1000100-50-100 100-3200-5500-

Performance 0 to 50% NOx reduction, 

depending on existing equipment. 20 to 30% NOx reduction, 

but can reduce kiln capacity due to high moisture content. 20 to 30% NOx reduction, 

depending on cement specifications 0 to 20% NOx reduction in 

conjunction with a 0-5% kiln capacity increase. 0 to 20% NOx reduction, and requires less operator attention. 0 to 20% NOx reduction; production may increase. 

Applicability More easily implemented in tower kilns. Tried in long kilns and preheater/precalciner kilns, but effectiveness is limited by poor combustion and increased hydrocarbon or SO2 emissions. 

Applicable to all kiln types, but may affect cement quality. Applicable to long kilns. Applicable to all kiln types, but risks unacceptable cement quality. Applicable to all kiln types. Can reduce cement quality on some kilns. 

Description Inject portion of the fuel downstream of the main flame to create locally reducing conditions where NOx can be destroyed. 

Sometimes includes installing a “NOx fan” to increase burnout. 

Add sewerage sludge to mid-kiln or tower for combined SNCR and fuel-staging affect. Change cement formulation by adding waste iron to lower clinkering temperature and suppress NOx. 

Re-inject cement kiln dust (CKD) into flame zone to lower peak temperatures and increase clinker production. Add temperature-monitoring device to kiln controls to minimize high-temperature excursions where more NOx is 

emitted. Replace open pipe burner with multi-annular design. Usually accompanied by installation of an indirect coal feed system to reduce coal transport airflow. 

Technology Air or fuel staging Biosolids injection Iron addition (CemStar) Kiln dust insufflation Kiln temperature control Low-NOx Burner 

(LNB) 

Table 17. Cement Kilns. 
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Cost, $/1000-500-1000 200-100200-100

Performance 30-50% NOx. Little 

experience 15 to 30% NOx reduction; 

generate revenues. 0 to 20% NOx reduction 

and potential for additional capacity. 30 to 70% NOx reductions, 

depending on access to temperatures in 1600-1800 °F range. 

Applicability Applicable only to preheater/precalciner kilns. Injected mid-kiln in long kilns, and into lower tower for preheater/precalciner kilns. Cement quality could be more difficult to control. Applicable to preheater/precalciner kilns. 

Description Replace calciner with new lowNOx design. 

Inject whole tires or shredded tires downstream of the flame to reduce NOx formed in the burner. 

O2 lance to decrease fuel 

requirement for clinker formation. Inject ammonia-based reagent into upper furnace (1700-2000oF) 

to destroy NOx. 

Technology Low-NOx calciners 

Mid-kiln or tower tire injection Oxygen enrichment SNCR 

Table 17. Cement Kilns (Continued). 
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Cost, $/T 500-3000 200-1000 1000-200Not avail2000-1001300-300

Performance 40-80% NOx reduction 

30-60% NOx reduction 40-80% NOx reduction 70-99% NOx reduction claimed. 70-90+% NOx reduction 

30-60% NOx reduction 

Applicability Most units, but could affect heat balance. Induced FGR requires pressure part changes. Most boilers. Most units. Furnace height may restrict some applications Steam-hydrogen regeneration gas not practical for some boilers. Limited testing to date. Most units. Space availability may constrain some options. High sulfur fuels more challenging Most. Residence time and temperature characteristics are important. 

Description Recycle 15-25% of the flue gas to the windbox to reduce flame temperature. Can use eductors for induced FGR Burners designed to produce lower NOx emissions – 

“staged” combustion Form of “staged” combustion. Divert portion of the air from the windbox to OFA ports installed above Add chemical reactor for NOx sorption, followed by 

regeneration. Ammonia added upstream of catalytic reactor. Inject ammonia-based reagent into upper furnace (1700-2000oF) to destroy 

NOx. 

Technology Flue Gas Recirculation (FGR) Low-NOx Burners 

Overfire Air (OFA) SCONOX SCR SNCR 

Table 18. Oil/Natural Gas-Fired Boilers. 
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Table 19. Turbines. 

Cost,$/T > 500 1000-2000 > 7000 500-10000+ 2000-7000 

Performance 0.05 lb/MBtu (80% reduction) has been measured. 0.1 lb/MBtu (70% reduction) can be guaranteed on new units. 0.02 lb/MBtu (> 90% reduction) claimed. 90 % reduction down to 0.03 lb/MBtu. 0.15 lb./MBtu (50% reduction) can be achieved. 

Applicability Limited experience. Most turbines. Flame instability a problem for some gas fuels. Reliability of system not yet proven. Applied to most turbines Can be applied to most turbines, but some will experience slight efficiency loss. 

Description Catalytic combustor reduces combustion temperature below thermal NOx limit. 

Low NOx combustor is GT 

“equivalent” of LNB. Add chemical reactor for NOx

sorption, followed by regeneration. Add catalyst section to HRSG to destroy NOx at temperatures 

of 600 to 900 °F. Spray water or steam into combustor to suppress flame temperature. 

Technology Catalytic combustion DLN (fuel-lean combustion) SCONOX SCR Tempering (Water/ Steam Injection) 
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Table 20. Wood or Biomass-Fired Boilers. 

Cost, $/T 300-3000 200-500 200-2000 900-2200 

Performance 40-60% NOx reduction 

0-20 % NOx reduction 

20-60% NOx reduction 

40-80 % NOx reduction 

reported 

Applicability Stoker, water tube Watertube boilers Stoker, watertube Stoker, FBC, watertube 

Description Inject portion of the fuel into the furnace downstream of burner zone. Usually requires OFA to complete combustion Sensors and software optimize air-fuel ratio to burners. Form of “staged” combustion. Divert portion of the air from the windbox to OFA ports installed above the burners. Inject ammonia-based reagent into upper furnace (1700-2000o

F) to destroy NOx. 

Technology Fuel Reburn "Intelligent" Controls Overfire air (OFA) Selective NonCatalytic Reduction (SNCR) 
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Table 21. Process Heaters. 

Cost, $/Ton Gas: 1,720-2,480 Oil: 2,390-2,910 Gas: 1,210-1,820 Oil: 1,200-2,340 Gas: 810-1,280 Oil: 400-1,440 Gas: 5,130-10,600 Oil: 3,710-6,490 Gas: 1,470-2,640 Oil: 1,230-2,350 

Performance 50-60% 30-50% Ultra-LNB: 50-80% 75-90% 50-70% 

Applicability Oil/gas fired, MD only Oil/gas fired Oil/gas fired Oil/gas fired 

Description Staged firing with flue gas mixed with precombustion air Staged firing; Combines staged firing with induced flue gas recirculation Ammonia added upstream of catalytic reactor. Inject ammonia-based reagent into upper furnace (1700-2000o F) 

to destroy NOx. 

Technology LNB + FGR Low-NOx Burners, 

Ultra Low-NOx Burners 

SCR SNCR 
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Table 22. Glass Melting Furnaces. 

Cost, $/Ton 890-1,040 2,600-9,900 790-1,680 moderate 2,150-4,400 

Performance 5-25% 10-30% 40% 50-65% 80-85% 

Applicability Any glass melting furnace w/ >50% cullet in batch Oil/gas fired furnaces 

Description Residual heat of waste gas used to preheat batch materials/cullet (recycled glass) Burners designed to produce lower NOx emissions – “staged” 

b ti

Inject portion of the fuel into the furnace downstream of burner zone. Oxygen used instead of air; requires different furnace design 

Technology Batch/Cullet Preheating Electric Boost Low-NOx Burners 

Natural Gas Reburn Oxy-Fuel Firing 
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The formation of NOx is a byproduct of the combustion of fossil fuels. Nitrogen contained in 

fuels such as coal and oil, as well as the harmless nitrogen in the air, will react with oxygen 

during combustion to form nitrogen oxides (NOx). The degree to which this formation evolves is 

dependent on many factors, including both the combustion process itself and the properties of the 

particular fuel being burned. This explains why similar boilers firing different fuels or similar 

fuels burned in different boilers will yield different NOx emissions. 

As a result of these complex interactions in the formation of NOx, an equally large number of 

approaches to minimize or reduce its emissions into the atmosphere have been and continue to be 

developed. A relatively simple way of understanding the many technologies available for NOx

emission control is to divide them into two major categories: (1) those that minimize the 

formation of NOx during the combustion process (e.g., smaller quantities of NOx are formed); 

and (2) those that reduce NOx after the combustion process. It is common to refer to the first 

approach as “combustion modifications” whereas technologies in the second category are termed 

"post-combustion controls." 

Within each of these categories, several technologies and variations of the same technology 

exist. Finally, combinations of some of these technologies are not only possible but often 

desirable as they may produce more effective NOx 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 technologies such as low-NOx burners (LNB), 

Overfire air (OFA), or Reburn. All combustion modification approaches face a common 

challenge: that of striking a balance between NOx reduction and fuel efficiency. 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 reutilization (e.g., cement and concrete production). 

Combustion Optimization

Combustion optimization efforts can lead to reductions in NOx emissions of 5%-15% or even 

higher in cases where a unit may be poorly "tuned." 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 drastic 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 approaches to minimizing the formation of NOx during 

combustion. Simply, this is accomplished by controlling the quantities and the way in which 
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fuel and air are introduced and mixed in the boiler (usually referred to as "fuel or air staging"). 

These technologies are the most prevalent in the power industry at present. For example, plants 

that have had to comply with Phase I of Title IV of the CAAA of 1990 have largely used these 

technologies for compliance. (Phase II of the Title IV has required the use of post-combustion 

technologies to meet more stringent requirements for both Group 1 and Group 2 boilers.) 

Competing manufacturers have proprietary designs, geared towards application in different 

boiler types, as well as reflecting their own design philosophies. LNB’s and OFA, which can be 

used separately or as a system, are capable of NOx 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. NOx emission rates on the order of 0.15 lb/MBtu can be achieved with 

low NOx 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 reflecting easier "plug-in" application, whereas the 

higher costs are typically associated with more difficult and involved retrofits (e.g., where new 

controls or other systems may be replaced 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 other plant outage requirements, 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" NOx through chemically 

reducing conditions shortly after it is formed rather than minimizing its formation as discussed 

previously. From a practical standpoint, this is accomplished by introducing the reburn fuel 

(theoretically any fossil fuel can be used, but natural gas is the most common) into the boiler 

above the main burner region. Subsequently, this "fuel-rich" environment reacts with and 

"destroys" the NOx formed in the main burners. This technology has been implemented in the 

U.S. and overseas, and while not as common as LNB/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 criteria such as boiler size, availability of natural gas, type 

and quality of the main fuel are all important in determining the suitability of a unit for this 

technology. One important feature of reburn is its compatibility with cyclone boilers, for which 

the previously mentioned technologies 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 and quantity, initial NOx level, boiler design, etc. Reburn can be thought of as a 

"dial-in" NOx technology in that NOx reductions are a function of the amount of reburn fuel. 

This feature may provide strategic value in compliance scenarios. 
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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 from $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 (pulverization and atomization, respectively) represent the dominating 

O&M costs. Countering these costs, particularly in the gas reburn case, are SO2, particulates, 

and CO2 co-benefits proportional to the fraction of gas used. 

Project retrofit schedules for this 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) developed for specific applications where NOx

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 less than $10/kW, making it a potentially effective 

option in specific applications. 

SCR and SNCR

Readily available post-combustion NOx controls are limited to 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 NOx produced in the boiler 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 operates at lower temperatures (about 600oF) and 

hence needs a catalyst to produce the desired reaction between ammonia and NOx. 

While this difference between the two technologies may seem minor, it results in significant 

difference in performance and costs. This is because 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 designed to be), while in the SCR case, a dedicated 

reactor and the reaction-promoting catalyst ensure a highly controlled, 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 more reagent is needed to accomplish a given 

reduction in NOx); and finally, has limited NOx reduction capability (typically 30%-40%, with 

some cases achieving reductions in the 50% range). SCR, on the other hand, has higher capital 

costs but offers lower operating costs and the opportunity for very high NOx 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 primarily 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 reagent utilization) as well as the initial NOx level and the desired 

percent reduction. Two additional parameters important in the overall 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. 
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Combined Approaches

In theory, most of these technologies can be used together. However, NOx 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 (SNCR) and capital costs (SCR – smaller 

reactor/catalyst) due to lower NOx 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 NOx 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 available for ICE’s, having a wide range of complexity, cost and 

performance. 

Some in-cylinder methods offer low to moderate NOx 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 are widely available, and NOx 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 retrofitted with Low-Emission Combustion (LEC) technology 

can potentially achieve significant NOx 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 technology is estimated to provide annual NOx 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 engines (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 for post-combustion control of diesel and leanburn spark-ignition engines. Experience in the U.S. with SCR on these engines is growing, 

especially for diesel engines. SCR has been applied 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 NOx 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 seasonal reductions at a cost of under $1,000/ton for 

engines operating at high capacity factors (typically, 65% or greater). 

Recent developments from the application of urea-SCR on mobile sources (diesel trucks) offer 

the possibility of reducing the size and capital cost of SCR systems for stationary ICE’s. This 
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new technology, developed from efforts to apply SCR to mobile diesel engines, appears to make 

it possible to achieve much more cost-effective NOx reduction on stationary ICE’s that operate 

for only a few hundreds of hours a year. NOx 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 with capacity factor greater than 45%.

3.4 Cement Kilns 

As with other combustion systems, modifying the combustion process is one strategy for 

reducing NOx 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 combustion zone increases the efficiency of the 

cement-making process and can result in reduced NOx emissions. Combustion modifications 

include staged combustion of air or fuel. Specifically designed low-NOx burners are sometimes 

used. Even without low-NOx burners, staging can be achieved by adding some of the fuel midkiln, as in mid-kiln injection of tires. Mid-kiln injection of fuel (most often tires) was in practice 

in twenty kilns in the U.S. in 2000. 

Iron addition (CemStar process) has 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 NOx). 

Post-combustion (post-kiln) NOx 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/precalciner 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 NOx control options for gas and oil-fired boilers 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 and hence, is not mentioned there. 

While the control technologies are common to the coal-fired options, application issues require 

different considerations and analyses. Examples range from differences in the inherent NOx

formation amongst the fuels (thermal NOx vs. “fuel”-NOx), which dictate that combustion-based 

technologies are designed accordingly for each fuel, to the fact that gas produces no PM or 

SO2/SO3 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), deployment of these technologies tends to be less 

constraining than for coal. 
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3.6 Turbines 

There have been some important developments in gas turbine NOx control technology, but wellestablished technologies continue to play an important role in reduction of NOx. Dry Low NOx

(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 NOx from gas turbines. 

Many turbine manufacturers can convert or replace conventional combustors on existing turbines 

with DLN combustors. DLN combustion retrofits have been made possible by recent 

developments in gas turbine combustor technology. DLN technology offers the potential for 

substantial reduction of NOx 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, NOx emissions of 25 ppm can be guaranteed for new 

turbines and emissions below 42 ppm can be guaranteed for retrofitted turbines. For large 

turbines (75 MW and higher in size), controlled NOx emission levels of as low as 9 ppm have 

been guaranteed, even for retrofits. 

DLN capital costs vary with the size of the turbine and the specifics of the particular turbine 

being retrofitted. The baseline NOx level significantly affects the estimate of cost per ton of NOx

reduced. Using expected baseline NOx 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 conventional combustion control is 

estimated to provide NOx reductions under $2,000/ton for annual 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/ton for nearly all conditions. 

Water injection and steam injection are two well-established technologies that can offer 

controlled NOx emission levels below 42 ppm in many cases. Because water or steam injection 

technologies frequently have lower capital cost than DLN but higher variable costs, these 

technologies can be more attractive for peaking 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 NOx 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 benefit from low-temperature SCR. 

The cost of NOx reduction with SCR varies considerably according to application, turbine size, 

and the type of SCR technology that is appropriate for the application. As in the case of the 

DLN cost estimates, expected baseline NOx 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 capacity factors was estimated to cost about 
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$440/ton for annual controls and $870/ton for seasonal controls, for turbines equipped with 

conventional combustion technology (baseline NOx emissions of 154 ppm). For turbines with 

lower baseline NOx emissions (such as those equipped with DLN combustors having baseline 

NOx emissions of 15 ppm), the cost per ton of additional NOx removed was estimated to be 

greater, ranging from about $3,700/ton (annual control, high capacity factor) to over $13,000/ton 

(seasonal controls, low capacity factor). 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 NOx emissions of 142 ppm). Seasonal controls for smaller turbines 

are estimated at over $15,000/ton of NOx removed at a low capacity factor (45%) with baseline 

NOx 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 equipped with conventional 

combustion technology (baseline NOx 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 NOx emissions (such as those equipped with 

DLN combustors) showed a higher cost per ton of NOx reduction. The estimated cost of NOx

reduction for a 75 MW turbine with baseline NOx emissions of 15 ppm ranges from $5,170/ton 

(annual controls, high capacity factor of 85%) to as high as $20,000/ton (seasonal controls, low 

capacity factor of 45%). On smaller 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 NOx emissions of 142 ppm). Cost is estimated to range from $6,750/ton 

(annual controls, high capacity factor of 85%) to about $27,000/ton (seasonal controls, low 

capacity factor of 45%) with baseline NOx emissions of 42 ppm. 

Emerging combustion technologies (such as catalytic combustion) and post-combustion 

technologies (such as SCONOx) offer the potential for very low NOx emission levels. Because 

there is much less experience with these technologies, available cost information is limited. 
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4 PM CONTROL TECHNOLOGIES 

4.1 Overview 

As discussed in Section 2, 8 source categories make 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 technologies with demonstrated operating experience in a wide range 

of applications. Table 24 gives the following information about each technology: 

• Name 

• Source categories to which the technology can be applied 

• Summary prepared? (Y/N) 

Technology summaries are contained 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) 321 114,589 
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Table 24. PM Control Technologies 

4.2 PM Control for Coal-Fired Boilers 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 (inorganic 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", "PM2.5" (particulate matter (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 pulverized 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 grate-fired boilers are used to burn 

coal, wood and waste. The majority of the ash falls through the grate and is discharged as 

bottom ash. Mineral composition of the coal and the amount of carbon in the fly ash determine 

the quantity, resistivity and cohesivity of the fly ash. 

PM emissions from other point source processes involve similar phenomena where particulate 

matter is carried with the flue gas, in suspension to the stack. Hence, the general technologies 

applicable to one source are typically suitable for 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 N 
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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 principle of rapid mixing and impingement of 

the particulate with the liquid droplets and subsequent removal with the liquid waste. 

For particulate controls the “venturi scrubber” is an effective technology whose 

performance is directly related to the pressure loss across the venturi section of the 

scrubber. Venturi scrubbers are effective devices for particulate control. However, for 

higher collecting efficiencies and a wider range of particulate 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 operate on the principle of electrophoresis, by 

imparting a charge to the particulates and collecting them on opposed charged 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. In gases with high moisture content, 

dry ESP’s are not suitable because the wet gas 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 essentially “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 including 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 (greater 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 application 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 electrostatically- enhanced fabric filtration 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 Collector 
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(AHPC) are examples of hybrid particulate collectors. In COHPAC, an ESP is followed by a 

pulse-jet Fabric Filter either immediately 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 with 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 resulting 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. NOx and SO2) 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 ranges become useless. An attempt 

to summarize costs in terms of capital and 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 hence, the costs of a PM control device, is the 

quantity of flue gas it must handle. As a result, it is more appropriate 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-size 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 generalize for such a variety of technologies and applications, as they 

are affected by many parameters that 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 apply 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 Filter - $0.35 - $0.75/yr-ACFM 
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• Pulse Jet Fabric Filter - $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 Filter - $0.70 - $0.80/yr-ACFM 

• Pulse Jet Fabric Filter - $.90 - $1.1/yr-ACFM 

• Venturi Scrubber - $1.2 - $1.8/yr-ACFM 

• Cyclone – Not applicable 

 
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5 MULTI-POLLUTANT CONTROL TECHNOLOGIES 

Emerging environmental issues and proposed federal legislation (President’s Clear Skies 

Initiative, Carper Bill, Jeffords’ Bill) as well as state legislation (examples include MA, NY, NC, 

NH, CT) have driven interest in multi-pollutant (as opposed to single pollutant) control 

technologies capable of addressing air pollutant emissions more comprehensively with greater 

flexibility and ultimately lower cost. Multi-pollutant control technologies integrate in-situ and/or 

post-combustion controls of at least two of the following pollutants: SO2, NOx, and Hg (and 

other hazardous air pollutants including cadmium, arsenic, and nickel), and CO2. 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 often limit them to larger, utility boilers. Since 

coal-fired boilers represent the single largest source category for both NOx (as well as SO2 and 

Hg) and PM in the thirteen-state region, it is worth considering 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 NOx, SO2, and Hg from coal-fired power plants [26]. Some of the bills 

also include emission limits for CO2. 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 SO2 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; and 1.98 mm TPY in the eastern region). For 

NOx, 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 CO2 to be met by 2008 

(roughly 1990 levels). Except for Hg, national trading 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 proposals. It would cap SO2 emissions at 4.5 mm TPY in 2010 and at 3 mm 

TPY in 2018. The corresponding limits for NOx are 3 mm TPY (in 2008) 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 CO2. A national trading program similar to the existing trading program for SO2

emissions under Title IV of the Clean Air Act will be the implementation mechanism to achieve 

these caps. All electric generation sources greater than 25 MW would fall under this program. 

• The Clean Air Planning Act (CAPA, Carper,Breaux, Baucus, and Chafe)) was intended as 

middle ground between the CPA and CSA. For SO2, 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 NOx are 1.87 mm TPY by 2008 

and 1.7 mm TPY by 2012. The Hg cap limits are 24 TPY by 2008, and a potential cap of 5-

16 TPY by 2012 (this cap to be set by EPA and implies 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 allowed (each plant will be required to reduce its 

Hg emissions at site by at least 50% in 2008 and by 75% in 2012). For CO2, CAPA proposes 

to stabilize CO2 emissions at 2005 levels (approximately 2.6 billion TPY) by 2008, and then 

stabilize to 2001 levels (approximately 2.4 billion TPY) by 2012. 
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All three bills recognize and incorporate the WRAP SO2 trading program by setting separate 

caps on SO2 emissions in the West. The CPA and CAPA allow nationwide trading of NOx, 

while the CSA divides the country into two zones for NOx 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 the 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 under 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 partial trading. There is no trading under CPA. 

Both CSA and the first phase of CAPA have modest Hg emission reduction targets; these would 

make it possible in some cases to achieve reduction of Hg as a “co-benefit” 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 additional incentive to install an SCR and/or FGD on 

plants for which there might not be justification on the basis of a single pollutant. 

In terms of Hg co-benefits, the West is at a disadvantage as compared to the East. In the latter 

region, more utilities burn bituminous coals that are high in chlorine (which tends to increase the 

amount of oxidized Hg in flue gas) and in sulfur. Wet scrubbers are effective for the removal of 

oxidized Hg, but ineffective for removal of the elemental Hg that is the predominant form of Hg 

in many western power plants. If all coal-fired power plants must reduce Hg emissions by 

upwards of 70%, the West will have a more difficult job than the East, owing to differences in 

coal composition. The bills that allow Hg trading (CSA and CAPA) would allow western power 

plants to deploy Hg control technology at plants were the highest emissions 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 control, 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 trillion Btu input). In this case, coal-fired power 

plants will have to look at application of activated carbon injection, the most mature technology 

for Hg control currently, or one of the multi-pollutant processes under development. Activated 

carbon injection may require adding additional particulate 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, chromium, 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 addition to in-situ and post-combustion control processes, options such 

as advanced power generation technologies, power plant rehabilitation-upgrading-repowering, 

fuel switching or blending and power plant optimization are sometimes included in the multipollutant control category. Emerging and commercial processes for multi-pollutant control for 

coal-fired boilers are summarized in Table 25, which 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. 
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Approximately half of the options listed in Table 25 are in commercial and early commercial 

stages. However, nearly all the options in commercial stage are proven SO2 control 

technologies, which also remove Hg, advanced power generation options and power plant 

upgrading-fuel switching options. Nearly all in-situ and post-combustion controls (SO2-NOx or 

SO2-NOx-Hg) are either in demonstration or pilot-scale. Some technologies (e.g., SNOX, SNRB, 

Advacate and CZD) have been tested either in pilot or demonstration scale 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 technologies may become more cost-effective if 

additional controls are required. Most of the environmental control processes increase the 

auxiliary power requirements of the plant (some up to 5%, but mostly in the range of 1 to 2%), 

increasing proportionally the CO2 emissions. 

Emerging post-combustion, multi-pollutant control technologies are being developed by a 

number of companies. The Electro-Catalytic Oxidation (ECO) system is a four-stage pollution 

control process that integrates established technologies to remove SO2, NOx, Hg and PM2.5. 

The system also produces a valuable fertilizer byproduct. The AIRborne process removes SO2

and NOx from plant emissions while turning the leftover material into a high-quality granular 

fertilizer. EnviroScrub is a dry scrubbing system that results in control of SO2, NOx, 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 CO2. 

Capital costs of options controlling two pollutants (either SO2-NOx or SO2-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. Also, lack of information, especially 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 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 gasification combined cycle (IGCC) are potentially attractive 

options because they are revenue-generating options, while reducing significantly SO2 and NOx, 

and to a lesser extent CO2. These options are available mainly for new power plants. Also, 

supercritical pulverized coal boiler provides an attractive 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 percentage, their cost-effectiveness is attractive; also, 

the amount of CO2 reduction (in tons or tons per year) is significant. 

Of particular interest are options such as power 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 options. Optimization involves only operating 

changes, and while it results in only minor emission reductions, its costs are very low and 

therefore it is an attractive option and should be pursued in all power plants. Fuel blending or 

switching, and power plant upgrading provide significant opportunities for emission control, but 

their site-specific nature makes it difficult to generalize regarding their emission reduction 

potential and cost-effectiveness. A more site-specific assessment is recommended to assess the 

potential for these options in a typical utility system. 
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Table 25. Commercial and Emerging Multi-Pollutant Control Technologies for External Combustion B

Status: P = pilot stage; C = commercial; D = demonstration 

Issues Hg removal can coal type, operaPotential impactDemonstration oneeded Not used commimpacts on ESP Full scale demoinsufficient infoFew application potentially expeHg removal may coal type, operato Spray DryersHigh costs and arequirements Cost-effectiveneRequires demonDemonstration icomparable to FIn demonstratio

Applicability Low to medium sulfur coals Units with ESP or FF for particulate control Existing plants, especially older units less than 300 MW Units with ESP or FF for particulate control Wet Scrubber Plants Integration with wet scrubbers, retrofit dry ESPs, new units NOX-Hg control for low to medium sulfur coals(same as Spray Dryers) New and retrofit New and retrofit New and retrofit New and retrofit New and retrofit 

Emissions Reductions SO2: >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: 

NA SO2: 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: 

NA 

Status C P/C C/D P/C P C/P P/C C/D C P D D 

Technology SO2/Mercury Control

Dry Scrubbers (conventional) SO2 sorbents, low temperature 

SO2 sorbents, furnace injection Activated carbon with SO2

sorbent processes Wet FGD with mercury oxidation processes Wet FGD with wet ESP Advanced Dry FGD SO2/NOx Control

E-BEAM SNOX SNRB AIRborne Thermal NOX 
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Issues High costs, due to high Not widely ash salabilitimpact of mDemonstratDemonstratestimated to FGD-SCRDepends on 

Applicability New and retrofit Retrofit and new units with ESP an/or FF New and Retrofit New and retrofit. Plants with SCR and Wet scrubber technologies 

Emissions Reductions SO2: 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% 

Status C P/C D D C 

Technology SO2/NOx/Mercury Control

Activated Coke Activated carbon with particulate controls Electro Catalytic Oxidation EnviroScrub Wet FGD and SCR 

Table 25. Commercial and Emerging Multi-Pollutant Control Technologies for External Combustion B

Status: P = pilot stage; C = commercial; D = demonstration 

Table 25. Commercial and Emerging Multi-Pollutant Control Technologies for External Combustion Boi
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6 SUMMARY AND RECOMMENDATIONS 

6.1 NOx and PM Sources 

The main objectives of this project were to identify and briefly describe the available (or 

emerging) technologies for control of NOx and PM emissions that could be applied to sources in 

the western United States. The starting point for this work was an analysis 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, and WY. The GCVTR accounted for 75% of the 

NOx emissions and 83% of the PM emissions within the thirteen-state region. Generally, the 

distribution of sources was the same in the GCVTR 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 NOx emissions in the 1996 WRAP database for the 

thirteen-state region. For ICE’s (reciprocating engines 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 stationary source emissions. Thus, NOx 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 NOx by far in the thirteen-state region is coal-fired boilers (68%); 

the top five categories (coal-fired boilers, internal combustion engines, cement kilns, turbines 

and oil and natural gas boilers) account for 90% of the NOx emissions. The states with the 

largest stationary source NOx 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 

NOx sources greater than 100 TPY had at least one type of control. 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 for 1996. Therefore, the 1996 WRAP database was 

compared with the data available for utility boilers in the 1996 CEMS and E-GRID databases. 

The EIA-767 database was also searched for NOx control technologies. This comparison only 

looked at coal-fired utility boilers and not all coal-fired boilers. However, only 3% of the WRAP 

NOx emissions from coal-fired boilers in the thirteen-state region were from non-utility boilers. 

WRAP data augmented by these other databases suggested that 44% of the utility boilers had at 

least one type of NOx control in 1996, mostly low-NOx burners. 

The NOx emission rate from external combustion boilers that is achievable with combustion 

modification depends on the fuel type. For coal-fired boilers, lower NOx emission rates are 

obtained when firing subbituminous coal as compared to bituminous coal. Considering the 
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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. The largest source category in the thirteen-state region is coal-fired boilers 

(40%); the top eight categories account for 92% of the PM emissions (greater than 100 TPY): 

coal-fired boilers, mineral processing, petrochemical, wood boilers, fugitive, 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 category of emissions, had 

PM controls. Overall, though, only 38% of units had PM controls. 

6.2 Controls for NOx and PM 

Many commercially available technologies exist for control of NOx and PM emissions from 

stationary sources. Twenty-five NOx control technologies and four PM control technologies 

were summarized. Cost and performance information was obtained for most technologies. 

There are a lot more technologies available for NOx control because of the different ways in 

which NOx can be prevented or destroyed. In contrast, 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 modification. Further work should be done to look into the details of 

important industrial processes to determine where process modification will yield significant 

reductions in PM. 

Most of the NOx emissions from stationary sources are generated by combustion or by high 

temperature thermal processing. NOx control technologies fall broadly into two categories: 

combustion modifications and post-combustion removal or destruction. Combustion systems 

differ, from internal combustion engines to external combustion boilers. Thus, there are many 

different strategies for modifying the combustion process. Deciding on an appropriate NOx 

control technology is highly dependent on the process conditions and on the type of fuel. The 

existing NOx control technology on a particular source will also influence what additional NOx

controls can be added successfully. Post-combustion NOx controls are not truly “back-end” 

technologies, like ESPs and baghouses for PM control; some degree of process 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 NOx 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 NOx control technology already in use; and 

• The target NOx emission rate. 
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Emerging environmental issues and regulatory changes have driven interest in multi-pollutant (as 

opposed to single pollutant) control technologies capable of addressing air pollutant emissions 

more comprehensively with greater flexibility and ultimately lower cost. Multi-pollutant control 

technologies integrate in-situ and/or post-combustion controls of at least two of the following: 

SO2, NOx, and mercury pollutants, and CO2 emissions. Multi-pollutant controls are intended 

primarily for external combustion boilers, particularly coal-fired boilers. The complexity of 

some of these processes as well as regulatory drivers often limit them to larger, power-generation 

boilers. 

Emerging post-combustion, multi-pollutant control technologies are being developed for SO2, 

NOx, and mercury that could be applied 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 SO2

removal rates of greater than 50%, and NOx removal rates of greater than 70%. Several of these 

processes are currently in pilot or full-scale demonstration. Costs of options controlling two 

pollutants (either SO2-NOx or SO2-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. Also, lack of information, especially 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 costs of the combined commercial technologies, FGD 

and SCR are above 200-250 $/kW. 

6.3 What’s on the horizon? What trends will influence emissions and control 

technologies? 

- The rate of advancement and use of multi-pollutant technologies (NOx/Hg, SO2/Hg, 

PM/Hg, etc.) will depend on the levels of future mercury emissions reduction. 

- Significant enhancements have been made in the ability of combustion modifications to 

reduce NOx formation, but they may be reaching their maximum potential given the 

theoretical limits within the combustion process and given the nitrogen content of some 

fuels (e.g., coal). Determining how much NOx emissions can be reduced in the West 

through this type of technology will require closer examination of the types and vintages 

of combustion modifications 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 turn 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 existing 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 new perspective, one which includes greater 

emphasis on overall impacts, costs, inter-pollutant compatibility, etc.
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6.4 Recommendations for Future Work 

Further work must be done in order to generate both accurate costs and reasonable control 

scenarios to be used in both regional-scale atmospheric 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; 

• NOx and PM control technologies already in place; and 

• Accurate estimates of the current emissions. 

Better use could be made of existing EPA databases; 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 complete picture of current emissions and control 

technologies for NOx and PM. Since much has changed in the West since the 1996 WRAP 

stationary source inventory, these databases are useful for getting more current information on 

utility boilers, which generate a significant amount of the emissions in the western U.S. It would 

be worthwhile now to look at trends in emissions and NOx control technologies in the West by 

analyzing the most recent CEMs and E-GRID databases. 

Sufficient detail about the configuration and process of the sources is generally not available in 

the EPA databases and these databases are only for utility boilers. The 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 are instances in the 1996 WRAP database in which 

there is insufficient information on the type of source and/or the fuel in use. Obviously, better 

identification of existing air pollution control technology is critical. For combustion sources, 

particularly utility boilers, the capacity, in terms of MBtu/yr should 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 emissions reductions. The subset should be a 

representative distribution of those sources within the most important source categories. 
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 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 Technology Options for Coal-Fired Power Plants,” 

EPA-600/R-02/075, October 2002. 

5. Battye, R., Walsh, S., Lee-Greco, J. “NOx Control Technologies for the Cement Industry 

(Final Report).” EPA Contract No. 68-D98-026, EC/R Incorporated, Chapel Hill, NC, 

September 2000. 

6. Dusome D. (1993). “Staged Combustion for NOX Control at the Calaveras Tehachapi 

Plant”, presented to the Portland Cement Association. 

7. Nielsen, P.B. et al. (1990). “An Overview of the Formation of SOX and NOX in Various 

Pyroprocessing Systems”, IEEE Cement Industry Technical Conference. 

8. SA Johnson and S Haythornthwaite, Summary of Available NOx Control Techniques for 

the Cement Industry, submitted to the Portland Cement Association, Skokie, IL 1998. 

9. Amar, K.P., Staudt, J. “Status Report on NOx Controls for Gas Turbines, Cement Kilns, 

Industrial Boilers, Internal Combustion Engines; Technologies and Cost Effictiveness.” 

Norhteast States for Coordinated Air Use Management, Boston, MA, January, 2001.

10. U.S. Environmental Protection Agency. “Alternative Control Techniques DocumentNOx Emissions from Stationary Gas Turbines.” 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 Environmental Protection. “State of the Art (SOTA) 

Manual for Reciprocating Internal Combustion Engines.” Trenton, NJ, July, 1997. 

13. SA Johnson and S Haythornthwaite, Summary of Available NOx Control Techniques for 

the Cement Industry, submitted to the Portland Cement Association, Skokie, IL 1998. 

14. State of California Air Resources Board. “CAPCOA/ARB Proposed Determination of 

Reasonably Available Control Technology and Best Available Retrofit Control 

Technology for Stationary Internal Combustion Engines (DRAFT).” Sacramento, CA, 

December, 1997. 

15. State of New Jersey Department of Environmental Protection. “State of the Art (SOTA) 

Manual for Reciprocating Internal Combustion Engines.” Trenton, NJ, July, 1997. 

16. European IPPC Bureau. “Reference Document on Best Available Techniques in the 

Glass Manufacturing Industry.” Seville, Spain, October, 2000. 

17. W. Neuffer, U. S. EPA. Summary of Information Provided by Engine Manufacturers on 

Low Emission Combustion. 

18. Telecon. R. Faulkner, Diesel Supply Company, with S. Edgerton, EC/R. April 6, 2000. 
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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 Services, 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: Plasma Ignition Retard for NO(x) Reductions.” 

http://es.epa.gov/ncerqa_abstracts/sbir/94/topics43.html. 

22. Manufacturers of Emission Controls 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 NOx Emissions by State 
A-1 

Table A-1. WRAP NOx Emissions for sources > 100 TPY by State 

Category 13-States AZ* CA*  # Units 

Total NOx

TPY (>100 

TPY) # Units 

Total NOx

TPY (>100 

TPY) # Units 

Total NOx

TPY (>100 

TPY) # Units 

Coal-Fired Boilers 151 607,748 15 75,018 3 1,544 31 Reciprocating Engines 423 86,210 16 6,441 58 10,274 56  NG 404 81,786 14 5,731 54 9,436 5 Diesel 16 4,021 2 709 3 708  Process Gas 3 403 1 130 Cement Kilns 39 41,009 2 4,662 16 15,886 4 Oil/NG Boilers 112 32,910 4 1,092 40 12,290 9 Turbines 86 25,278 8 1,918 37 8,990 9  NG 83 24,821 7 1,795 37 8,990  Diesel 3 457 1 123 Mineral Processing 34 16,250 4 2,861 4 3,263 Petrochemical 48 13,719 1 101 13 3,978 4 NG Compressor 16 10,959 14 10,686 Pulp and Paper 39 10,010 3 602 Wood Boilers 48 9,776 14 2,430 Refinery Process Heaters 38 9,311 28 7,096 Glass Manufacture 14 5,033 11 4,128 1 Primary Metal Production 17 3,476 2 1,009 2 Waste Combustion 6 3,309 Refinery Emissions 8 3,256 8 3,256 In-process Fuel Use 9 2,605 7 1,906 Jet Engine Testing 4 2,297 4 2,297 Oil and Gas Production 7 1,140 Smelting Operations 3 961 2 852 Sugar Beet Production 3 730 1 111 Secondary Metal Production 4 507 Turbines, Steam 1 165 1 165 Total (> 100 TPY) 1,110 886,659 68 104,639 248 78,217 116 

* GCTVR State 
A-2 

Table A-1. WRAP NOx Emissions for sources > 100 TPY by State [continued] 

Category ID* MT ND  # Units 

Total NOx

TPY (>100 

TPY) # Units 

Total NOx

TPY (>100 

TPY) # Units 

Total NOx

TPY (>100 

TPY) # Units 

Coal-Fired Boilers 6 2,218 6 25,452 17 108,007 10 Reciprocating Engines 14 4,357 8 2,569 201  NG 4 2,056 8 2,569 20 Diesel 10 2,301  Process Gas Cement Kilns 1 1,662 1 Oil/NG Boilers 1 128 3 909 10 Turbines 1 139 0 0 3 564 12  NG 1 139 3 564 1 Diesel Mineral Processing 1 117 3 428 1 Petrochemical 3 1,449 5 842 1 915 1 NG Compressor Pulp and Paper 3 377 4 920 Wood Boilers 4 708 4 1,057 1 Refinery Process Heaters 1 Glass Manufacture Primary Metal Production Waste Combustion 4 2,971 Refinery Emissions In-process Fuel Use 1 589 Jet Engine Testing Oil and Gas Production 2 348 1 Smelting Operations Sugar Beet Production 2 619 Secondary Metal Production Turbines, Steam Total (> 100 TPY) 18 5,008 39 35,436 40 116,901 23

* GCTVR State 
A-3 

Table A-1. WRAP NOx Emissions for sources > 100 TPY by State [continued] 

Category NV* OR* SD  # Units 

Total NOx

TPY (>100 

TPY) # Units 

Total NOx

TPY (>100 

TPY) # Units 

Total NOx

TPY (>100 

TPY) # Units 

Coal-Fired Boilers 8 39,040 1 4,195 3 17,268 15 Reciprocating Engines 15  NG  Diesel  Process Gas Cement Kilns 2 3,789 2 687 3 2,718 2 Oil/NG Boilers 6 3,727 6 2,155 1 Turbines 1 191 3 5,372 2 435 3  NG 2 5,229 2 435  Diesel 1 191 1 143 Mineral Processing 2 218 2 577 5 Petrochemical 2 NG Compressor 2 Pulp and Paper 14 3,641 Wood Boilers 17 3,366 Refinery Process Heaters Glass Manufacture Primary Metal Production 1 125 3 514 7 Waste Combustion 2 Refinery Emissions In-process Fuel Use 1 109 Jet Engine Testing Oil and Gas Production Smelting Operations Sugar Beet Production Secondary Metal Production Turbines, Steam Total (> 100 TPY) 21 47,199 46 19,929 10 20,998 

* GCTVR State 
A-4 

Table A-1. WRAP NOx Emissions for sources > 100 TPY by State [continued] 

Category WA WY*  # Units 

Total NOx 

TPY (>100 

TPY) # Units 

Total NOx 

TPY (>100 

TPY) 

Coal-Fired Boilers 8 20,138 28 95,148 Reciprocating Engines 7 1,191 48 10,219  NG 5 918 48 10,219  Diesel  Process Gas 2 273 Cement Kilns 4 4,126 2 1,444 Oil/NG Boilers 28 5,758 4 553 Turbines 3 324 4 1,971  NG 3 324 4 1,971  Diesel Mineral Processing 4 1,904 8 2,197 Petrochemical 11 3,635 7 1,619 NG Compressor Pulp and Paper 15 4,471 Wood Boilers 8 1,856 Refinery Process Heaters 9 2,009 Glass Manufacture 2 654 Primary Metal Production 1 116 1 205 Waste Combustion Refinery Emissions In-process Fuel Use Jet Engine Testing Oil and Gas Production 4 652 Smelting Operations 1 109 Sugar Beet Production Secondary Metal Production 4 507 Turbines, Steam Total (> 100 TPY) 105 46,798 106 114,009 

*GCVTR State 
: 

APPENDIX B : Breakdown of PM Emissions by State 
Table B-1. WRAP PM Emissions for sources > 100 TPY by State 

Category 13-States AZ* CA* C # Units 

Total PM 

TPY # Units 

Total PM 

TPY # Units 

Total PM 

TPY # Units 

Coal-Fired Boilers 88 46,010 9 2,657 1 699 3 Mineral Processing 85 24,499 14 4,932 5 710 18 Petrochemical 42 10,836 5 834 4 Wood Boilers 24 5,718 3 471 Refinery Emissions 11 5,631 2 3,949 1 104 3 Primary Metal Production 20 4,697 3 529 1 139 1 Pulp and Paper 15 4,476 2 272 Smelting Operations 8 3,555 1 137 Miscellaneous 1 2,456 1 2,456 Oil/NG Boilers 5 1,379 Sugar Beet Processing 5 1,150 1 210 1 110 1 Cooling Tower 4 932 Cement Kilns 4 641 1 132 Turbines 2 838 1 590 1  Diesel 1 590 1 590  NG 1 248 Secondary Metal Production 1 537 Jet Engine Testing 2 535 2 535 Reciprocating Engines 3 525 1 104 1  Diesel 2 273 1 104  NG 1 252 Refinery Process Heaters 1 176 1 176 Total 321 114,589 32 13,107 24 6,638 32 

* GCTVR State 
Table B-1. WRAP PM Emissions for sources > 100 TPY by State [continued] 

Category ID* MT ND N # Units 

Total PM 

TPY # Units 

Total PM 

TPY # Units 

Total PM 

TPY # Units 

Coal-Fired Boilers 8 5,180 4 3,990 11 3,679 9 Mineral Processing 5 1,864 9 2,565 1 110 2 Petrochemical 4 688 2 274 1 590 1 Wood Boilers 6 1,683 2 242 Refinery Emissions Primary Metal Production 1 477 Pulp and Paper 6 2,949 Smelting Operations 1 158 4 Miscellaneous Oil/NG Boilers Sugar Beet Processing 1 297 Cooling Tower Cement Kilns 1 216 1 117 1 Turbines  Diesel  NG Secondary Metal Production Jet Engine Testing Reciprocating Engines  Diesel  NG Refinery Process Heaters Total 30 12,579 20 7,825 14 4,676 17 

* GCTVR State 
Table B-1. WRAP PM Emissions for sources > 100 TPY by State [continued] 

Category NV* OR* SD U # Units 

Total PM 

TPY # Units 

Total PM 

TPY # Units 

Total PM 

TPY # Units 

Coal-Fired Boilers 8 5,688 1 108 2 236 8 Mineral Processing 2 244 11 Petrochemical Wood Boilers 11 3,056 Refinery Emissions 1 233 Primary Metal Production 1 211 1 276 4 Pulp and Paper 5 898 Smelting Operations 2 Miscellaneous Oil/NG Boilers 4 1,235 1 144 Sugar Beet Processing Cooling Tower Cement Kilns Turbines  Diesel  NG Secondary Metal Production 1 537 Jet Engine Testing Reciprocating Engines  Diesel  NG Refinery Process Heaters Total 15 7,379 20 5,019 3 469 25 

* GCTVR State 
Table B-1. WRAP NOx Emissions for sources > 100 TPY by State [continued] 

Category WA WY*  # Units 

Total PM 

TPY # Units 

Total PM 

TPY 

Coal-Fired Boilers 4 2,968 20 10,400 Mineral Processing 18 6,594 Petrochemical 2 255 23 7,130 Wood Boilers 2 266 Refinery Emissions 3 386 1 115 Primary Metal Production 8 1,976 Pulp and Paper 2 357 Smelting Operations Miscellaneous Oil/NG Boilers Sugar Beet Processing 1 103 Cooling Tower 4 932 Cement Kilns Turbines  Diesel  NG Secondary Metal Production Jet Engine Testing Reciprocating Engines 1 252  Diesel  NG 1 252 Refinery Process Heaters Total 22 6,311 67 25,423 

*GCVTR State 
APPENDIC C: NOx Control Technology Summaries 
C-1 

Process: Air or Fuel Staging

Category 

NOx, TPY 

(WRAP 

1996) 

%NOx

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 NOx

can be destroyed. Sometimes includes installing a “NOx 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 

NOx Reduction: 

NOx reduction is achieved by creating two separate combustion zones. The burner zone is fired fuel-lean 

to create the high temperatures needed for clinker formation. 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. NOx reductions as high as 50% can be achieved by controlling the size of the fuel-rich region in 

the second combustion zone. Conversely, if combustion is fuel-lean or well-mixed in the second zone, 

NOx 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 NOx

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 reducing conditions adversely affect cement quality. 

Development Status: 

Commercially available. 

Practical Considerations: 

The technology is easier to implement on preheater/precalciner 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 SO2 emission controls. 
C-2 

Process: Air or Fuel Staging

Secondary Environmental Impacts: 

None expected. 

References: 

Dusome D. (1993). “Staged Combustion for NOx Control at the Calaveras Tehachapi Plant”, presented to 

the Portland Cement Association. 

Nielsen, P.B. et al. (1990). “An Overview of the Formation of SOX and NOX in Various Pyroprocessing 

Systems”, IEEE Cement Industry Technical Conference. 

Johnson, S.A. and Haythornthwaite, S., “Summary of Available NOx Control Techniques for the Cement 

Industry”, submitted to the Portland Cement Association, Skokie, IL, 1998. 
C-3 

Process: Batch/Cullet Preheating

Category 

NOx, TPY 

(WRAP 

1996) 

%NOx

reduction Cost, $/ton Status 

Glass Manufacturing 5,033 5-25% 890-1,040 Commercial 

Process Description: 

Batch and cullet (recycled glass) preheating can be applied 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 that 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 technique (savings between 10-20%), but its practice 

reduces NOx emissions due to lower fuel requirements and lower furnace temperatures. 

Cost Information: 

Capital costs generally range from $42K-110K. Economics 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 temperature 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 temperature of the flue gases should not exceed 600°C. 

The design and implementation of the preheating unit 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 combustion 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/Nm3

) and secondary particulate abatement is necessary. 

• Direct preheating reduces acidic compounds, SO2, HF, and HCl by up to 60%, 50%, and 90% 

respectively (difference before and after cullet bed). 

References 

European IPPC Bureau. “Reference Document on Best Available Techniques in the Glass Manufacturing 

Industry.” Seville, Spain, October, 2000. 
C-4 

Process: Catalytic Combustion

Category 

NOx, TPY 

(WRAP 

1996>100 

TPY) 

%NOx

reduction Cost, $/ton Status 

 Combustion or Gas Turbines 25,278 > 80% > 500 Commercial 

Process Description: 

Catalytic combustion reduces NOx formed from the combustion process by reducing the combustion 

temperature to reduce thermal NOx. 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 temperatures 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 configuration. 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 combustion is completed in a second stage catalyst bed. 

NOx Reduction: 

According to one developer of the technology, catalytic combustion has been demonstrated to achieve 3 

ppm NOx on a 1.5 MW gas turbine. A NOx 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 combustor types and are effective on both diesel- and gasfired turbines. The technology has a limited operating 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 NOx Controls for Gas Turbines, Cement Kilns, Industrial Boilers and 

Internal Combustion Engines: Technologies and Cost Effectiveness,” December 2000

U.S. Environmental Protection Agency. “Alternative Control Techniques Document-NOx Emissions 

from Stationary Gas Turbines.” EPA-453/R-93-007, Research Park Triangle, NC, January 1993. 

DOE, “Cost Analyses of NOx Control Alternatives for Stationary Gar Turbines”, November 1999.
C-5 
C-6 

Process: DLN (Fuel-lean combustion)

Category 

NOx, TPY 

(WRAP 

1996>100 

TPY) 

%NOx

reduction Cost, $/ton Status 

Turbines 25,278 70% 1,000-2,000 Commercial 

Process Description: 

Dry Low NOx (DLN) is a combustion technology for gas turbines that enables gas-turbine combustors to 

produce low NOx emission levels without diluents (such as water or steam) or catalysts. DLN technology 

utilizes a lean, premixed flame as opposed to a turbulent diffusion flame, a gas turbine equivalent of the 

LNB. 

NOx Reduction: 

Engines from 3-10 MW retrofit with DLN achieved 42 ppm NOx 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 NOx. 

Cost Information: 

The cost of NOx reduction by DLN is very sensitive to the capacity 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 project management or other charges associated with 

the project beyond the equipment and installation. 

Development Status: 

Commercially available 

As of August 2000, about 50 turbines had been retrofitted and over 500 new turbines were operating with 

DLN technology. 

Practical Considerations: 

Because DLN combustor technology operates under conditions that are much closer to the flammability 

limit than the conventional combustor technology, there is a significant risk of flame instability. 

Manufacturers have developed improved electronic turbine controls to address this problem. Some early 

experience has also found combustor liners failing after only about 5,000 hours compared to over 20,000 

hour lifetime for conventional technology. Similarly, 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 NOx 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 conventional 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 NOx 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 

NOx, TPY 

(WRAP 

1996>100 

TPY) 

%NOx

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 NOx reduction approach that involves reintroducing 

some flue gas (5% to 15%) into the combustion air (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. This is because its main benefit is in the minimization 

of thermal NOx (NOx formed from nitrogen in the combustion air), as opposed to fuel-NOx (NOx formed 

from fuel-bound nitrogen). Since in oil and coal sources a significant fraction of NOx comes from “fuelNOx”, FGR is less effective in such applications 

NOx Reduction: 

NOx reductions from FGR on gas-fired sources can be in the range of 40% to 80%. 

FGR is often used in combination with LNBs and 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 operations 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 levels 
C-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 NOx technologies although the overall cost effectiveness 

needs to be addressed case-by-case. 

Secondary Environmental Impacts: 

None expected. 

References: 

EPRI, “Retrofit NOx Control Guidelines for Gas- and Oil-Fired Boilers”, Final Report, December 1993. 

Poole, L., “Houston Galveston Area NOx Abatement Industries Perspective,” present at the Council of 

Industrial Boiler Owners, NOx Control XV Conference, Houston, TX, August 2002. 
C-10 

Process: Fuel Reburn

Category 

NOx, TPY 

(WRAP 

1996>100 

TPY) 

%NOx

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 the “Combustion Modification” category of NOx 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 NOx formed in the main burner zone is destroyed by reacting with 

hydrocarbon and nitrogen compounds. The hardware needed for reburning includes reburn fuel burners or 

nozzles and overfire or burnout air ports (see discussion 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 capability of the existing boiler (e.g., the burner/boiler 

control system). 

NOx Reduction: 

Full load NOx 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% ∆NOx

• initial NOx level 

• “tolerance” of negative impacts (e.g., efficiency loss, ash quality) 

At low loads, NOx reduction may fall 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 

temperature). Reburning, like SNCR and SCR, may be thought of as a “dial-in” technology in that NOx

reductions will be a function of the 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 differential (certainly gas vs 

coal). For other fuels (e.g. coal/orimulsion reburning), 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 NOx 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 and encouraging results, which increase the level of 

comfort with the technology; and (2) the “proliferation” of advanced reburn technologies, each with its 

own features, advantages and disadvantages. These “advanced” reburning options involve enhancements 

of the conventional approach, with features ranging 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 characteristics 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 pulverizers (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 provides benefits from lower maintenance costs (e.g., less 

demand on pulverizers) and lower emissions of other pollutants (particulate, SOx, CO2). 

Compatibility with other air pollution control technologies: 

Reburn Technology can be implemented with both Low NOx combustion approaches (e.g. LNBs) and 

post combustion technologies (SNCR/SCR). However, the overall NOx 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 positive 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 design 
C-12 

Process: Fuel Reburn

• SO2/CO2 benefits when reburn fuel is gas (proportional to gas input) 

References: 

NESCAUM, “Status Report on NOx Control Technologies and Cost Effectiveness for Utility Boilers”, 

June 1998. 

EPRI, “Retrofit NOx Controls for Coal-Fired Utility Boilers – 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 

NOx, TPY 

(WRAP 

1996>100 

TPY) 

%NOx

reduction Cost, $/ton Status 

 Reciprocating Engines 86,210 50% - 80% 115 - 200+ Commercial 

Process Description: 

HEIS technology, also known as plasma ignition, provides 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 fraction of a degree of crankshaft rotation. The extended 

energy ensures that ignition will occur even in the leanest of conditions. A rich mixture is ignited in a 

small ignition cell located in the cylinder head. The ignition cell flame passes to the cylinder where it 

provides a uniform ignition source. 

NOx Reduction: 

Laboratory tests and case studies have shown NOx 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% reduction 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 NOx RACT requirements in the range of 2.5 to 3.0 

g/bhp-hr in the Eastern United States. Several users have reported over 80% reduction in NOx emissions. 

Practical Considerations: 

HEIS technology can be used only in lean-burn, natural 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 NOx technologies (SCR, NSCR). However, the overall NOx reductions 

are not strictly additive and careful evaluation is required to ensure cost effective strategies. 

Secondary Environmental Impacts: 

In most cases, NOx reductions have been accompanied by increased power output and increased fuel 

economy. 

References: 

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. 

NESCAUM, “ Status Report on NOx Controls for Gas Turbines, Cement Kilns, Industrial Boilers and 
C-14 

Process: High Energy Ignition System (HEIS)

Internal Combustion Engines: Technologies and Cost Effectiveness,” December 2000. 

State of New Jersey Department of Environmental Protection. “State of the Art (SOTA) Manual for 

Reciprocating Internal Combustion Engines.” Trenton, NJ, July, 1997. 

Alternative Control Techniques Document: NOx 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 

NOx, TPY 

(WRAP 

1996>100 

TPY) 

%NOx

reduction Cost, $/ton Status 

Reciprocating Engines 86,210 ~80% N/A (less than LEC) Commercial 

Process Description: 

High-Pressure Fuel Injection represents a “second generation” Low Emission Combustion (LEC), 

according to one vendor of NOx 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 comparison to LEC, diminishing the turbocharging and 

intercooling retrofit requirements. 

NOx Reduction: 

Tests from a large (~5,000 bhp) turbocharged Clark 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 turbocharging and intercooling required. 

Development Status: 

Commercially available 

Considered emerging in 2000. 

Practical Considerations: 

An LEC retrofit vendor stated that NOx emissions cannot be reduced to 2 g/bhp-hr through the use of a 

high-pressure fuel system alone. Less stringent regulatory requirements cans be met with a combination 

of ignition timing adjustment, high-pressure fuel injectors, and improve A/F ratio and ignition system 

controls. 

Compatibility with other air pollution control technologies: 

Compatible with post-combustion NOx technologies (SCR, NSCR). However, the overall NOx 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. “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. 

National Center for Environmental Research, U. S. EPA Office of Research and Development. “1994 

Phase II Abstracts: Plasma Ignition Retard for NO(x) Reductions.” 

http://es.epa.gov/ncerqa_abstracts/sbir/94/topics43.html. 
C-16 
C-17 

Process: “Intelligent” Combustion Controls

Category 

NOx, TPY 

(WRAP 

1996) 

%NOx

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 airflow 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 resides on the operator’s digital control system (DCS). 

NOx Reduction: 

Full -load NOx reductions with combustion monitoring and tuning 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 NOx level. 

o Operational flexibility of the burner/furnace design. 

The highest NOx 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, NOx 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 monitoring and tuning are less than $1M per boiler. 

Operating costs are mainly driven by additional labor 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 efficiency can be increased. Reducing unburned carbon in 

the ash residue will not only increase boiler efficiency but also could improve salability of this byproduct 

to the cement industry. 

An outage is generally not required when implementing 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 dependability. Since each application of the technology 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 combustion expert to achieve best results. 

Practical Considerations: 

Boilers with the following design and operating characteristics are expected to be more suitable 

candidates for combustion monitoring and tuning: 

• Combustion equipment must be in good operating 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 NOx combustion approaches (e.g. 

LNBs) and post combustion technologies (SNCR/SCR). However, the overall NOx reductions are not 

strictly additive and careful evaluation is required to ensure cost effective strategies. 

Secondary Environmental Impacts: 

Combustion monitoring and tuning has the potential 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 Guidelines, EPRI Report, December 1998 

Alternative Control Techniques Document: NOx Emissions from Industrial/Commercial/Institutional 

(ICI) Boilers. EPA Document No. EPA-453/R-94-022, July 1994. 

Alternative Control Techniques Document: NOx 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 DoctorTM System”, EPRI/DOE/EPA Mega Symposium, 

Washington, May 2003 

Kohn, D. “Combustion Optimization Case Studies & Emerging Applications”, EPRI/DOE/EPA Mega 

Symposium, Washington, May 2003 
C-20 

Process: Iron Slag Addition (CemStar)

Category 

NOx, TPY 

(WRAP 

1996) 

%NOx

reduction Cost, $/ton Status 

 Cement Kilns 41,009 12-30% 0-100 Commercial 

Process Description: 

Change cement formulation by adding waste iron to lower clinkering temperature and suppress NOx. The 

iron waste is usually supplied from local steel production facilities, which limits the technology to certain 

geographical areas. 

NOx Reduction: 

NOx reduction is achieved by reducing clinkering temperature as well as the required heat input to 

produce a ton of clinker. The technology reduces total NOx emissions by about 20 to 30%, and also may 

increase clinker production. 

Cost Information: 

Iron addition provides an overall economic benefit while reducing total NOx emissions. The technology 

is currently being used at several cement plants for its original purpose 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 incorporated 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 NOx Controls for Gas Turbines, Cement Kilns, Industrial Boilers, Internal 

Combustion Engines; Technologies and Cost Effectiveness.” December 2000. 
C-21 

Process: Kiln temperature control

Category 

NOx, TPY 

(WRAP 

1996) 

%NOx

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 

NOx is emitted. 

NOx Reduction: 

NOx reduction is achieved by measuring a characteristic flame-zone temperature and then controlling heat 

input to maintain that temperature. Without direct temperature measurement, 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. Temperature measurement helps operators avoid 

losing clinker formation and thus maintain relatively steady kiln temperatures. 

Cost Information: 

Capital cost for the technology includes installation 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 will 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. “Alternative Control Techniques Document: NOx Emissions from 

Cement Manufacturing.” EPA Document No. EPA-453/R-94-004, January 1994. 

Johnson, S.A. and Haythornthwaite, S., “Summary of Available NOx Control Techniques for the Cement 

Industry”, submitted to the Portland Cement Association, Skokie, IL, 1998. 
C-23 

Process: Low-Emission Combustion (LEC)

Category 

NOx, TPY 

(WRAP 

1996>100 

TPY) 

%NOx

reduction Cost, $/ton Status 

Reciprocating Engines 86,210 80-90% 190-700 Commercial 

Process Description: 

NOx 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. Additional combustion air acts as a heat sink, lowering the 

temperature in the cylinder and reducing NOx formation. Deeper leaning can be achieved by relocating 

the spark plug to a precombustion chamber (may use High-Energy Ignition, see associated description) 

where the mixture is somewhat richer than in the cylinder. Early sparking avoids problems associated 

with ignition and misfiring that can result form leaning the mixture. Some smaller engines use an “open 

chamber” LEC design instead of a precombustion chamber. These designs typically incorporate 

improved air-fuel mixing systems to achieve stable combustion under very lean conditions. 

NOx Reduction: 

Large, stationary spark-ignition engines usually achieve 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, and about 60-70% for landfill gas engines (probably due 

to lower initial NOx from the lower heating-value landfill gas). 

Engines with open-chamber LEC technology typically are designed for excess air levels only slightly 

above 50%, while engines with precombustion 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 engine BHP. For engines firing a single fuel, 

retrofits have been implemented costing $340/hp for 3400hp engines. A lower capital cost is expected for 

smaller, medium-speed engines, about $200/hp. Dual-fuel 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 based 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 gaseous 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 required to avoid derate. In retrofit situations, this typically involves 

upgrading or replacing the turbocharger and intercooler, or adding this equipment. 

Other equipment associated with increased air flows may also need to be modified for LEC, such as the 

air intake and filtration system, the intercooler radiator, 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 achieve proper ignition and stable combustion. Vendors of 

LEC technology (i.e., engine manufacturers and third-party 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 technologies (SCR, NSCR). However, the overall NOx

reductions are not strictly additive and careful evaluation 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. “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. 

NESCAUM. “Status Report on NOx Controls for Gas Turbines, Cement Kilns, Industrial Boilers, 

Internal Combustion Engines; Technologies and Cost Effectiveness.” December, 2000. 

State of California Air Resources Board. “CAPCOA/ARB Proposed Determination of Reasonably 

Available Control Technology and Best Available Retrofit Control Technology for Stationary Internal 

Combustion Engines (DRAFT).” Sacramento, CA, December, 1997. 

State of New Jersey Department of Environmental Protection. “State of the Art (SOTA) Manual for 

Reciprocating Internal Combustion Engines.” Trenton, NJ, July, 1997. 

U.S. Environmental Protection Agency. “Alternative Control Techniques Document – NOx 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 Services, Painted Post, NY. May 7, 1999. 2pp.
C-25 

Process: Low-NOx Burners

Category 

NOx, TPY 

(WRAP 

1996) 

%NOx

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 released in a region where the 

concentration of oxygen is very low. This inhibits 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 flame core. Additional air is introduced to surround the 

primary flame where the temperature is lower, limiting thermal NOx formation. A few low-NOx 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 introduces the dilute coal stream downstream of the burner 

while air is introduced only to the primary flame. The fuel introduced into the primary flame zone results 

in a high temperature fuel rich central flame. The balance of coal is added outside the primary flame 

where it burns at a lower temperature. 

NOx Reduction: 

Full load NOx reductions with Low-NOx Burners can be expected to range from 30% to 60% depending 

on factors such as: 

• Fuel type. 

• Initial NOx level. 

• Excess air 

• Operational flexibility of the boiler or furnace. 

For coal-fired boilers, NOx 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-NOx burners is usually the first step taken to reduce NOx 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 when existing burners are modified instead of replaced to achieve lower 

NOx. Operating costs are negligible unless increased unburned carbon results in lost revenues from ash 

sales. An outage is generally required when implementing this technology, but coal-flow sensors and 

adjustable orifices are best installed when a mill is out of service. 
C-26 

Process: Low-NOx Burners

Development Status: 

Commercially available. 

Practical Considerations: 

Since low-NOx Burners usually produce longer flames, the 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 optional configurations to 

shape the flame at the expense of less NOx reduction. 

Compatibility with other air pollution control technologies: 

Low-NOx burners can be implemented with other NOx-control technologies such as OFA, SNCR, or SCR. 

In general, the NOx reduction achieved with LNB make post-combustion NOx control technologies more 

cost-effective. 

Secondary Environmental Impacts: 

Low-NOx burners can cause 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 or finer particulate. 

 

References: 

EPRI, “Retrofit NOx Controls for Coal-Fired Utility Boilers – 2000 Update”, EPRI Final Report, 

December 2000 

EPRI, “Retrofit NOx Controls for Coal-Fired Utility Boilers – 1996 Update Addendum”, May 1997 
C-27 

Process: Low-NOx Calciners

Category 

NOx, TPY 

(WRAP 

1996) 

%NOx

reduction Cost, $/ton Status 

 Cement Kilns 41,009 30 to 50% 1000-5000 Commercial 

Process Description: 

Replace the riser duct in existing preheater/precalciner kilns with new equipment designed for staged 

combustion. The new duct has separated air and fuel injection points, and extended residence time 

downstream of the final air addition point to assure acceptable burnout and minimize CO or hydrocarbon 

emissions. 

NOx Reduction: 

NOx reduction is achieved by creating two separate combustion zones. The burner zone is fired fuel-lean 

to create the high temperatures needed for clinker formation. 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. NOx reductions as high as 50% can be achieved by controlling the size of the fuel-rich region in 

the second combustion zone. Conversely, if combustion is fuel lean or well mixed in the second zone, 

NOx 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 NOx

production when the staging air is added. 

Cost Information: 

Capital cost for the technology includes additional injectors, ductwork and controls. In some cases, the 

cyclones used to improve gas-solids contact are also replaced. Capital cost range from $500,000 and 

5,000,000 depending on how much of the existing tower is replaced. Operating costs should not change 

unless cement quality degrades due to lower temperatures 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 SO2 emission controls. 

Secondary Environmental Impacts: 

None expected. 
C-28 

Process: Low-NOx Calciners

References: 

Rother, R. and Kupper, D., “Staged Fuel Supply – An Effective Way of Reducing NOx Emissions”, 

Zement-Kalk-Gips, No. 9. 1989. 
C-29 

Process: Mid-Kiln or Tower Tire Injection

Category 

NOx, TPY 

(WRAP 

1996) 

%NOx

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 fuel 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 region 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 NOx but also generates revenue in the form 

of tipping fees and reduced fuel requirements. Cadence Environmental Energy, a subsidiary of Ash 

Grove Cement, offers an automated whole-tire injection system, including a fork that picks up the tires 

and drops them into the kiln through a gate assembly. A second option is to set up a tire shredding 

operation on site and inject tire flake into the kiln. 

NOx Reduction: 

NOx is lowered by burning some of the fuel at a lower temperature, and by creating pockets of fuel-rich 

gas as the tires decompose. Hydrocarbons from tire destruction can reduce NOx formed in the burner 

flame. Results to date have varied from 15 to 30% NOx 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 “NOx 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, injector costs can be recovered within a few years. 

An outage is required when implementing this technology, 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 much high-quality clinker as possible at the lowest 

energy cost. Over-feeding tires creates locally reducing conditions that cause smoke, soot, and spoil the 

naturally occurring sulfur capture in the clinker resulting in higher SO2 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 NOx emissions rise and fall erratically, making control very 

difficult. 

Compatibility with other air pollution control technologies: 

High airflows from the NOx fans can cause increased carryover of cement kiln dust (CKD) into the 

exhaust. Reducing conditions in the flame zone increase SO2 emissions. 

Secondary Environmental Impacts: 

Combustion monitoring and tuning has the potential to effect both positive and negative secondary 

environmental impacts depending on factors such as the 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. 

• SO2 may increase due to increased staging. 

• ESP performance may degrade with increased CKD. 

References: 

U.S. Environmental Protection Agency, “Alternative Control Techniques Document: NOx 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 

NOx, TPY 

(WRAP 

1996) 

%NOx

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 NOx 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 NOx emissions), the inlet exhaust stream 

must have very low oxygen content, as well as proper concentrations of NOx, 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. 

NOx Reduction: 

This source indicates that these catalyst systems reduce NOX emissions by over 98 percent, while 

reducing VOC by 80 percent and carbon monoxide by over 97 percent. NOx 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 after about 20,000 hours of operation. 

Development Status: 

Commercial. Information from vendors of NSCR systems 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 systems typically reduce the efficiency of the engine, 

harming fuel economy. The biggest operational problem associated with NSCR has 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 oxidized 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. “Emission Control Technology for Stationary Internal 

Combustion Engines.” Status Report, July 1997. 

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.
C-33 

Process: NOxTech

Category 

NOx, TPY 

(WRAP 

1996>100 

TPY) 

%NOx

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 exhaust gases are chemically treated with a nonhazardous 

liquid chemical. The technology involves replacing the engine exhaust silencer with a reaction chamber 

where NOx and reagent react to form nitrogen, water vapor, and carbon dioxide. The non-catalytic 

chemical reagent is injected into the exhaust at temperatures between 1,400 and 1,500 °F. 

NOx 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 NOx 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 these engines, NOxTech has been demonstrated as 

BACT for some diesel engines. 

Practical Considerations: 

The exhaust gas must be heated to achieve the temperatures 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-NOx combustion approaches (LNB, combustion modification). Can be used to 

augment LEC. 

Secondary Environmental Impacts: 

Technology also potentially removes 60-80% of particulate 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. “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. 

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 

NOx, TPY 

(WRAP 

1996>100 

TPY) 

%NOx

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 NOx during 

combustion. Simply, this is accomplished by "controlling" 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 diverting 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 location of the OFA ports, the supply of air to the 

OFA (either directly from the windbox, or from a dedicated booster fan). 

NOx Reduction: 

OFA, which can be used separately or as a system with LNBs, is capable of NOx 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 costs (other than the potential 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 technologies 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 industry at present. Plants that have had to comply 

with Title IV of the CAAA of 1992 have largely used these technologies for compliance. Competing 

manufacturers have proprietary designs, geared towards application in different boiler types, as well as 

reflecting their own design philosophies. 

Practical Considerations: 

Boilers with the following design and operating characteristics 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 O2 is 

possible 

• 3-5 percentage points increase in LOI is possible; in general, as higher NOx reduction is 

being sought, the higher the probability for increased LOI (NOx vs. LOI trade-off) 

• Changes in reheat and superheat steam temperatures (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 NOx 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 NOx reduction and fuel efficiency. The concern is exemplified by the typically higher carbon 

levels in the fly ash, which reflect lower combustion efficiency but also the contamination of the fly ash 

itself possibly making it unsuitable for reutilization (e.g., cement industry). 

References: 

EPRI, “Retrofit NOx Control Guidelines for Gas- and Oil-Fired Boilers”, Final Report, December 1993. 

EPRI, “Retrofit NOx Controls for Coal-Fired Utility Boilers – 1996 Update Addendum”, May 1997. 

EPRI, “Retrofit NOx Controls for Coal-Fired Utility Boilers – 2000 Update”, EPRI Final Report, 

December 2000 
C-37 

Process: Oxy-Fuel Firing

Category 

NOx, TPY 

(WRAP 

1996) 

%NOx

reduction Cost, $/ton Status 

Glass Manufacturing 5,033 80-85% 2,150-4,400 Commercial 

Process Description: 

Oxy-fuel melting involves the replacement of the 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 form the combustion atmosphere reduces the volume of 

the waste gases (composed mainly of CO2 and water vapor) by 70-85 % depending on oxygen purity. In 

general, oxy-fuel furnaces have the 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 substantial energy savings because it is not necessary to heat the 

atmospheric nitrogen to the temperature of the flames. The formation of thermal NOx is greatly reduced 

because the main source of nitrogen in the furnace is much lower. 

NOx Reduction: 

Compared to air-fuel fired furnaces, NOx 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 NOx/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 $1,930K-$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 recuperative furnace of comparable pull-rate. 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 with the costs of alternative NO

abatement techniques. 

Development Status: 

Commercially available 

It is estimated that 5-10% of the world’s glass production is made with oxy-fuel melting, but this figure 

varies between the sectors. There are several examples 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 NOx

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. Similar 
C-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 being 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 case to case depending on furnace size and availability of 

pure oxygen. The technique is most effectively installed during furnace rebuild. Hot installation may 

lead to energy savings and to an increased pull rate; however, it is unlikely to result in lower NOx

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 species, cooling is usually by dilution with air. The 

higher temperatures associated with the technique 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 NOx 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 reduces gas flow over the melt and in some cases reduced 

turbulence. 

• Particulate emissions in soda-lime glass can be reduced to 0.2-0.3 kg/ton. 

• Particulate emissions most effectively reduced for boron containing glasses (up to 50%). 

• Reduction in fuel usage leads to lower SO2 emissions for oil-fired furnaces. 

Concentrations of all pollutants may actually be higher due to reduced gas volume, although the absolute 

emission is reduced. Dilution with cooling air usually 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 

NOx, TPY 

(WRAP 

1996) 

%NOx

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, O2 injection is used to improve effectiveness of OFA operation. Small amounts of 

oxygen are introduced into the burner zone through specially designed lances. The added O2 creates a 

local hot spot that increases the rate of coal volatile release, encourages more NOx reduction, and enables 

more fuel-rich operation where less NOx 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, NOx is not reduced but NOx emission rates (lb. 

NOx/ton of clinker) goes down in proportion to the increase in production. O2 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 NOx formation. 

NOx Reduction: 

In the coal-fired boiler demonstration, conventional OFA reduced NOx to around 0.35 to 0.40 lb./MBtu. 

O2 injection lowered the NOx 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. NOx 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% NOx reduction in conjunction with a 0-

5% kiln capacity increase. Increased capacity (when it occurs) is the primary cause of the NOx 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 oxygen 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-fuel 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-rate. 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 with the costs of alternative NOx abatement techniques. 
C-40 

Process: Oxygen-Enhanced Combustion Modifications

Development Status: 

The coal-fired boiler technology needs to be demonstrated 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 case to case depending on furnace size and availability of 

pure oxygen. The technique is most effectively installed during furnace rebuild. Hot installation may 

lead to energy savings and to an increased pull rate; however, it is unlikely to result in lower NOx

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 species, cooling is usually by dilution with air. The 

higher temperatures associated with the technique 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 return 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 O2 is added to an unstaged flame, NOx emissions will increase. The technology can also be combined 

with SNCR or SCR for greater NOx reductions. O2 can also be used with post-combustion NOx 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 reduced gas flow and in some cases reduced turbulence. 

• Particulate emissions in soda-lime glass can be reduced to 0.2-0.3 kg/ton. 

• Particulate emissions most effectively reduced for boron containing glasses (up to 50%). 

• Reduction in fuel usage leads to lower SO2 emissions for oil-fired furnaces. 

Concentrations of all pollutants may actually be higher due to reduced gas volume, although the absolute 

emission is reduced. Dilution with cooling air usually brings the concentrations closer to more normal 

levels. 

References: 

U.S. Environmental Protection Agency, “Alternative Control Techniques Document: NOx Emissions from 
C-41 

Process: Oxygen-Enhanced Combustion Modifications

Utility Boilers”. EPA Document No. EPA-453/R-94-023, July 1994. 

 

Bool, L., “NOx Reduction from a 44MW Wall-Fired Boiler Utilizing Oxygen-enhanced Combustion”, 

EPRI/DOE/EPA Mega Symposium, Washington, May 2003 
C-42 

Process: Pre-Stratified Charge

Category 

NOx, TPY 

(WRAP 

1996>100 

TPY) 

%NOx

reduction Cost, $/ton Status 

Reciprocating Engines 86,210 80-95% <500 Commercial 

Process Description: 

Air is injected into the intake manifold so that during 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 spark plug is very lean, acting a s a heat sink and 

suppressing NOx formation. 

NOx Reduction: 

From tests for ten engine models ranging from 100 to 800 bhp, NOx 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 NOx reductions averaging 77%. 

Vendors guarantee the achievable NOx 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 conjunction with post-combustion technologies. However, the 

overall NOx 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. “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.
C-43 

Process: SCONOx Technology

Category 

NOx, TPY 

(WRAP 

1996>100 

TPY) 

%NOx

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 NOx sorption using a catalyst/sorbent to remove NOx, 

carbon monoxide, and VOC. NOx is oxidized in the presence of a platinum-based catalyst and the 

resulting NO2 is adsorbed onto a potassium carbonate sorbent, forming potassium nitrites. The sorbent 

must be regenerated periodically by passing a controlled 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. 

NOx Reduction: 

The first commercial installation in gas turbines achieved NOx emissions below 2 ppm, a reduction of 

over 90%. 

Vendor testing shows SCONOx reduced NOx emissions in natural gas-fired reciprocating engines up to 

95%. Preliminary testing in diesel engines found the technology reduced NOx by 98.9% to 0.4 g/bhp-hr. 

Cost Information: 

Cost for Gas Turbine application is preliminary and from DOE reference below. 

Development Status: 

Commercially available 

First commercial installations in gas turbines commenced 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 turbines, but variations have been developed for naturalgas and diesel-fired reciprocating engines. 

Regeneration gas flow is about 1 percent 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 NOx reduction. Performance also 

improves as exhaust gas oxygen levels approach zero. Temperature and O2 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 SO2, 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. “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. 

Amar, K.P., Staudt, J. “Status Report on NOx Controls 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 

NOx, TPY 

(WRAP 

1996>100 

TPY) 

%NOx

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 NOx 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 NOx 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 NOx. High temperature catalysts, sometimes used in gas turbine 

applications can operate at temperatures up to ~1100°F 

Conventional SCR incorporates a reactor located typically 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 SCR 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 the flue gas before it enters the SCR. This extra 

equipment makes the capital and energy costs higher than in a conventional SCR. On the other hand, the 

tail-end SCR uses less catalyst, experiences a longer catalyst 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. 

NOx Reduction: 

NOx reductions of 90+% are capable with SCR. NOx reduction levels are typically limited by the need to 

control residual ammonia to low levels (2-5ppm), and by cost effectiveness considerations (higher costto-NOx reduction ratio for deeper reductions. SCR applications typically represent a balance between the 

percentage NOx reduction requirement, residual ammonia limit, SO2 to SO3 oxidation rate, and ability to 

continuously maintain a uniform, stable NH3/NOx distribution across the entry plane into the catalyst. 

Cost Information: 

Capital costs for retrofit SCR systems to power generation sources are mostly within the range of $60/kW 

to about $140/kW. The lower end of this range applies to retrofits with nominal difficulty. The high end 

of the range would typically be associated with retrofits 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 represent over 50,000 MW of installed 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 retrofit 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 

NOx for optimized performance (maximum NOx reduction and minimum NH3 slip) 

• Flue gas pressure drop which is dependent upon flue gas velocity, catalyst configuration, and 

quantity of catalyst required to achieve specified NOx 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 SO3

generated in the furnace when firing sulfur bearing fuels will form ammonium bisulfate/sulfate 

that deposits on the cold end sections of the air heater to cause corrosion and increased pressure 

drop 

• Flue gas contaminants - alkaline compounds, halogens, and heavy metals can cause catalyst 

poisoning. 

• Decreased heat rate at low load if economizer bypass 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 combustion 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, NOx 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 NOx levels entering the SCR system. 

 
C-47 

Process: Selective Catalytic Reduction (SCR)

When combining SCR with NOx control technologies whose performance depends on mixing 

characteristics in the upper furnace (i.e., OFA, reburn, or SNCR), potential stratification of inlet NOx

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 SO3 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 with sulfur and other contaminants-bearing fuels (e.g. 

coal/oil). Applications with natural gas are more benign both with respect to catalyst choice and life, as 

well as other plant impacts. 

References: 

EPRI, “Retrofit NOx Controls for Coal-Fired Utility Boilers – 2000 Update”, EPRI Final Report, 

December 2000 

NESCAUM, “Status Report on NOx Control Technologies and Cost Effectiveness for Utility Boilers”, 

June 1998. 

Cichanowicz, J., “100 GW of SCR: Installation Status and Implications of Operating Performance on 

Compliance Strategies”, EPRI/DOE/EPA Mega Symposium, Washington, May 2003 

McIlvaine, R., “SCR Operating Experience of German Power Plant Owners as Applied to Challenging 

US High Sulfur Service”, EPRI/DOE/EPA Mega Symposium, Washington, May 2003
C-48 

Process: Selective Non-Catalytic Reduction (SNCR)

Category 

NOx, TPY 

(WRAP 

1996>100 

TPY) 

%NOx

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 NOx 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 NOx 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 NOx. 

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 reaction occurs in a somewhat 

uncontrolled fashion (e.g., the existing upper furnace becomes the “reactor”). In practice, this means that 

SNCR has lower capital costs (no need for a reactor/catalyst); higher operating costs (lower efficiency 

means that more reagent is needed to accomplish a given reduction in NOx); and limited NOx reduction 

capability (typically 30%-40%, with some cases achieving reductions in the 50% range). 

With SNCR, the reagent is introduced directly into the upper furnace, within the temperature window 

above. Typical applications may include multiple injection 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. 

NOx Reduction: 

SNCR technology is typically capable of NOx 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 consumption of the chemical reagent – usually urea for SNCR 

- which in turn is dependent upon the efficiency of the as well as the initial NOx level and the desired 

percent reduction. These are typically in the range of $500-$700/ton of NOx. 

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 employed in various industries and applications. Ureabased 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 appropriate distribution and mixing of the reagent 

• Sulfur content of the fuel (SO3 and NH3 form ammonium salts which 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 NOx reduction and ammonia slip) 

 

Compatibility with other air pollution control technologies: 

SNCR applications are compatible with combustion NOx 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, NOx 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 several developments by different companies. Various 

approaches are available commercially. Essentially they all revolve around the ability to combine the 

injection the reburn fuel and the amine reagent in the upper furnace region. NOx 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 NH3

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 SCR. The two most likely to warrant consideration are 

• NH3 slip (emissions and impacts on ash) 

• Formation of nitrous oxide (N2O – 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 NOx Control Technologies and Cost Effectiveness 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 Guidelines for Fossil-Fired Utility Boilers”, May 

1994
C-50 
C-51 

Process: Tempering (Water, air, steam injection)

Category 

NOx, TPY 

(WRAP 

1996>100 

TPY) 

%NOx

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 NOx 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. 

NOx Reduction: 

Controlled NOx 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 are 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 NOx 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 and 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: NOx Emissions from Stationary Gas Turbines. EPA 

Document No. EPA-453/R-93-007, January 1993. 

U.S. Environmental Protection Agency. “Alternative Control Techniques Document – NOx 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 NOx Abatement Industries Perspective,” present at the Council of 

Industrial Boiler Owners, NOx Control XV Conference, Houston, TX, August 2002.
APPENDIX D: PM Control Technology Summaries 
D-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 from gas streams, and belong to the broader family 

of mechanical collectors, which use a variety of mechanical 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 efficiencies 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 flow rate through the cyclone. Cyclones are therefore 

most effective at high boilers loads, where flue gas flow rates are highest, with collection efficiency 

decreasing at lower loads. 

Cost Information: 

The following values represent typical costs for several of these technologies (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 particulate collection applications over the years. In the 

past, industrial plants used mainly cyclones. Cyclones are robust technologies that can deal with the 

cyclic operation and load changes. However, their efficiency is moderate when compared with ESP or 

fabric filtration 

Practical Considerations: 

Cyclones are best suited for applications of relatively large particle sizes as their effectiveness on smaller 

particles is limited 

Cyclones are less expensive than other PM controls 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 and may be desirable in selected applications to 

minimize PM loadings into downstream controls 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.com
D-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 imparting 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 use 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 precipitator, and gas ions subsequently 

ionize particulates. The electric fields impart electrostatic forces to the negatively charged particles, 

“driving” them to the collecting electrodes. Particulates are collected from the electrode plates either by 

mechanical rapping (Dry ESP) or by using a water spray to remove this particulate. (Wet ESP). 

In a typical electrostatic precipitator, collecting plates 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 electrodes 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 collecting 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 removal efficiency. ESP size is an important one. Size 

determines residence time (longer particle residence 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 and 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 both 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 efficiency 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 technologies (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 flow 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 occur during rapping. Proper rapper design and timing will 

minimize rapper re-entrainment. Maintenance of appropriate 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 107

-1010 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 107

 ohm-cm), on the other hand, loose their charge to a collecting 

electrode rapidly and tend not to adhere to the electrode, causing high re-entrainment losses. (Carbon 

black is an example of a low resistivity material). 

Particles with high resistivity (greater than 1010 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 ions into the space between the discharge and collecting 
D-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, SO3 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 Control 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 Particulate 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.com
D-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 baghouses) 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 mechanisms. The dust cake which forms on the filter from the 

collected particulate can contribute significantly to the overall collection efficiency. 

FF types are usually defined by the type of bag cleaning utilized. Major types include: (1) the “reverseair” baghouse, where the flue gas flows upward through 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 off-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) the 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 removed by a reverse pulse of high-pressure air. This 

cleaning does not require isolation of the bags from the flue gas flow, and thus may be done on-line. 

PM Reduction: 

FF’s are capable of 99.9% removal efficiencies. In addition 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 the 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 removal 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 lower 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 started 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 started 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 the particulate loading and characteristics, and the 

cleaning method used. A high particulate loadings will require 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 reverse-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 are also choices for applications downstream of dry 

SO2 controls (e.g. spray dryers) as well as in combination 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 commercial 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 precipitator, or even fully integrated into the last 

field of the existing ESP, further reducing the over cost and space requirements. 

Secondary Environmental Impacts: 

As mentioned above FF’s can represent a complementary 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 needed 

 
D-8 

Process: Fabric Filter

References: 

EPRI, “Economic Evaluation of Particulate Control Technologies”, Final Report, September 1992. 

Staehle, R., “Particulate Control Options for Dry 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 Particulate 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.com
D-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 the liquid waste. For particulate controls the 

“venturi scrubber” is an effective technology whose performance is directly related to the 

pressure loss across the venturi 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 accelerate through a converging 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 based on deign operating conditions and particle 

characteristics. Performance can range 50% for the small size fraction (< 2microns) to over 99% for the 

larger sizes. 

Higher collecting efficiencies and a wider range of particulate sizes, require higher operating pressures. . 

High-energy scrubbers refer to designs operating at pressure 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 technologies (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 require throat velocity compensation to maintain 

specified scrubbing efficiencies, automatic and manually 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 manually controlled throat is generally sufficient. 

Compatibility with other air pollution control technologies: 

Scrubbers are compatible with other 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.com
Appendix A-8 – SO2 Milestones/Backstop Arizona Regional Haze SIP

APPENDIX A-8. SO2 MILESTONES/BACKSTOP

This appendix contains work products and references relied upon 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 Trading 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 facsimile

3622 Lyckan Parkway

Suite 2002

Durham, NC 27707

919-493-3144 telephone

919-493-3182 facsimile

P.O. Box 1575

Shingle Springs, CA 95682

530-672-0441 telephone

530-672-0504 facsimile

MARKET TRADING FORUM

NON-UTILITY SECTOR

ALLOCATION

FINAL REPORT FROM THE

ALLOCATIONS WORKING

GROUP

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. 02.11.001/9422.000

iii

CONTENTS

Page

TABLES ......................................................... ........... v

ACRONYMS AND ABBREVIATIONS .......................................... vii

EXECUTIVE SUMMARY ..................................................... ix

CHAPTER I

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

A. ANALYSIS METHODS ............................................... I-1

CHAPTER II

PETROLEUM REFINING ................................................... II-1

A. SECTOR DESCRIPTION AND SIGNIFICANT SO2 SOURCES ............. II-1

B. FLOOR ALLOCATION ESTIMATION METHODS ....................... II-1

1. Sulfur Recovery Units ........................................... II-1

2. Fuel Gas Combustion Units ...................................... II-2

3. Catalytic Crackers .............................................. II-3

4. Flares ........................................................ II-3

C. FLOOR ALLOCATION RESULTS .................................... II-3

D. COMPARISON WITH HISTORICAL EMISSIONS ...................... II-10

E. EXAMPLE CALCULATION ......................................... II-10

1. Sulfur Recovery Unit ........................................... II-10

2. Fuel Gas Combustion .......................................... II-10

3. Catalytic Crackers ............................................. II-12

4. Flares ....................................................... II-12

CHAPTER III

LIME MANUFACTURING .................................................. III-1

A. SECTOR DESCRIPTION AND SIGNIFICANT SO2 SOURCES ............. III-1

B. FLOOR ALLOCATION ESTIMATION METHODS ....................... III-1

CHAPTER IV

INDUSTRIAL BOILERS AND COGENERATORS ............................... IV-1

A. SECTOR DESCRIPTION AND SIGNIFICANT SO2 SOURCES ............. IV-1

B. FLOOR ALLOCATION ESTIMATION METHODS ....................... IV-1

1. Coal Fired Units ................................................ IV-2

2. Oil Fired Units ................................................. IV-2

C. FLOOR ALLOCATION RESULTS .................................... IV-3

D. COMPARISON WITH HISTORICAL EMISSIONS ....................... IV-3

E. EXAMPLE USE OF CAPACITY UTILIZATION DATA FOR FLOOR

ALLOCATION ESTIMATES ......................................... IV-3

CHAPTER V

PULP AND PAPER INDUSTRY ............................................... V-1

A. SECTOR DESCRIPTION AND SIGNIFICANT SO2 SOURCES .............. V-1

1. Recovery Furnaces ............................................... V-1

2. Lime Kilns ..................................................... V-1

B. FLOOR ALLOCATION ESTIMATION METHODS ........................ V-2

1. Recovery Furnaces ............................................... V-2

2. Lime Kilns ..................................................... V-2

C. FLOOR ALLOCATION RESULTS ..................................... V-2

D. COMPARISON WITH HISTORICAL EMISSIONS ........................ V-4
iv

CONTENTS (continued)

Page

CHAPTER VI

CEMENT MANUFACTURING ............................................... VI-1

A. SECTOR DESCRIPTION AND SIGNIFICANT SO2 SOURCES ............. VI-1

B. FLOOR ALLOCATION ESTIMATION METHODS ....................... VI-1

C. FLOOR ALLOCATION RESULTS .................................... VI-1

D. COMPARISON WITH HISTORICAL EMISSIONS ....................... VI-4

CHAPTER VII

NATURAL GAS PROCESSING PLANTS ..................................... VII-1

A. SECTOR DESCRIPTION AND SIGNIFICANT SO2 SOURCES ............ VII-1

B. FLOOR ALLOCATION ESTIMATION METHODS ...................... VII-1

C. FLOOR ALLOCATION RESULTS ................................... VII-2

1. General Plants ................................................ VII-2

2. Specific Example .............................................. VII-3

D. COMPARISON WITH HISTORICAL EMISSIONS ...................... VII-3

CHAPTER VIII

ELEMENTAL PHOSPHORUS PRODUCTION ............................... VIII-1

A. SECTOR DESCRIPTION AND SIGNIFICANT SO2 SOURCES ........... VIII-1

B. FLOOR ALLOCATION ESTIMATION PROCEDURES ................. VIII-1

CHAPTER IX

GLASS MANUFACTURING ................................................. IX-1

A. SECTOR DESCRIPTION AND SIGNIFICANT SO2 SOURCES ............. IX-1

B. FLOOR ALLOCATION ESTIMATION METHODS ....................... IX-2

CHAPTER X

COPPER SMELTERS ....................................................... X-1

A. SECTOR DESCRIPTION AND SIGNIFICANT SO2 SOURCES .............. X-1

B. FLOOR ALLOCATION ESTIMATION METHODS ........................ X-1

C. COMPARISON WITH HISTORICAL EMISSIONS ........................ X-2

CHAPTER XI

ALUMINUM PRODUCTION ................................................ XI-1

A. SECTOR DESCRIPTION AND SIGNIFICANT SO2 SOURCES ............. XI-1

B. FLOOR ALLOCATION ESTIMATION METHODS ....................... XI-2

CHAPTER XII

SULFURIC ACID PLANTS ................................................. XII-1

A. SECTOR DESCRIPTION AND SIGNIFICANT SO2 SOURCES ............ XII-1

B. FLOOR ALLOCATION ESTIMATION METHODS ...................... XII-2

CHAPTER XIII

METALLURGIC COKE PRODUCTION ..................................... XIII-1

A. SECTOR DESCRIPTION AND SIGNIFICANT SO2 SOURCES ........... XIII-1

1. By Product Coke Ovens ........................................ XIII-1

2. Rotary Calciners .............................................. XIII-1

B. FLOOR ALLOCATION ESTIMATION METHODS ..................... XIII-2

C. COMPARISON WITH HISTORICAL EMISSIONS ..................... XIII-3

CHAPTER XIV

FLOOR ALLOCATION SUMMARY .......................................... XIV-1
v

TABLES

Page

I-1 Methodology for the Calculation of the Floor Allocations for Non-Utility Sources I-3

II-1 Sulfur Plants - Required Minimum SO2

 Emission Reduction Efficiency ...... II-2

II-2 Petroleum Refining Floor Allocation Calculation ......................... II-4

II-3 Petroleum Refineries – Historical Emissions – 1990 to 2000 .............. II-11

III-1 Emission Factors for Lime Manufacturing .............................. III-3

III-2 Lime Manufacturing - Historical Emissions - 1990 to 2000 ................. III-4

IV-1 Assumed Level of Control for SO2 Floor Allocation ....................... IV-2

IV-2 Facility SO2

 Floor Allocation Estimation for ICI Boilers ................... IV-5

IV-3 Comparison of SO2 Floor Allocation with Historical Emissions for ICI Boilers . IV-7

IV-4 Example Use of Capacity Utilization Data for Floor Allocation Estimates .... IV-9

V-1 Facility SO2 Floor Allocation Estimation for Pulp and Paper Facilities

Based on Unit Capacity Values ........................................ V-3

V-2 Facility SO2 Floor Allocation Estimation for Pulp and Paper Facilities

Based on Fuel Throughput ............................................ V-3

V-3 Pulp and Paper - Historical Emissions - 1990 to 2000 ...................... V-5

VI-1 Floor Allocations ................................................... VI-2

VI-2 Cement Manufacturing - Historical Emissions - 1990 to 2000 .............. VI-3

VI-3 Example Calculation ................................................ VI-4

VII-1 Sulfur Plants - Required Minimum SO2

 Emission Reduction Efficiency ..... VII-2

VII-2 Possible Floor - Natural Gas Processing Units .......................... VII-4

VII-3 Oil and Gas Production - Historical Emissions - 1990 to 2000 ............. VII-6

VIII-1 Elemental Phosphorus Production - Historical Emissions - 1990 to 2000 ... VIII-2

IX-1 Glass Manufacturing - Historical Emissions - 1990 to 2000 ................ IX-3

X-1 Copper Smelter SO2 Emission Projections (tpy) ........................... X-2

X-2 Recent Historical Copper Smelter SO2 Emissions ......................... X-3

XI-1 Aluminum Plant Data Used to Estimate Floor Allocations ................. XI-4

XI-2 Aluminum Smelting - Historical Emissions - 1990 to 2000 ................. XI-5

XII-1 Sulfuric Acid Plants ................................................ XII-3

XIII-1 Historical SO2 Emissions at P4 Production, Rock Springs, WY ............ XIII-2

XIII-2 Coking Plant - Historical Emissions - 1990 to 2000 ..................... XIII-3

XIV-1 State/Sector Summary of SO2 Floor Allocations (tons per year) ............ XIV-2

XIV-2 Facility-Level SO2 Floor Allocations - Comparison with Year 2000

SO2 Emissions (tons per year) ........................................ XIV-3
vi
vii

ACRONYMS AND ABBREVIATIONS

BACT Best Available Control Technology

BART Best Available Retrofit Technology

BLS Black liquor solids

CAA Clean Air Act

CWPB center-worked prebake cells

DCE Direct contact evaporator

dscf dry standard cubic foot

ESPs electrostatic precipitators

FCCU fluid catalytic cracking unit

GCVTC Grand Canyon Visibility Transport Commission

H2S hydrogen sulfide

HSS horizontal stud Soderberg

ICI industrial, commercial, and institutional

kg kilogram

LAER Lowest Achievable Emission Reduction

lbs/MMBtu pounds per million British thermal units

Mg megagram

MTF Market Trading Forum

NOxoxides of nitrogen

NSPS New Source Performance Standards

ppm parts per million

ppmv parts per million volume

PTE potential to emit

RECLAIM Regional Clean Air Incentives Market

SCC Source Classification Code

SIC Standard Industrial Classification

SIP State Implementation Plan

SO2sulfur dioxide

SRU Sulfur Recovery Unit

SWPB side-worked prebake cells

tpy tons per year

VSS vertical stud Soderberg

WGA Western Governors’ Association

WRAP Western Regional Air Partnership
viii
ix

EXECUTIVE SUMMARY

This study was performed for a Working Group of the Western Regional Air

Partnerships’ (WRAP) Market Trading Forum. It provides a current, best estimate of the

floor allocation for non-utility sources in the region that would be established if western

States and tribes adopt a regional, backstop trading program for sulfur dioxide (SO2

) to

meet the requirements of Section 309 of the regional haze rule. The major SO2 emitting

non-utility source categories evaluated in this study include the following: petroleum

refineries, lime manufacturing, industrial boilers and co-generators, pulp and paper

manufacturing, cement manufacturing, natural gas processing and oil and gas production,

elemental phosphorus production, glass manufacturing, aluminum smelters, sulfuric acid

plants, and coke production. Of these industry sectors, phosphorus, aluminum smelters,

sulfuric acid plants, and coke production plants were not considered in the original source

categories for the Market Trading Forum. The floor control technology (or emission rate or

SO2 control effectiveness) was determined by evaluating the emissions performance of other

sources in that source category in the western States. The floor is defined to be best

available control technology (BACT), best available retrofit technology (BART), or lowest

achievable emission rate (LAER) for existing sources. For some sources, EPA has not

determined what these levels of emissions are. SO2

 floor allocations were computed for

each of about 200 major non-utility sources in the western States, where major is defined as

those sources emitting greater than 100 tons per year (tpy).

While this analysis uses plant and process-level information to estimate floor

allocations, if the backstop trading program is triggered, SO2

 allowances under the trading

program will be allocated by the participating transport region States and Tribes at that

time. This study is only an approximation of how the allocations might be made based

upon the limited information that we have today. It is expected that the States and Tribes

would be able to obtain more detailed information about current emissions and controls for

these non-utility sources than has been available for the current project.

The floor allocation analysis has been performed separately for each of the 12 major

non-utility source categories in the west. The text below summarizes the key findings for

each source category.

To simplify the analysis, it was determined that California SO2

 sources are already

highly controlled. The California floor allocation of 27,335 tpy is based on the opt-in/out

2018 SO2 allocation that has been estimated previously by the WRAP Market Trading

Forum.

Petroleum Refining: There are ten petroleum refineries outside California in the

WRAP transport region. Data were received from all of these refineries for the allocation

process. These floor allocations were computed for each of the four major SO2 emitting

processes at refineries: sulfur plants, fluidized catalytic cracking units (FCCUs), fuel

combustion units, and flares. The SO2 floor allocation for these ten refineries is 11,418 tpy,

or about 5,400 tpy less than historic emissions during 1996 to 2000. This is one of the best

characterized source categories.

Cement Manufacturing: The control technology analyses for cement kilns showed that

there was no demonstrated SO2 control technique at western State sources that could be

applied to reduce SO2 across the source population. There are widely varying SO2

emissions rates from these kilns, and the process itself removes sulfur from the off gas. As

a result, this sector’s floor allocation of 7,761 tpy was based on recent historic emissions. 

The analysis for lime manufacturing reached the same conclusion as that for cement. The

lime manufacturing floor allocation is 2,103 tpy.
x

Boilers and Co-generators: The floor for boilers and co-generators at industrial

facilities was estimated by applying the equivalent of 85 percent SO2

 control to coal and oilfired sources not already at, or near, this control level. Average capacity factors were used

to estimate boiler utilization for estimating the floor with a 5 percent growth margin. This

assumption is consistent with that used in the utility boiler floor allocations. Some nonutility boilers are operating at low utilization rates. The industrial boiler and cogenerator

floor allocation is 7,910 tpy.

Pulp and Paper Industry: Recovery furnaces and lime kilns are the SO2 sources at the

Kraft pulp mills in the west. Most of these mills are in Oregon. Floor allocations for

recovery furnaces and lime kilns are based on standard U.S. Environmental Protection

Agency (EPA) emission factors and 100 percent capacity utilization (or recent annual

throughput, if capacity estimates were not available). The pulp and paper floor allocation is

7,184 tpy.

Natural Gas Processing Plants and Oil and Gas Production: SO2 emissions from

natural gas processing plants result from combustion of sour gases. It was decided that the

current New Source Performance Standard (NSPS) would serve as the floor. The NSPS

requires a variable sulfur removal efficiency based on the hydrogen sulfide (H2S) content of

the acid gas and the amount of sulfur in the gas. If a facility had current control levels

higher than the assumed floor, the actual average emissions over the past three years were

used to estimate the floor. Since emissions from flaring operations both in the plant and

the well field are not amenable to control, floor emissions are assumed to be the average of

the emissions in three recent years. Data availability was a significant issue in

determining the floor allocations for some gas plants. The floor allocation for this source

category is 28,884 tpy.

Elemental Phosphorus Production: One of the two U.S. elemental phosphorus

production facilities is in Idaho. Because of the uniqueness of this facility, no floor control

technology was identified. The floor allocation is set at year 2000 SO2 emissions, which

were 15,861 tpy. It is expected that the State of Idaho will perform a more detailed

evaluation of this facility during preparation of its regional haze State Implementation

Plan (SIP).

Glass Manufacturing: The major source of SO2 emissions in the glass industry is the

glass melting operation. There are only two active glass manufacturing facilities in the 8

non-California WRAP States. With a lack of information about SO2 control techniques in

practice, the floor allocation for glass manufacturing plants was set according to historical

SO2 emissions. The glass manufacturing floor allocation is 368 tpy.

Copper Smelters: Because of the uniqueness of the existing copper smelters, retrofit

technology analysis must be performed on a smelter-by-smelter basis. A double contact

acid plant is considered the appropriate retrofit control equipment. All copper smelters in

the western States are currently equipped with double contact acid plants. The current

year SO2 allocation for the six copper smelters in the 9-State region is 86,000 tons. This

allocation is reduced to 78,000 tons by 2013 and is the same in 2018.

Aluminum Production: There are only 2 primary aluminum plants in the study region

and both are located in Oregon. The primary SO2 source in aluminum production is the

sulfur in the coke, and the coal tar pitch binder used to produce the anodes. The floor

control technology for aluminum smelters was determined by evaluating the emissions

performance at the two Oregon facilities. One facility uses a wet scrubber to achieve a 70

percent SO2 emission reduction. Therefore, a wet scrubber with a 70 percent SO2 reduction

was selected as the floor technology for aluminum smelters. The aluminum smelter floor

allocation is 2,076 tpy.

Sulfuric Acid Plants: The only significant source of air emissions from a contact

sulfuric acid plant is the tail gas leaving the final absorbing tower. This gas contains small

amounts of SO2 and even smaller amounts of sulfur trioxide, sulfuric vapor, and sulfuric
xi

acid mist. Based on the information available for the 4 sulfuric acid plants in the west, it

was decided that the floor allocation should be estimated by applying the NSPS

requirements to each sulfuric acid plant. Achieving this standard requires a conversion

efficiency of 99.7 percent in an uncontrolled plant, or the equivalent SO2 collection

mechanism in a controlled facility. However, recent historical SO2 emissions for these

facilities were lower than the NSPS emission rate times capacity estimated values, so the

sulfuric acid plant floor was estimated using these historical SO2 emission values. The

resulting floor allocation for these sulfuric acid plants is 5,386 tpy.

Metallurgic Coke Production: SO2 emissions from coke oven operations primarily result

from combustion of the byproduct coal gas in the oven. There were three coke production

facilities operating in the west during the 1990s. Coke production has recently ceased at

two of these facilities. The only facility that continues to operate is a rotary calciner in

Wyoming. Because of the uniqueness of this operation, the floor allocation is based on

recent historic SO2

 emissions, and is 631 tpy.

There are two benchmarks that can be used to put the floor allocations in perspective. 

One is year 2000 historic emissions and the other is the non-utility SO2

 emissions forecast

for 2018. The floor allocation estimate in this report is about 2,500 tons higher than year

2000 historical emissions. However, this comparison of the respective emission totals is

skewed by the fact that year 2000 copper smelter emission were about one-half of the 78

thousand ton allocation for this sector. When copper smelters are removed from the totals,

the floor allocation is about 45 thousand tons lower than year 2000 emissions. A

comparison of the floor allocation with the SO2 emissions in the 2018 opt-in/out emission

allocations shows that the floor allocation is approximately the same.
xii
I-1

CHAPTER I

INTRODUCTION

This report describes an analysis that was prepared for a Working Group of the

Western Regional Air Partnership’s (WRAP) Market Trading Forum (MTF). It provides the

current best estimate of the floor allocation for non-utility sources in the region that would

be established if western States and tribes adopt a regional, backstop trading program for

sulfur dioxide (SO2

) to meet the requirements of Section 309 of the regional haze rule. Note

that this does not establish final allocations for sources in the region. Each State and tribe

will determine the appropriate floor level for sources within their jurisdiction, and will

include this information in their State or tribal implementation plan. The program is

voluntary for western States and tribes. Information is provided to assist eligible States

and tribes evaluate the impacts of the program, but decisions to participate in the program

will be made by each separate jurisdiction.

The distribution of regional SO2 allowances to existing sources in the nine Commission

Transport States is composed of two portions: floor and reducible allocation. There are two

components of the floor allocation - an allocation for the California Regional Clean Air

Incentives Market (RECLAIM) program, and source-specific floor allocations for nonRECLAIM sources. The floor allocation is a minimum allocation for all existing sources,

which will be calculated to ensure that well-controlled sources will receive a full allocation.

California RECLAIM Program: 3,462 SO2

 allowances will be included in the California

budget for RECLAIM sources. These credits will be a subset of the existing source pool for

the State of California and, hence, will not consume any extra credits from the total credit

pool.

Source-specific Floor Allocation: A floor allocation will be calculated for all existing

sources in the region based on some specified level of control (e.g., Best Available Control

Technology [BACT], Best Available Retrofit Technology [BART], Lowest Achievable

Emission Reduction [LAER]) for non-utility sources.

The sources affected by the backstop trading programs are all those stationary sources

in participating States and tribes that emit SO2

 in an amount greater than or equal to 100

tons per year (tpy). The 100 ton cut off will be assessed at the plant level to correspond

with the methodology used in the 1990 emissions inventory. Among the source types

covered by this definition are utility and industrial boilers, refineries, smelters, pulp and

paper mills, cement and lime kilns, and all of the other source categories listed in section

169(g)(7) of the Clean Air Act (CAA).

In this report, the geographic area of analysis is defined to be the nine Commission

Transport Region States, which are Arizona, California, Colorado, Idaho, Nevada, New

Mexico, Oregon, Utah, and Wyoming. Facilities included in the analysis are those that

emitted 100 tpy or more of SO2 sometime during the period 1990 to 2000. Plants that are

electric utilities are excluded from this analysis.

A. ANALYSIS METHODS

The floor allocation analysis for the non-utility sector was performed using the

following steps:

1. It was assumed that the SO2 sources in the State of California are already at the

floor. This is expected because of the stringency of the air emission regulations in

that State.
I-2

2. Because copper smelter allocations for 2018 have already been determined, no

additional analyses were performed for copper smelters. Smelter allocations are

presented in Chapter X.

3. The focus of the analysis was on non-California, non-smelter facilities that had at

least 100 tpy of SO2

 emissions during at least one year in the period 1990 to 2000. 

States included in this analysis were Arizona, Colorado, Idaho, Nevada, New

Mexico, Oregon, Utah, and Wyoming.

4. The major SO2 emitting non-utility source categories evaluated in this study

included the following: petroleum refineries, lime manufacturing, industrial

boilers and co-generators, pulp and paper manufacturing, cement manufacturing,

natural gas processing and oil and gas production, elemental phosphorus

production, glass manufacturing, aluminum smelting, sulfuric acid production, and

metallurgical coke production.

5. The floor control technology or emission rate or SO2 control effectiveness was

determined by evaluating the emissions performance of other sources in that

source category in the western States. The floor is defined to be BACT, BART, or

LAER for existing sources. The floor for each of the major source categories is

summarized in Table I-1.

6. The primary source of emissions information for the western States is the 1996

WRAP point source inventory. The 1996 emission estimates were prepared under

contract to the Western Governors’ Association (WGA) by Pacific Environmental;

Services and Eastern Research Group, Inc. under contract to the WGA (PES,

2001). However, this data set was not sufficient for providing all of the

information needed to compute the floor allocation for each source. The State air

pollution control agencies in each of the 8 States were contacted to obtain

supplementary data. For most source categories, this additional information

included estimates of unit capacities. This could be either the design capacity for

boilers, or the production capacity for industrial processes.

7. Once data was received from the State agencies, it was used to estimate the floor

allocation by source and facility based on the control technologies listed in Table

I-1 and the unit or plant-specific information about existing capacities and SO2

control techniques.

The chapters that follow explain the floor allocation analyses for each of the key

industrial sector source categories in the western United States.
I-3

Table I-1

Methodology for the Calculation of the Floor Allocations for Non-Utility Sources

Source Category Technologies or Standard for Floor

Copper Smelters Due to the uniqueness of the existing smelters, retrofit technology

analysis must be perform ed on a smelter-by-smelter basis. 

Currently, the Hidalgo smelter is the only BART-eligible source on

the list in this category. A double-contact acid plant will be

considered the appropriate retrofit control equipment (all sm elters in

the region are currently equipped with double-contact acid plants). 

On August 21, 2000, New Mexico completed an engineering

analysis that verified earlier determinations by the MTF that the

fugitive SO2 capture system at Hidalgo satisfies BART at 96%

overall capture.

Refineries There are four sources of SO2 emissions at the refinery level. Floor

based upon New Source Perform ance Standards (NSPS) where

applicable.

Description Assumed Average Control Level

Sulfur Recovery Unit (SRU) Meet NSPS Subpart J or the

equivalent of 3-stage Claus units with

a tail gas unit (NSPS and the tail gas

unit does not apply to Claus units

smaller than 20 long tons/day or less).

Fuel gas com bustion units Fix at the NSPS emission limit rate of

0.027 pounds per million British

thermal units (lbs/MMBtu) assuming

fuel gas input and not fuel oil.

Catalytic crackers NSPS (J) selected 9.8 lbs of SO2 per

1,000 lbs of coke burned.

Flares Based upon average of the last 5

years' emission, AP42 factors for

calculated. No additional controls.

Natural Gas Processing Description Assumed Average Level of Control

Process Emissions Reduction to satisfy NSPS. Variable

reduction depending on hydrogen

sulfide (H2S) content and plant size. 

Flaring Based upon average of the last 5

years' emission.

Oil & Gas Production Description Assumed Average Level of Control

Flaring Based upon average of the last 5

years' emission.

Lime Plants No additional reduction. Approximately 50% control inherent in the

process. Additional SO2

 controls are not in place at lime plants in

the western States.
Table I-1 (continued)

Source Category Technologies or Standard for Floor

I-4

Industrial Boilers (Cogens) Technology determination dependent upon current level of control.

Description Assumed Average Level of Control

Uncontrolled Units 85%

Units controlled at less than

70%

Treat as uncontrolled (see above).

Units controlled between

70-80%

Increase reductions by 5% (i.e., if a

unit is at 72%, would be assumed to

control to 77%).

Units controlled greater

than 80%

No additional reductions.

Pulp and Paper Sulfur sources are recovery furnaces and boilers. Boiler discussions

covered with industrial boilers.

Recovery Furnaces: No additional reduction. Low emissions

coupled with lack of more than one example of scrubbing.

Cement Plants No additional reduction. Approximately 70-90 percent control

inherent in the process. Additional SO2 controls are not typically

applied to these levels of processes.

Aluminum Smelters A wet scrubber with a 70 percent SO2

 emission reduction selected

as the floor based on achieved control levels at NW Aluminum in

Oregon.

Sulfuric Acid Plants No additional reduction. Existing units are already controlled to

NSPS levels (4 lbs per ton of 100% acid produced).

Coke Production Only one facility is still operating. Because of the uniqueness of this

rotary calciner, the floor allocation is established at historic SO2

emission levels.
II-1

CHAPTER II

PETROLEUM REFINING

A. SECTOR DESCRIPTION AND SIGNIFICANT SO2 SOURCES

The petroleum refining industry involves numerous processes that convert crude oil

into more than 2,500 products, including gasoline, liquefied petroleum gas, kerosene, jet

fuel, diesel fuel, other fuel oils, lubricating oils, and feed stock for the petrochemical

industry. Petroleum refinery activities include the storage of crude oil at the refinery,

petroleum handling and refining operations, and storage of the refined products prior to

shipment. As of January 1990, there were 189 operating refineries in the United States

with a total crude capacity of 15.4 million barrels per calendar day.

Removal of sulfur from refinery streams is a part of refining. It would be desirable to

remove all sulfur compounds before any crude processing begins, but because this is

impractical, sulfur is removed throughout the refining process. There are several reasons,

besides air pollution control, for removing sulfur from intermediate fractions and products

of crude oil. Sulfur removal reduces corrosion, odor, breakdown frequency, catalyst

poisoning, and gum formation and improves octane rating, color, and lube oil life.

B. FLOOR ALLOCATION ESTIMATION METHODS

There are four possible unit types (SO2 emission points) within a refinery, as noted in

the methodology for the calculation of the floor allocations for non-utility sources. These

four SO2

 sources are: (1) the SRU; (2) fuel gas combustion units; (3) catalytic crackers; and

(4) flares. The approach for estimating SO2 floor allocations is unique for each of these four

SO2 source types within the refinery. Floor calculation methods are presented below for

each of these four source types.

1. Sulfur Recovery Units

Sulfur recovery refers to conversion of H2S to elemental sulfur. H2S is a by product of

processing natural gas and refining high sulfur crude oils. The most common conversion

method used is the Claus process. Approximately 90 to 95 percent of recovered sulfur is

produced by the Claus process. The Claus process typically recovers 95 to 97 percent of the

H2S feed stream.

The average production rate of a sulfur recovery plant in the United States varies from

51 to 203 megagrams (Mg) (56 to 224 tons) per day. Some of the small to mid-sized

refineries in the western States have sulfur plant capacities that are lower than these

average values.

The SO2

 floor allocation for SRUs depends on the size of the sulfur plant. For sulfur

plants of 20 long tons per day or larger, the NSPS require a 3-stage Claus unit with a tail

gas unit. Existing NSPS limit sulfur emissions from Claus sulfur recovery plants of greater

than 20.32 Mg (22.40 tons) per day capacity to 0.025 percent by volume (250 parts per

million volume [ppmv]). The NSPS and tail gas unit do not apply to Claus units smaller

than 20 long tons per day or less. For these smaller sulfur plants, the SO2

 floor allocations

are estimated as 95 percent SO2 control.

Table 8.13-1 in AP-42 provides the following SO2

 emission factors for modified Claus

Recovery Plants:
II-2

Emission Factors for Modified Claus Sulfur Recovery Plants

SO2

 Emissions

Number of 

Catalytic Stages

Average %

Sulfur Recovery

Kilograms (kg)/Mg of

Sulfur Produced

lbs/ton of

Sulfur Produced

1, Uncontrolled 93.5 139 278

3, Uncontrolled 95.5 94 188

4, Uncontrolled 96.5 73 145

2, Controlled 98.6 29 57

3, Controlled 96.8 65 129

The SO2

 emission factor for 99.8 percent sulfur recovery is 8 lbs/ton and for 96.8

percent sulfur recovery is 132 lbs/ton of sulfur produced. This emission factor value is

multiplied by the sulfur plant capacity in tons per day, 365 days per year, and 1 ton per

2,000 lbs to arrive at an annual SO2 emissions floor estimate. Equation (1) below shows the

above description as a formula:

For refineries with sulfur plants smaller than 20 long tons per day, and lower H2S

contents in their acid gas, an SO2

 control level of 96.8 percent may not be achievable. In

that situation, an alternative way to calculate the floor is to use the sulfur feed rate and the

H2S content of the acid gas of the affected facility to compute the appropriate minimum SO2

reduction efficiency using the relationships shown in Table II-1. This table is from the

NSPS for onshore natural gas production.

Table II-1

Sulfur Plants - Required Minimum SO2 Emission Reduction Efficiency

H2S Content of

Acid Gas (Y), %

Sulfur Feed Rate (x), Long Tons per Day

2.0<X<5.0 5.0<X<15.0 15.0<X<300.0 X>300.0

Y>50 74.0

. . . . . . . 85.35X0.0144Y0.0128 . . . . . . .

or 99.8, whichever is smaller

20<Y<50 74.0

. . . . 85.35X0.0144Y0.0128 . . . .

or 97.5, whichever is smaller 97.5

10<Y<20 74.0

85.35X0.0144Y0.0128

or 90.8, whichever is smaller 90.8 90.8

Y<10 74.0 74.0 74.0 74.0

2. Fuel Gas Combustion Units

Fuel gas combustion units in refineries were defined to include all process heaters and

boilers, and their combined oil and gas combustion capacity. SO2

 floor allocations are

estimated as the combined oil and gas combustion capacity multiplied by 0.027 lbs/MMBtu. 

This emission rate is an approximation of the SO2 emission factor for a fuel gas combustion

unit meeting the NSPS of 0.10 grains H2S per dry standard cubic foot (dscf) as required by

40 CFR 60 Subpart J.

This H2S value is converted to an SO2

 emission rate in lbs/MMBtu using the equation

below:
II-3

In the floor allocation estimates for fuel gas combustion units, the fuel gas combustion

capacity is based on reported values for the refineries in Colorado, New Mexico, and Utah

as well as for Wyoming Refining and Frontier Refining in Wyoming. Where this value has

not been reported, it is estimated to be 5 percent of the crude oil processing capacity at that

refinery. The industry norm is reported to be in the range of 5 to 10 percent. The 5 percent

value was used because it is the average value for the western State refineries for which

data on fuel gas combustion capacity were provided.

3. Catalytic Crackers

The SO2

 floor allocation for catalytic crackers at petroleum refineries is computed using

the NSPS for fluid catalytic cracking units (FCCUs). The NSPS for FCCUs without add-on

controls is 9.8 kg SOx per 1,000 kg coke burn-off. For FCCUs without add-on control

devices, EPA decided that the regulated pollutant should be SOx

, because SO3

 could

constitute a significant portion of the total SO2 emissions from FCCUs using SOx reduction

catalysts. The standard for FCCUs without add-on controls requires the use of Method 8 to

determine the total SOx

 emissions from affected facilities.

One of the issues in applying the NSPS emission rate to estimate the SO2

 floor

allocation is the availability of information about the amount of coke burn-off for each

FCCU. The Source Classification Code (SCC) units used in emission inventories, and AP42 SO2

 emission factors, are expressed as lbs/1,000 barrels of fresh feed. Therefore, it is

necessary to develop a conversion factor to go from an emission limit expressed as an SOx

emission rate per 1,000 kg coke burn-off to an emission limit expressed in AP-42 or SCC

units if the coke burn rate is not available for a refinery.

In order to apply the NSPS SO2 emission rate to estimate the floor allocation for

FCCUs, information about the coke burn rate was needed for each refinery. For 10 of the

Western State refineries listed in Table II-1, estimates of the coke burn rate in pounds per

hour were available from a data set that the American Petroleum Institute provided to EPA

as part of the MACT standard setting process. These coke burn rates are based on 1997

operations. For the refineries with FCCUs and no coke burn rate available, the coke burn

rates were estimated using the relationship between the FCCU feed capacity in barrels per

calendar day and the coke burn rate (pounds per hour) for the 10 western refineries with

reported values. The relationship used was 16 pounds coke per barrel of oil. Refineries

where this default value was applied included the two Colorado refineries and Flying J, Inc.

in Utah. Wyoming Refining provided a design coke burn rate for its FCCU.

4. Flares

Flares are commonly used for the disposal of waste gases during process upsets and

emergencies. They are basically safety devices that are also used to destroy organic

constituents in waste emission streams. The AP-42 SO2 emission factor for a vapor

recovery system and flaring is 26.9 lbs per 1,000 barrels refinery feed. This emission factor

is applied to estimate the SO2

 emissions floor for flares at each refinery.

C. FLOOR ALLOCATION RESULTS

Table II-2 includes the floor allocation calculation for the refineries in the 8 nonCalifornia Western Regional Air Partnership (WRAP) States. The Oil & Gas Journal

Worldwide Refining Survey for 2000 provided the values for sulfur plant capacity, catalytic

cracking unit capacity, and crude capacity listed in Table II-2 where they were not

otherwise provided by State air agencies or refinery companies. Fuel gas combustion

capacities in MMBtu/hour (hr) are estimated using information provided by State air

pollution control agencies. Sinclair Corporation provided data for its two Wyoming

refineries (Greene, 2002).
II-4

Table II-2

Petroleum Refining Floor Allocation Calculation

Plant Name City State Source Type Plant/Unit Capa city Capacity Notes

Floor Allocation

Em ission Rate

Emission

Rate Units

Floor allocation

tons/year

Cono co Inc. Co mmerce C ity CO Sulfur R eco very U nit 70 Su lfur plant capacity

tons sulfur per day

8 lbs of SO2 per ton

sulfur produced

102.2

Fuel Gas Combustion

 Gas MMBtu/hr 0.027 lbs of SO2 per

million Btu

112.9

 Oil MMBtu/hr

 Total 955 MMBtu/hr

FCCU 12,666 Coke Burn R ate (lbs/hr) 20 lbs of SO2 per ton

coke burn off

554.8

Flares 57,500 From the December 2000

Oil and Gas Journal

(bbls/cd)

26.9 lbs/1,000 bbl

refinery feed

282.3

All Sources Combined 1,052.2

Colorado Refining Denver CO Sulfur R eco very U nit 4 Su lfur plant capacity

tons sulfur per day

132 lbs of SO2

 per ton

sulfur produced

96.4

Fuel Gas Combustion

 Gas MMBtu/hr 0.027 lbs of SO2

 per

million Btu

60.2

 Oil MMBtu/hr

 Total 509 MMBtu/hr

FCCU 5,333 Coke Burn R ate (lbs/hr) 20 lbs of SO2 per coke

burn off

233.6

Flares 35,000 From the December 2000

Oil and Gas Journal

(bbls/cd)

26.9 lbs/1,000 bbl

refinery feed

171.8

All Sources Combined 562.0

Giant Refining Co. Bloom field NM Sulfur R eco very U nit 2 Su lfur plant capacity

tons sulfur per day

132 lbs of SO2 per ton

sulfur produced

48.2

Fuel Gas Combustion

 Gas 328 MMBtu/hr 0.027 lbs of SO2 per

million Btu

38.8

 Oil MMBtu/hr
Table II-2 (continued)

Plant Name City State Source Type Plant/Unit Capa city Capacity Notes

Floor Allocation

Em ission Rate

Emission

Rate Units

Floor allocation

tons/year

II-5

 Total 328 MMBtu/hr

FCCU 5,400 Coke Burn R ate (lbs/hr) 20 lbs of SO2

 per ton

coke burn off

236.5

Flares 18,500 From the December 2000

Oil and Gas Journal

(bbls/cd)

26.9 lbs/1,000 bbl

refinery feed

90.8

All Sources Combined 414.3

Giant Refining Co. Gallup NM Sulfur R eco very U nit 2 Su lfur plant capacity

tons sulfur per day

132 lbs of SO2 per ton

sulfur produced

48.2

Fuel Gas Combustion

 Gas MMBtu/hr 0.027 lbs of SO2 per

million Btu

37.3

 Oil MMBtu/hr

 Total 315 MMBtu/hr

FCCU 8,200 Coke Burn R ate (lbs/hr) 20 lbs of SO2 per ton

coke burn off

359.2

Flares 32,200 From the December 2000

Oil and Gas Journal

(bbls/cd)

26.9 lbs/1,000 bbl

refinery feed

158.1

All Sources Combined 602.7

Navajo Refining Co. Artesia NM Sulfur R eco very U nit 140 Su lfur plant capacity

tons sulfur per day

8 lbs of SO2 per ton

sulfur produced

204.4

Fuel Gas Combustion

 Gas MMBtu/hr 0.027 lbs of SO2 per

million Btu

109.3

 Oil MMBtu/hr

 Total 924 MMBtu/hr

FCCU 13,000 Coke Burn R ate (lbs/hr) 20 lbs of SO2

 per ton

coke burn off

569.4

Flares 70,000 From the December 2000

Oil and Gas Journal

(bbls/cd)

26.9 lbs/1,000 bbl

refinery feed

343.6
Table II-2 (continued)

Plant Name City State Source Type Plant/Unit Capa city Capacity Notes

Floor Allocation

Em ission Rate

Emission

Rate Units

Floor allocation

tons/year

II-6

All Sources Combined 1,226.7

BP/now Tesoro Petroleum Sa lt Lake City UT Sulfur R eco very U nit 17.4 Su lfur plant capacity

tons sulfur per day

132 lbs of SO2

 per ton

sulfur produced

419.2

Fuel Gas Combustion

 Gas MMBtu/hr 0.027 lbs of SO2 per

million Btu

100.0

 Oil MMBtu/hr

 Total 846 MMBtu/hr

FCCU 14,000 Coke Burn R ate (lbs/hr) 20 lbs of SO2 per ton

coke burn off

613.2

Flares 52,000 From the December 2000

Oil and Gas Journal

(bbls/cd)

26.9 lbs/1,000 bbl

refinery feed

255.3

All Sources Combined 1,387.7

Chevron Products Co. Sa lt Lake City UT Sulfur R eco very U nit 22.4 Su lfur plant capacity

tons sulfur per day

132 lbs of SO2 per ton

sulfur produced

539.6

Fuel Gas Combustion

 Gas MMBtu/hr 0.027 lbs of SO2 per

million Btu

145.9

 Oil MMBtu/hr

 Total 1,234 MMBtu/hr

FCCU 6,500 Coke Burn R ate (lbs/hr) 20 lbs of SO2 per ton

coke burn off

284.7

Flares 55,000 From the December 2000

Oil and Gas Journal

(bbls/cd)

26.9 lbs/1,000 bbl

refinery feed

270.0

All Sources Combined 1,240.3

Silver Eagle Refining Inc. W ood s Cro ss UT Sulfur R eco very U nit 0 Su lfur plant capacity

tons sulfur per day

132 lbs of SO2

 per ton

sulfur produced

0.0

Fuel Gas Combustion

 Gas MMBtu/hr 0.027 lbs of SO2 per

million Btu

15.6
Table II-2 (continued)

Plant Name City State Source Type Plant/Unit Capa city Capacity Notes

Floor Allocation

Em ission Rate

Emission

Rate Units

Floor allocation

tons/year

II-7

 Oil MMBtu/hr

 Total 132 MMBtu/hr

FCCU 0 Coke Burn R ate (lbs/hr) 20 lbs of SO2

 per ton

coke burn off

0.0

Flares 12,500 From the December 2000

Oil and Gas Journal

(bbls/cd)

26.9 lbs/1,000 bbl

refinery feed

61.4

All Sources Combined 77.0

Flying J Inc. Sa lt Lake City UT Sulfur R eco very U nit 7 Su lfur plant capacity

tons sulfur per day

132 lbs of SO2 per ton

sulfur produced

168.6

Fuel Gas Combustion

 Gas MMBtu/hr 0.027 lbs of SO2 per

million Btu

57.8

 Oil MMBtu/hr

 Total 489 MMBtu/hr

FCCU 7,533 Coke Burn R ate (lbs/hr) 20 lbs of SO2 per ton

coke burn

329.9

Flares 24,000 From the December 2000

Oil and Gas Journal

(bbls/cd)

26.9 lbs/1,000 bbl

refinery feed

117.8

All Sources Combined 674.2

Phillips Petroleum Co. W ood s Cro ss UT Sulfur R eco very U nit 14 Su lfur plant capacity

tons sulfur per day

132 lbs of SO2

 per ton

sulfur produced

337.3

Fuel Gas Combustion

 Gas MMBtu/hr 0.027 lbs of SO2 per

million Btu

83.4

 Oil MMBtu/hr

 Total 705 MMBtu/hr

FCCU 5,000 Coke Burn R ate (lbs/hr) 20 lbs of SO2

 per ton

coke burn off

219.0

Flares 25,000 From the December 2000

Oil and Gas Journal

(bbls/cd)

26.9 lbs/1,000 bbl

refinery feed

122.7
Table II-2 (continued)

Plant Name City State Source Type Plant/Unit Capa city Capacity Notes

Floor Allocation

Em ission Rate

Emission

Rate Units

Floor allocation

tons/year

II-8

All Sources Combined 762.4

Frontier Refining Inc. Cheyenne W Y Sulfur R eco very U nit 110 Su lfur plant capacity

tons sulfur per day

8 lbs of SO2 per ton

sulfur produced

160.6

Fuel Gas Combustion

 Gas MMBtu/hr 0.027 lbs of SO2 per

million Btu

155.5

 Oil MMBtu/hr

 Total 1,315 MMBtu/hr

FCCU 7,330 Coke Burn R ate (lbs/hr) 20 lbs of SO2 per ton

coke burn off

321.1

Flares 46,000 From the December 2000

Oil and Gas Journal

(bbls/cd)

26.9 lbs/1,000 bbl

refinery feed

225.8

All Sources Combined 863.0

Sinclair Oil Corp. Casper W Y Sulfur R eco very U nit 21.7 Su lfur plant capacity

tons sulfur per day

132 lbs of SO2 per ton

sulfur produced

522.8

Fuel Gas Combustion

 Gas MMBtu/hr 0.027 lbs of SO2

 per

million Btu

77.1

 Oil MMBtu/hr

 Total 652 MMBtu/hr

FCCU 7,590 Coke Burn R ate (lbs/hr) 20 lbs of SO2

 per ton

coke burn off

332.4

Flares 22,000 Based on 2001

operations (bbls/cd)

26.9 lbs/1,000 bbl

refinery feed

108.0

All Sources Combined 1,040.3

Sinclair Oil Corp. Sinclair W Y Sulfur R eco very U nit 52.6 Su lfur plant capacity

tons sulfur per day

8 lbs of SO2

 per ton

sulfur produced

76.8

Fuel Gas Combustion
Table II-2 (continued)

Plant Name City State Source Type Plant/Unit Capa city Capacity Notes

Floor Allocation

Em ission Rate

Emission

Rate Units

Floor allocation

tons/year

II-9

 Gas MMBtu/hr 0.027 lbs of SO2 per

million Btu

119.9

 Oil MMBtu/hr

 Total 1,014 MMBtu/hr

FCCU 13,120 Coke Burn R ate (lbs/hr) 20 lbs of SO2 per ton

coke burn off

574.7

Flares 60,000 Based on 2001

operations (bbls/cd)

26.9 lbs/1,000 bbl

refinery feed

294.6

All Sources Combined 1,066.0

W yoming Refining Co. Ne wca stle W Y Sulfur R eco very U nit 3 Su lfur plant capacity

tons sulfur per day

132 lbs of SO2 per ton

sulfur produced

72.3

Fuel Gas Combustion

 Gas 0 MMBtu/hr 0.027 lbs of SO2

 per

million Btu

51.6

 Oil 0 MMBtu/hr

 Total 436.6 MMBtu/hr

FCCU 6,028.5 Data provided by

W yoming Refining

(lbs/hr) design coke burn

rate

20 lbs of SO2 per ton

coke burned

264.0

Flares 12,500 From the December 2000

Oil and Gas Journal

(bbls/cd)

26.9 lbs/1,000 bbl

refinery feed

61.4

All Sources Combined 449.3

Total Floor Allocation (CO, NM, UT, WY) 11,418
II-10

D. COMPARISON WITH HISTORICAL EMISSIONS

Table II-3 summarizes historical SO2

 emissions from petroleum refineries located in the

9 WRAP States. California refineries are included in this table. This table provides a point

of comparison with the floor allocations shown in Table II-2.

E. EXAMPLE CALCULATION

This section provides an example calculation of the refinery floor allocation using the

data provided for this project by Wyoming Refining. This refinery is located in Newcastle,

Wyoming. This same information can be found in Table II-2 in condensed form.

1. Sulfur Recovery Unit

The SO2 floor allocation for the SRU is based on the capacity of the unit. Because the

capacity of the Wyoming Refining sulfur plant is less than 20 long tons per day, a sulfur

recovery efficiency of 96.8 percent is applied in the floor calculation. (If the sulfur plant

was larger than 20 long tons per day, a 99.8 percent sulfur recovery value would be

applied.)

The SO2 emission factor for 96.8 percent sulfur recovery is 132 lbs SO2 per ton of sulfur

produced as shown below:

Then, the SO2 floor allocation is the sulfur plant capacity (3 short tons per day) multiplied

by the SO2

 emission factor and 365 days per year, as follows:

2. Fuel Gas Combustion

The SO2 floor allocation for fuel gas combustion is based on the combined boiler and

process heater combustion capacity with each refinery. Wyoming Refining estimates that

its total boiler plus process heater fired duty capacity at the refinery is 436.6 MMBtu per

hour. The SO2 floor allocation is estimated to be the combined oil and gas combustion

capacity multiplied by 0.027

lbs/MMBtu.
II-11

Table II-3

Petroleum Refineries – Historical Emissions – 1990 to 2000

Sta te

Sta te

ID

Co unty

ID

Fac ility

ID

IAS

Region SIC

MTF

Sector Sector Description Facility Name (1990)

Current Facility Name

(if different from 1990)

SO2 tpy

1990

SO2 tpy

1996

SO2 tpy

1998

SO2 tpy

2000

AZ 4 005 0001 42 2911 6 Oil/Gas Intermountain Refining 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. INC (EIS USE) - EL SEGUNDO CHEVRON PRODUCTS CO. 833 1,795 938 1,208

CA 6 013 10 11 2911 6 Oil/Gas CHEVRON USA INC - RICHMOND 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 TION - BEN ICIA 4,922 6,042 5,779 5,779

CA 6 029 37 13 2911 6 Oil/Gas KE RN OIL & R EFININ G C O. 319 425 443 364

CA 6 037 800089 14 2911 6 Oil/Gas MOBIL OIL CORP (EIS USE) - TORRANCE MOBIL OIL CORP (EIS USE) 256 807 725 1,018

CA 6 013 32 11 2911 6 Oil/Gas PACIFIC REFINING COMPANY NOW PLANT ID 11587 278 290 0 0

CA 6 029 25 13 2911 6 Oil/Gas SAN JOAQUIN REFINERY SAN JOAQUIN REFINING COMPANY 337 313 138 0

CA 6 013 11 11 2911 6 Oil/Gas SHELL O IL COMPAN Y - MARTINEZ MARTINEZ REFINING COMPANY 2,790 2,518 2,374 1,159

CA 6 037 800223 14 2911 6 Oil/Gas TEXACO REFINING & MARKETING IN - WILMINGTON 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 REFINERY 7,661 4,459 5,422 5,422

CA 6 037 800026 14 2911 6 Oil/Gas ULTR 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 (NSR USE O TOSCO REFINING COMPANY 724 1,005 806 806

CA 6 079 4 13 2911 6 Oil/Gas UNOCAL CARBON TOSCO SANTA MARIA REFINERY 0 0 0 0

CA 6 079 4 13 2911 6 Oil/Gas UNOCAL CHEM DIV-UNOCAL CORP - ARROYO GR TOSCO 3,034 3,950 0 0

CA 6 013 16 11 2911 6 Oil/Gas UNOCAL CORPORATION - RODEO TOSCO RODEO REFINERY 584 728 675 615

CA 6 037 14 2911 6 Oil/Gas UNOCAL REFINING & MARKETING CO TO SC O R EFININ G (L .A.) 0 343 508 587

CA 6 079 13 13 2911 6 Oil/Gas UNOCAL- SANTA MARIA REFINERY TOSCO SANTA MARIA REFINERY 647 225 3,501 3,727

CA 6 037 800047 14 2911 6 Oil/Gas FLETCHER OIL & REF CO (EIS USE 107 0 0 0

CA 6 037 800184 14 2911 6 Oil/Gas GO LD EN WES T R EF CO (EIS US E) 232 0 0 0

CA 6 037 800103 14 2911 6 Oil/Gas PO WER INE OIL CO (EIS US E) 196 0 1 1

CA 6 037 800115 14 2911 6 Oil/Gas SHELL OIL CO (EIS USE) - CARSON SHELL O IL PRODUC TS 778 0 0 0

CO 8 001 0004 53 2911 6 Oil/Gas COLO REFINING 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 PETROLEUM 157 0 0 0

NM 35 045 0023 60 2911 6 Oil/Gas GIANT INDUSTRIES/BLOOMFIELD REF 676 772 920 920

NM 35 031 0008 61 2911 6 Oil/Gas GIANT REFINING/CINIZA REFINERY 1,346 1,115 1,779 1,779

NM 35 015 0010 65 2911 6 Oil/Gas NAVAJO REFINING/ARTESIA REFINERY 1,549 1,552 969 980

UT 49 035 0004 32 2911 6 Oil/Gas Am oco Pe troleum Produc ts TESORO PETROLEUM 6,701 983 1,116 1,368

UT 49 011 0003 31 2911 6 Oil/Gas Chevron Products Company 2,424 1,116 845 1,242

UT 49 011 0008 31 2911 6 Oil/Gas Flying J Incorporated 312 574 225 300

UT 49 011 0013 31 2911 6 Oil/Gas Phillips 66 Company 5,672 864 862 601

W Y 56 021 0001 9 2911 6 Oil/Gas FRONTIER OIL & REFINING - CHEYENNE 1,521 1,769 1,422 1,396

W Y 56 025 0001 9 2911 6 Oil/Gas LITTLE AMERICA REFINING COMPANY SINCLAIR - CASPER 1,899 1,629 1,305 1,458

W Y 56 007 0011 9 2911 6 Oil/Gas SIN CLAIR @ SIN CLAIR 5,917 3,990 3,524 3,407

W Y 56 045 0001 9 2911 6 Oil/Gas WYOMING REFINING CO WY OMING R EFINING - NEWC ASTLE 630 930 804 876

W Y 56 025 0002 9 2911 6 Oil/Gas AMOCO REFINERY 1,153 0 0 0

Tota ls 61,994 46,721 42,575 42,734
II-12

3. Catalytic Crackers

The SO2

 floor allocation for catalytic crackers is based on the coke burn rate at the

FCCU and the NSPS SO2

 emission rate. The FCCU for Wyoming Refining has a design

feed rate of 5,300 barrels per day, or 6,029 lbs per hour. The NSPS SO2

 emission rate is 20

lbs SO2 per ton coke burn-off.

4. Flares

The SO2 floor allocation for the flares at Wyoming Refining is estimated according to

the total crude processing capacity of the facility. The estimated crude processing capacity

for Wyoming Refining is 12,500 barrels per calendar day. This capacity value is multiplied

by the AP-42 SO2

 emission factor for a vapor recovery system and flaring of 26.9 lbs per

1,000 barrels refinery feed.

REFERENCES

40 CFR Part 60, 2001a: Code of Federal Regulations, “Subpart J - Standards of

Performance for Petroleum Refineries,” (60.100-60.109), 2001.

40 CFR Part 60, 2001b: Code of Federal Regulations, “Subpart LLL - Standards of

Performance for Onshore Natural Gas Processing: SO2

 Emissions,” 2001.

EPA, 1989: U.S. Environmental Protection Agency, “Sulfur Oxides Emissions from Fluid

Catalytic Cracking Unit Regenerators – Background Information for Promulgated

Standards – Final EIS,” EPA-450/3-82-013b, Office of Air Quality Planning and

Standards, Research Triangle Park, NC, April 1989.

EPA, 1993: U.S. Environmental Protection Agency, “Compilation of Air Pollutant Emission

Factors (AP-42), Section 8.13 Sulfur Recovery,” Office of Air Quality Planning and

Standards, Research Triangle Park, NC, 1993.

EPA, 1995: U.S. Environmental Protection Agency, “Compilation of Air Pollutant Emission

Factors (AP-42), Section 5.1 Petroleum Refining,” Office of Air Quality Planning and

Standards, Research Triangle Park, NC, 1995.

Greene, 2002: Letter from Samuel B. Greene, P.E., Sinclair Oil Corporation, Salt Lake City,

UT, to Jim Wilson, E.H. Pechan & Associates, Inc., Springfield, VA, Re: Sinclair Oil

Corporation Western Regional Air Partnership - Market Trading Forum, Non-Utility

SO2

 Floor Allocation Study, Transmittal of Requested Information, September 30, 2002.

Oil & Gas Journal, 2000: Oil & Gas Journal, “2000 Worldwide Refining Survey,” December

18, 2000, Volume 98.51, 2000.
III-1

CHAPTER III

LIME MANUFACTURING

A. SECTOR DESCRIPTION AND SIGNIFICANT SO2 SOURCES

Lime is the high temperature product of the calcination of limestone. Although

limestone deposits are found in every State, only a small portion is pure enough for

industrial lime manufacturing. The Standard Industrial Classification (SIC) code for lime

manufacturing is 3274. The six-digit SCC for lime manufacturing is 3-05-016.

The heart of a lime plant is the kiln. The prevalent type of kiln is the rotary kiln,

accounting for about 90 percent of all U.S. lime production. This kiln is a long, cylindrical,

slightly inclined, refractory-lined furnace, through which the limestone and hot combustion

gases pass concurrently. Coal, oil, and natural gas may all be fired in rotary kilns. Product

coolers and kiln feed preheaters of various types are commonly used to recover heat from

the hot lime product and hot exhaust gases, respectively.

The next most common type of kiln in the United States is the vertical, or shaft, kiln. 

This kiln can be described as an upright heavy steel cylinder lined with refractory material. 

The limestone is charged at the top and is calcined as it descends slowly to discharge at the

bottom of the kiln. A primary advantage of vertical kilns over rotary kilns is higher

average fuel efficiency. The primary disadvantages of vertical kilns are their relatively low

production rates and the fact that coal cannot be used without degrading the quality of the

lime produced. There have been few recent vertical kiln installations in the United States

because of high product quality requirements.

Other, must less common, kiln types include rotary hearth and fluidized bed kilns. 

Both kiln types can achieve high production rates, but neither can operate with coal. The

“calcimatic” kiln, or rotary hearth kiln, is a circular kiln with a slowly revolving doughnutshaped hearth. In fluidized bed kilns, finely divided limestone is brought into contact with

hot combustion air in a turbulent zone, usually above a perforated grate. Because of the

amount of lime carryover into the exhaust gases, dust collection equipment must be

installed on fluidized bed kilns for process economy.

SO2 emissions are influenced by several factors, including the fuel sulfur content, the

sulfur content and numeralogical form (pyrite or gypsum) of the stone feed, the quality of

lime being produced, and the type of kiln. The dominant source of SO2 emissions is the

kiln’s fuel, and the vast majority of the fuel sulfur is not emitted because of reactions with

calcium oxides in the kiln. SO2 emissions may be further reduced if the pollution

equipment uses a wet process or if it brings calcium oxides and SO2 into intimate contact.

Table III-1 provides SO2 emission factors for lime manufacturing. This table shows

that there is a wide range of SO2 emissions performance depending on the kiln type,

pollution control equipment, feedstock, and fuel.

Because of differences in the sulfur content of the raw material and fuel and in process

operations, a mass balance on sulfur may yield a more representative emission factor for a

specific facility than AP-42 emission factors.

B. FLOOR ALLOCATION ESTIMATION METHODS

With the wide range of SO2 emission factors for lime manufacturing, the SO2 control

that is inherent in the lime manufacturing process, and additional controls are not typically

applied to lime plants, the SO2 floor allocation for lime plants will be based on historical
III-2

emissions. The historical emissions for the 1990 to 2000 period are listed in Table III-2. 

The calendar year 2000 SO2

 emission total for lime manufacturing is 2,316 tons.

REFERENCES

AWMA, 2000: Air & Waste Management Association, “Air Pollution Engineering Manual,”

2

nd edition, edited by Wayne T. Davis, 2000.

EPA, 1998: U.S. Environmental Protection Agency, “Compilation of Air Pollutant Emission

Factors, AP-42, Section 11:17: Lime Manufacturing,” Office of Air Quality Planning

and Standards, Research Triangle Park, NC, 1998.
III-3

Table III-1

Emission Factors for Lime Manufacturinga

Source SO2

b Emission Factor Rating

Coal-fired rotary kiln (SCC 3-05-016-18) 5.4 D

Coal-fired rotary kiln with fabric filter (SCC 3-05-016-18) 1.7 D

Coal-fired rotary kiln with wet scrubber (SCC 3-05-016-18) 0.30 D

Gas-fired rotary kiln (SCC 3-05-016-19) ND

Coal- and gas-fired rotary kiln with venturi scrubber

(SCC 3-05-016-20)

ND

Coal- and coke-fired rotary kiln with venturi scrubber

(SCC 3-05-016-21)

ND

Coal-fired rotary preheater kiln with dry PM controls

(SCC 3-05-016-22)

2.3 E

Coal-fired rotary preheater kiln with m ulticlone, water spray,

and fabric filter (SCC 3-05-016-22)

6.4 E

Gas-fired calcimatic kiln (SCC 3-05-016-05) ND

Gas-fired parallel flow regenerative kiln with fabric filter

(SCC 3-05-016-23)

0.0012 D

Product cooler (SCC 3-05-016-11) ND

NOTES: aFactors represent uncontrolled emissions unless otherwise noted. Factors are lbs/ton of lime produced unless

noted. ND = no data. Classification Code.

bMass balance on sulfur may yield a more representative emission factor for a specific facility.
III-4

Table III-2

Lime Manufacturing - Historical Emissions - 1990 to 2000

Sta te

Sta te

ID

Co unty

ID

Fac ility

ID

IAS

Region SIC

MTF

Sector Sector Description Facility Name (1990)

Current Facility Name

(if different from 1990)

SO2 tpy

1990

SO2 tpy

1996

SO2 tpy

1998

SO2 tpy

2000

Floor

Allocation*

AZ 4 025 0011 41 3274 10 Me tals/Min ing/Min erals CHEMICAL LIME (CHEMSTAR) CHEMICAL LIME CO - NELSON

PLANT

141 122 562 702 632

AZ 4 003 0003 47 3274 10 Me tals/Min ing/Min erals CHEMICAL LIME (DOUGLAS) CHEMICAL LIME CO - DOUGLAS

PLANT

212 634 724 742 733

CA 6 053 12 12 3274 10 Me tals/Min ing/Min erals NATIONA L REFRA CTOR IES&MINERALS CHEMICAL LIME CO - NATIVIDAD

PLANT

243 <100 69 82 76

NV 32 003 0003 22 3274 10 Me tals/Min ing/Min erals CHEMSTAR APEX CHEMICAL LIME CO - APEX

PLANT

783 175 210 193

NV 32 007 0261 3274 10 Me tals/Min ing/Min erals CONTINENTAL LIME INC., PILOT PEAK

PLANT

GRAYMONT WESTERN US INC,

PILOT PEAK PLANT

<100 136 235 249 242

UT 49 027 35 3274 10 Me tals/Min ing/Min erals CONTINENTAL LIME INC., CRICKET

MOUNTAIN PLANT

GR AY MO NT W ES TE RN US , INC.,

CRICKET MOUNTAIN PLANT

115 297 275 331 303

Tota ls 1,594 1,289 2,040 2,316 2,179

NOTE: *Based on 1998 and 2000 historical SO2

 emission estimates.
IV-1

CHAPTER IV

INDUSTRIAL BOILERS AND COGENERATORS

A. SECTOR DESCRIPTION AND SIGNIFICANT SO2 SOURCES

Industrial, commercial and institutional (ICI) boilers produce steam or heat water for

use in industrial processes, electrical/mechanical power generation, or space heating. Some

have a dual functionality such as the cogeneration of steam and electricity. Auxiliary

boilers provide backup power and power for startup/shutdown of large units. Large boilers

($150 MMBtu/hr) are generally field-erected units while small boilers are preassembled,

packaged units. The design of an individual ICI boiler is often dependant on the application

of steam and the space limitations in a particular plant.

ICI boilers generate steam at lower temperatures and pressures than utility boilers,

therefore, their heat inputs are smaller. Industrial boilers generally have heat input rates

ranging from 30 to 250 MMBtu/hr, but may be as high as 1,500 MMBtu/hr (EPA, 1994).

Commercial and institutional boilers typically have heat input rates ranging from 0.4 to 12

MMBtu/hr, but may be as high as 100 MMBtu/hr (EPA, 1994). The overall population of ICI

boilers have small heat inputs, with 80 percent of the population operating at less than 5

MMBtu/hr per boiler (STAPPA, 1994). Over 80 percent of the ICI boilers burn oil and gas.

The remaining boilers burn primarily coal, with a small number burning biomass, waste or

other non-fossil fuel. ICI combustion units often burn a mixture of conventional fuels and

biomass or waste. Pulverized coal-fired units account for approximately 1 percent of the

total ICI boiler population. However, they have large heat inputs, greater than 100

MMBtu/hr, therefore, they represent 14 percent of the total ICI boiler capacity. Oil and gas

fired ICI boilers are smaller in size than coal-fired boilers, typically less than 250

MMBtu/hr.

The use of ICI boilers varies with the industrial application. In addition, the

application of steam from an industrial boiler can change with the seasons, and can vary

through the course of a day as well, depending on the processes and activities underway at

a given moment and their demand for steam. Therefore, ICI boilers may have a much lower

annual operating load or capacity factor than a typical utility boiler. 

B. FLOOR ALLOCATION ESTIMATION METHODS

The analysis was limited to facilities which emit greater than 100 tpy of SO2 in total,

and/or individual units which emit greater than 25 tpy of SO2

. In addition, only coal and oil

fired units were analyzed. Auxiliary boilers were included in the floor allocation estimation

if the unit had a potential to emit (PTE) greater than 25 tpy. This includes boilers larger

than 5 MMBtu/hr firing fossil fuel with a sulfur content of 1 percent or more.

The air pollution agencies for each WRAP State provided information for each ICI

boiler being analyzed. This information included the boiler design capacity, annual fuel

consumption for recent calendar years, fuel type (coal or oil), fuel sulfur content, SO2

 control

device information, and the control device SO2

 control efficiency, or permitted SO2

emissions limit for each unit.

The SO2

 floor allocations are calculated for each facility based on the current level of

control. An average level of control is then assumed for each facility, according to Table

IV-1 below:
IV-2

Table IV-1

Assumed Level of Control for SO2

 Floor Allocation

Current Facility Level of Control

Assumed Average Level of Control

for Estimating the Floor

Uncontrolled, 0% 85% Reduction

Units controlled at 0% to <70% 85% Reduction

Units controlled at 70% to 80 % Increase reduction by 5%

Units controlled at 80% or greater No additional reduction

Floor allocations for industrial boilers/cogenerators were also based on the average

capacity utilization during the most recent calendar years. Some States were able to

provide as many as five years worth of boiler utilization data. The recent years of boiler

utilization (fuel consumption) data were used to estimate an average capacity factor for

each unit. This average capacity factor was used, along with a 5 percent margin for growth,

in the SO2

 floor allocation calculation for each boiler/cogenerator.

1. Coal Fired Units

Coal fired units were assumed to fire subbituminous coal with a heating value of 9,000

Btu/lb (18 MMBtu/ton) of coal burned, unless a specific coal type or heating value was

reported (AWMA, 2000). The ICI boilers in the WRAP States were assumed to burn

subbituminous coal since it has a low sulfur content. In addition, a lower grade of

subbituminous coal, class C coal, was assumed to be used for ICI applications. The fuel

sulfur content used to calculate the floor allocation was facility-specific, where available. 

For facilities that did not report sulfur content, an average sulfur content (1 percent) for the

type of coal being fired was used (AWMA, 2000).

The SO2

 emission factor for subbituminous coal fired boilers in pounds of SO2

 emitted

per ton of coal burned is given in AP-42 as:

where S is the percentage sulfur content of the coal burned by each combustion unit (EPA,

1998a).

2. Oil Fired Units

Oil fired units were assumed to have a heating value of 0.15 MMBtu/gal unless a

specific oil type or heating value was reported (AWMA, 2000). The fuel sulfur content used

to calculate the floor allocation was facility-specific. For facilities not reporting sulfur

content, an average sulfur content for the type of oil being fired was used (AWMA, 2000).

The SO2

 emission factor for No. 2 and No. 6 oil fired boilers in pounds of SO2 emitted

per 1,000 gallons of oil burned is given in AP-42 as:

where S is the percentage sulfur content of the oil burned by each combustion unit (EPA

1998b).
IV-3

Units that burn natural gas and oil are assumed to burn natural gas as a primary fuel,

if the emission data indicated SO2

 emission < 5 tpy. If natural gas is the primary fuel, no

allocations are computed.

C. FLOOR ALLOCATION RESULTS

Table IV-2 summarizes the floor allocation calculation for the ICI boilers in the 8 nonCalifornia Western Regional Air Partnership (WRAP) States.

D. COMPARISON WITH HISTORICAL EMISSIONS

Table IV-3 summarizes historical SO2 emissions from industrial boilers located in

Arizona, Colorado, Idaho, Oregon, Utah, and Wyoming. This table provides a point of

comparison with the floor allocations shown in Table IV-2 and historical emissions at each

facility. Note that the historical emissions are the total plant emissions, not just those

resulting from operation of the boiler. In general, boilers which currently have a scrubber

are able to meet their SO2 floor allocations based on historical emissions. 

E. EXAMPLE USE OF CAPACITY UTILIZATION DATA FOR FLOOR ALLOCATION

ESTIMATES

The floor allocation estimation method for boilers and cogenerators takes into account

utilization of these fuel combustion units in the most recent historical years. This section

provides an example of how the capacity factor calculation was performed for one boiler at

Abitibi Consolidated in Arizona.

In order to estimate the average annual capacity factors of each unit, Pechan requested

the actual fuel throughput data for the last 5 years for each boiler. The data was supplied

by the air pollution agencies for each WRAP State. The fuel throughput data supplied by

the Arizona DEQ for Abitibi Consolidated is listed in Table IV-4.

Fuel throughput for all fuel types, coal, oil and natural gas were used to estimate the

annual heat input for each unit using the following equation:

where:

Qannual

= annual heat input for each boiler (MMBtu/yr),

T = throughput for given fuel type, and

HC = heat content for a given fuel type.

Most States did not specify the heat content for each fuel, therefore, the following default

values were used:

Coal Heat content = 18.0 MMBtu/ton

Oil Heat content = 0.15 MMBtu/gal

Natural Gas Heat content = 1,020 MMBtu/MMscf

The boiler design capacity at Abitibi Power boiler #2 is 1,132 MMBtu per hour. In this

exercise, the annual fuel consumption is compared with this boiler design capacity to

estimate the percentage of total capacity that is used in each year. The Arizona DEQ was

able to provide fuel throughput, or fuel consumption, estimates for four calendar years: 

1998 through 2001. This particular unit burns coal and oil, but not natural gas. Fuel

consumption estimates were provided by the State in tons for coal and gallons for oil. The

average heat contents of these two fuels are listed in Table IV-4 and are used to compute an

All Fuels Combined Throughput value in column J. Column K contains the boiler design

capacity value converted to an annual equivalent. The capacity factor for each calendar

year is computed (in column L) as the ratio of column J to column K. For Abitibi Power

boiler #2, these capacity factors range from 60 to 70 percent, with an average capacity
IV-4

factor of 64 percent. The 64 percent average capacity factor value is used in the floor

allocation estimate. (Note that during a leap year (2000), the potential hours of operation

are greater.)

This average capacity factor is used to calculate the SO2 floor allocation. This value is

multiplied by 1.05 to provide some margin for future increases in operations. Only the

primary fuel (coal in this example) is assumed to burned by the boiler in the floor allocation

estimation. The SO2 allocations are calculated using the assumed control efficiency (85

percent) as specified in Table IV-1. The SO2 floor allocation is calculated using the

following equation:

where:

SO2

= SO2 floor allocation (tons/yr),

Qdesign

= annual heat input (MMBtu/yr),

HCprime = heat content of primary fuel (MMBtu/ton, MMBtu/gal), 

EF = SO2 emissions factor (lb/ton, lb/gal),

CF = average capacity factor (%), and

CE = required control efficiency (%).

For Abitibi Power boiler #2, the appropriate values for the above equation are:

Qdesign

= 9,916,320

HCprime = 18

EF = 35

CF = 0.64

CE = 85

As is shown in column P of Table IV-4, the SO2 floor allocation estimate for Abitibi

Power boiler #2 is 978 tpy.

REFERENCES

AWMA, 2000: Air and Waste Management Association, Davis, Wayne T. ed., “Air Pollution

Engineering Manual,” Second Edition, John Wiley and Sons, Inc., New York, 2000.

EPA, 1994: U.S. Environmental Protection Agency, “Alternative Control Techniques

Document – NOx

 Emissions from Industrial/Commercial/Institutional Boilers,” EPA453/R-94-022, Emission Standards Division, Office of Air Quality Planning and

Standards, Research Triangle Park, NC, March 1994.

EPA, 1998a: U.S. Environmental Protection Agency, “Compilation of Air Pollutant

Emission Factors (AP-42), Section 1.1 Bituminous And Subbituminous Coal

Combustion,” Office of Air Quality Planning and Standards, Research Triangle Park,

NC, 1998.

EPA, 1998b: U.S. Environmental Protection Agency, “Compilation of Air Pollutant

Emission Factors (AP-42), Section 1.3 Fuel Oil Combustion,” Office of Air Quality

Planning and Standards, Research Triangle Park, NC, 1998.

STAPPA, 1994: State and Territorial Air Pollution Program Administrators (STAPPA) and

Association of Local Air Pollution Control Officials (ALAPCO), “Controlling Nitrous

Oxides,” July 1994.
IV-5

Table IV-2

Facility SO2 Floor Allocation Estimation for ICI Boilers

Fac ility Un it

Capac ity in

MM Btu/hr Fuel

Sulfur

Content

Current SO2

Co ntrols

Percent

Reduction SO2 Lim it

Average

Capac ity

Factor

(% )

Assumed

 Percent

Reduction

Floor

Allocation

(tpy)

Arizona

Abitibi Consolidated No. 2 Power Boiler 1,132 Coal 1.0 None 0 64 85 978

Colorado

TR IGE N - C olorado E nerg y Corp Boiler #3 225 Coal 0.39 0 43 85

TR IGE N - C olorado E nerg y Corp Boiler #4 360 Coal 0.38 0 62 85

TR IGE N - C olorado E nerg y Corp Boiler #5 650 Coal 0.43 0 59 85 387

Idaho

Amalgamated Sugar, Nampa S-B1 105 Coal 1.0 None 0 34 85

Amalgamated Sugar, Nampa S-B2 105 Coal 1.0 None 0 35 85

Amalgamated Sugar, Nampa S-B3 250 Coal 1.0 None 0 43 85 242

Amalgamated Sugar Company, Paul S-B1 200 Coal 1.0 None 0 35 85

Amalgamated Sugar Company, Paul S-B2 200 Coal 1.0 None 0 23 85 155

Am algam ated Sugar C om pany, T win Falls P-B1 280 Coal 1.0 None 0 30 85

Am algam ated Sugar C om pany, T win Falls P-B2 285 Coal 1.0 None 0 24 85 203

Oregon

Boise Cascade c Power Boiler 6-9 N/A Oil 2.0 No 0 4125 tpy -- 85 411

Amalgamated Sugar B& W Bo ilers 204 Coal 1.5 W et Scrubber 45 200 tpy 12 85

Amalgamated Sugar Foster Riley Boiler 136 Coal 1.5 0 265 tpy 20 85

Amalgamated Sugar Foster W heeler Boiler 300 Coal 1.5 0 775 tpy 21 85 74

Georgia Pacific W est Power Boiler #1 Unknown Oil 2.0 None 0 429.6 tpy -- 85 143

Pope & Talbot Power Boiler #1 Unknown Oil 2.0 None 0 391 tpy -- 85 107

W est Linn Paper Co. Boilers 1 & 2 Oil 2.0 None 0 492.74 tpy 46 85 211

Georgia-Pacific W auna Power Boiler Unknown Oil 2.0 None 0 641.1 tpy -- 85

Georgia-Pacific W auna Package Boiler Unknown Oil 2.0 None 0 0.5 tpy 0 85 277

W eyerh aeu ser Springfield Power Boiler Unknown Oil 2 None 0 590 tpy -- 85

W eyerh aeu ser Springfield Package Boiler Unknown Oil 0.55 None 0 73 tpy -- 85

W eyerh aeu ser Springfield Package Boiler 16 Oil 2 None 0 39 tpy 0 85 362

Utah

Sunnyside Cogeneration Associates FBC Boiler #1 700 Coal 1.0 Scrubber 86 462 lbs/hr 84 86 1,270

Ke nne cott U tah C opp er Corp N . Conce ntator Un it 1 431 Coal 0.68 None a0 1258 tpy 41 85

Ke nne cott U tah C opp er Corp N . Conce ntator Un it 2 431 Coal 0.68 None a

0 1258 tpy 33 85

Ke nne cott U tah C opp er Corp N . Conce ntator Un it 3 431 Coal 0.68 None a0 1258 tpy 28 85

Ke nne cott U tah C opp er Corp N . Conce ntator Un it 4 838 Coal 0.68 None a

0 2445 tpy 39 85 700

Brigh am You ng U niversity Units #2, #3, and #5 128 Coal 0.70 None a0 217 tpy 0 85

Brigh am You ng U niversity Auxiliary #7 5 Oil 1.5 0 6 85 0

Brush Wellman Incorporated S-11 - Main Boiler 81.2 Oil 1.5 None 46 0.85 lb/MB tu 32 85

Brush Wellman Incorporated S-10 Backup Boiler 12.66 Oil 1.5 None 46 0.85 lb/MB tu 19 85 23
Table IV-2 (continued)

Fac ility Un it

Capac ity in

MM Btu/hr Fuel

Sulfur

Content

Current SO2

Co ntrols

Percent

Reduction SO2 Lim it

Average

Capac ity

Factor

(% )

Assumed

 Percent

Reduction

Floor

Allocation

(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 Boiler 5 205 Coal/Gas 1.0 None 0 520.2 tpy 0 96 17

Wyoming

Solvay Minerals, Inc. Boiler #18 350 Coal 0.7 Scrubber 85 0.2 62 85

Solvay Minerals, Inc. Boiler #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-Torrington Plant 221 .2 Coal 0.7 No 0 None 17 85 23

FMC Corp - Green River Plant Boiler #6 887 Coal 0.5 Sc rubb er b0 1.2 70 85

FMC Corp - Green River Plant Boiler #7 887 Coal 0.5 Sc rubb er b0 1.2 70 85 956

University of W yoming Central Heating Plant Boiler #2 73.1 Coal 0.5 No 0 1.2 18 85

University of W yoming Central Heating Plant Boiler #3 73.1 Coal 0.5 No 0 1.2 25 85 22

University of W yoming Central Heating Plant Boiler #4 73.1 Coal 20

FMC Granger Boiler #1 358 Coal 1.0 Scrubber 99 0.2 lb/M Mb tu 48 99

FMC Granger Boiler #2 358 Coal 1.0 Scrubber 99 0.2 lb/M Mb tu 48 99 305

Total Floor Allocation 7,910

NOTES: aNatural gas is fired during winter months per SIP requirements.

bSc rubber is for the entire p lant no t just the b oiler.
IV-7

Table IV-3

Comparison of SO2 Floor Allocation with Historical Emissions for ICI Boilers

Historical SO2 Emissions

Fac ility Un it Capacity (MM Btu/hr) SO2 Floor Allocation (tpy) 199 0 (tpy) 199 6 (tpy) 199 8 (tpy) 200 0 (tpy)

Arizona

Abitibi Consolidated Power Boiler #2 1,132 978 2,455 2,448 1,893

Colorado

TRIGEN - Colorado Energy Corp b Boiler #3 225

TRIGEN - Colorado Energy Corp b Boiler #4 360

TRIGEN - Colorado Energy Corp b Boiler #5 650 387 2,675 3,708 2,583

Idaho

Amalgamated Sugar, Nampa S-B1 105

Amalgamated Sugar, Nampa S-B2 105

Amalgamated Sugar, Nampa S-B3 250 242 1,008 1,660 1,787 1,697

Amalgamated Sugar Company, Paul S-B1 200

Amalgamated Sugar Company, Paul S-B2 200 155 608 306 217 1,322

Am algam ated Sugar C om pany, T win Falls P-B1 280

Am algam ated Sugar C om pany, T win Falls P-B2 268 203 599 1,364 1,053 1,053

Oregon

Boise Cascade c Power Boiler 6-9 N/A 411 2,453 685 746 1,834

Amalgamated Sugar c B& W Bo ilers 204

Amalgamated Sugar c Foster Riley Boiler 136

Amalgamated Sugar c Foster W heeler Boiler 300 74 594 625 1,235 987

Ge orgia Pa cific W est c Power Boiler #1 Unknown 143

Pope & Talbot c Power Boiler #1 Unknown 107 39 161

W est Linn Paper Co. a Boilers 1 & 2 365 211

Georgia-Pacific - Wauna c Power Boiler Unknown

Georgia-Pacific - Wauna c Package Boiler 18 277 254 165

W eyerh aeu ser Springfield Power Boiler Unknown 297

W eyerh aeu ser Springfield Package Boiler Unknown 65

W eyerh aeu ser Springfield Package Boiler 16 0

Utah 

Sunnyside Cogeneration Associates bFBC Boiler #1 700 1,270 0 1,006 970 1,054

Ke nne cott U tah C opp er Corp, N . Conce ntator b Un it 1 431

Ke nne cott U tah C opp er Corp, N . Conce ntator b Un it 2 431

Ke nne cott U tah C opp er Corp, N . Conce ntator b Un it 3 431

Ke nne cott U tah C opp er Corp, N . Conce ntator b Un it 4 838 700 2,905 2,141 2,200 2,534

Brigh am You ng U niversity Units 2, 3, and 5 128

Brigh am You ng U niversity Auxiliary #7 5 0 248 90 158 125

Brush Wellman Incorporated S-11 Main Boiler 81.2

Brush Wellman Incorporated S-10 Back-up Boiler 12.66 23 161 175 208 179
Table IV-3 (continued)

Historical SO2

 Emissions

Fac ility Un it Capacity (MM Btu/hr) SO2

 Floor Allocation (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 inerals, Inc. b Boiler #18 350

So lvay M inerals, Inc. b Boiler #19 350 294 101 72 52

Ge neral C hem ical b Bo iler C 534

Ge neral C hem ical b Bo iler D 880 750 4,196 5,651 4,538 5,000

Ho lly Sugar-Torrington Plant b221 .2 23 374 266 154 178

FM C C orp - G reen Rive r Plan t b Boiler #6 887

FM C C orp - G reen Rive r Plan t b Boiler #7 887 956 4,795 5,256 4,533 4,901

Un iversity of W yom ing C entra l Hea ting Plant a Boiler #2 73.1

Un iversity of W yom ing C entra l Hea ting Plant a Boiler #3 73.1 22 152 154 223 193

Un iversity of W yom ing C entra l Hea ting Plant a Boiler #4 73.1

FMC Granger Boiler #1 358

FMC Granger Boiler #2 358 305 475 473 149 212

NOTES: aFacility with boilers as only SO2 source.

b

Fac ility has m ultiple so urce s, em ission s are total plan t.

c

Facility ha s m ultiple so urces, em issio ns are boile rs on ly.
IV-9

Table IV-4

Example Use of Capacity Utilization Data for Floor Allocation Estimates

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/yr)

Heat

Value

(M M Btu /ft3)

Throughput

All Fuels

Com bined

(MM Btu/yr)

Design

Capac ity

(MM Btu/yr)

Capac ity

Factor

Primary

Fuel Sulfur

Content

(% )

SO2 EF

(lb/ton)

SO2

Reduction

(% )

SO2

Allocation

(tons)

Arizona

Abitibi Consolidated Power Boiler # 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 the an nua l fuel consu m ption in the ca lend ar year.
IV-10
V-1

CHAPTER V

PULP AND PAPER INDUSTRY

A. SECTOR DESCRIPTION AND SIGNIFICANT SO2 SOURCES

The processing of wood for a variety of products is one of the ten largest industries in

the United States. To produce paper or paperboard, wood must be pulped first. In general,

the pulp and paper production processes can be divided into three steps: pulp making, pulp

processing, and paper/paperboard processing. The three basic types of pulping processes,

which are the major sources of SO2

, are chemical pulping, mechanical pulping, and semichemical pulping. Chemical wood pulping involves cooking wood chips or sawdust in an

aqueous chemical solution to dissolve the lignin that binds the cellulose fibers together.

There are two major types of chemical pulping used: Kraft/soda pulping and sulfite

pulping. Kraft pulping accounts for over 80 percent of the chemical pulp produced in the

United States.

Sources of SO2

 in a Kraft mill include: (1) boilers generating steam for power and

heat, using coal, oil, natural gas, or bark/wood waste as fuel; (2) recovery furnaces where

SO2

 emissions occur from the oxidation of reduced sulfur compounds; and (3) lime kilns

when fuel oil is being combusted.

Allocations for boilers are discussed in Chapter IV, "Industrial Boilers and

Cogenerators." Floor allocations for recovery furnaces and lime kilns are described in this

chapter. Note that the calculations for these sources are the same as those for like

configurations set forth in other chapters.

1. Recovery Furnaces

After the cooking period, the pulp and the liquor in which it cooked are separated,

the spent liquor (black liquor) is evaporated and concentrated to about 65 percent solids.

Concentrated black liquor is then sprayed into the furnace and the organic compounds are

combusted. The combustion of black liquor in a recovery furnace results in SO2 emissions

that vary with liquor properties (i.e., sulfidity, heat value), combustion air and liquor firing

patterns, furnace design and operational patterns.

SO2

 reduction is achieved by altering the process, rather than applying control

technology. Strategies to lower liquor sulfidity and optimize combustion and firing patterns

in such way that yields maximum and uniform temperatures in the lower furnace are used

to minimize SO2

 emissions. Flue gas desulfurization is energy intensive and its efficiency

uncertain, considering the generally low concentrations and fluctuating levels of SO2 in the

furnace flue gases.

2. Lime Kilns

In a pulp and paper lime kiln, the inorganic molten smelt that forms and collects at

the bottom of the furnace is withdrawn through spouts into a smelt-dissolving tank where

jets of water are used to quench the molten smelt, forming green liquor. The green liquor is

then combined with quicklime (CaO), resulting in a white liquor solution containing NaOH,

Na2S and lime mud precipitate (mainly CaCO3). This lime mud is washed, dried and

calcined in the lime kiln to regenerate quicklime. The regenerated quicklime in the kiln

acts as an in-situ-scrubbing agent and the Venturi scrubber that usually follows the kiln

further reduces SO2

 levels. Emissions from smelt-dissolving tanks and lime kilns are

generally negligible.
V-2

B. FLOOR ALLOCATION ESTIMATION METHODS

The analysis was limited to pulp and paper facilities that emit greater than 100 tpy

of SO2

 from all processes. There are seven pulp and paper facilities evaluated – six located

in the State of Oregon and one in Idaho. The Oregon Department of Environmental

Quality provided data on the unit capacity for each Oregon facility. However, the data given

were the permitted SO2 emission levels and the design capacity of production of each

recovery furnace or kiln.

Abitibi in Navajo County, Arizona no longer operates a recovery furnace. They are

no longer pulping and have converted to recycled paper processing. Therefore, they receive

no floor allocation for recovery furnace operation.

1. Recovery Furnaces

The floor allocation for recovery furnaces is determined assuming that the process

provides sufficient SO2 reductions. No further SO2 reductions will be required when

estimating the floor allocations. Pechan estimated the floor allocation using the emission

factor given in AP-42 in lbs/air-dried ton of pulp (ADT) and the designed pulp production

capacity. The SO2 floor allocations are given by the equation:

where:

AF = SO2 allocation for recovery furnaces in the facility, and

EFSO2 = AP-42 emission factor = 7 lbs/ADT.

For facilities where pulp production capacity was not given, but fuel throughput was

reported in its place, SO2

 allocations are estimated as the fuel throughput multiplied by the

EPA AP-42 SO2

 emission factor.

2. Lime Kilns

The floor allocation for lime kilns is determined in the same manner as recovery

furnaces. The floor allocation for lime kilns assumes no further SO2 reductions will be

required when estimating the floor allocations. Using the emission factor for lime kilns

given in AP-42, the SO2 floor allocation equation for lime kilns is given by:

where:

AK = SO2

 allocation for lime kilns in the facility, and

EFSO2 = AP-42 emission factor = 0.3 lbs/ADT.

For facilities where pulp production capacity was not given, but fuel throughput was

reported in its place, SO2

 allocations are estimated as the fuel throughput multiplied by the

EPA AP-42 SO2 emission factor.

C. FLOOR ALLOCATION RESULTS

Table V-1 presents the floor allocation calculations for pulp and paper plants in

Oregon based on the permitted capacity of the recovery furnaces and kilns. Unit capacity

values were given in air-dried tons of pulp per day. For the floor calculations, it was

assumed that the furnace was operated 365 days per year at 100 percent capacity.
V-3

Table V-2 presents the floor allocation for facilities where the pulp production

capacity was not given, but fuel throughput was reported instead. The Potlatch facility

listed in Table V-2 is located in Idaho. All other pulp and paper mills listed in Tables V-1

and V-2 are in Oregon. Therefore, the computed floor allocations by State are 1,807 tpy for

Idaho, and 5,377 tpy for Oregon. The California allocation for pulp/paper is based on the

1996, 1998, and 2000 historical SO2

 emissions data in Table V-3, and is 324 tpy.

Table V-1

Facility SO2 Floor Allocation Estimation for Pulp and Paper Facilities

Based on Unit Capacity Values

Facility Unit Capacity* (ADTP/day) SO2 Allocations (tpy)

Boise Cascade Corporation Recovery Furnace#2 450 575

Recovery Furnace#3 700 894

Lime Kiln#4 1,150 63

Georgia-Pacific (W auna Mill) Recovery Furnace 1,015 1,297

Lim e Kiln 1,174 64

W eyerhauser Springfield #3 Recovery Boiler 1,150 760

#4 Recovery Boiler 1,150 790

Lime Kilns 2,156 118

NOTE: *Design and a ctual capacity are unknown, the values given are the permitted levels.

Table V-2

Facility SO2 Floor Allocation Estimation for Pulp and Paper Facilities

Based on Fuel Throughput

Facility Unit Fuel Throughput

SO2 Allocations

(tpy)

Georgia-Pacific West, Inc. Recovery Furnace#1 DCE-BLS 242,725 tpy 129

Nat. gas

Recovery Furnace#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 Furnace#5 BLS 495,000 tpy 235

Nat. gas 350 MMft3 0

No.2 fuel oil 1E06 gal/y 39

Lime Kiln #3 Oil/nat.gas/LPG 1.35E05 ton lime mud/y 36

Pope & Talbot, Inc. Recovery Furnace 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 9
V-4

D. COMPARISON WITH HISTORICAL EMISSIONS

Table V-3 summarizes historical SO2

 emissions from pulp and paper facilities. This

table provides a point of comparison with the floor allocations shown in Tables V-1 and V-2

and historical emissions at each facility. Note that the historical emissions are the total

plant emissions, not just those resulting from operation of the recovery furnace and lime

kiln.

REFERENCES

AWMA, 2000: Air and Waste Management Association, “Air Pollution Engineering

Manual,” 2nd edition, Chapter 18 -Wood Processing Industry, 2000.

EPA, 1998: U.S. Environmental Protection Agency, “Compilation of Air Pollutant Emission

Factors, AP-42, Fifth Edition, Volume I: Stationary Point and Area Source, Section

10.2 Chemical Wood Pulping,” Office of Air Quality Planning and Standards,

Research Triangle Park, NC, 1998.
V-5

Table V-3

Pulp and Paper - Historical Emissions - 1990 to 2000

Sta te

Sta te

ID

Co unty

ID

Fac ility

ID

IAS

Region SIC

MTF

Sector Sector Description Facility Name (1990)

Current Facility Name

(if different from 1990)

SO2

 tpy

1990

SO2

 tpy

1996

SO2

 tpy

1998

SO2

 tpy

2000

AZ 4 017 0007 43 2611 3 W ood/Paper/Pulp STONE CONTAINER ABITIBI 8,536 2,455 2,448 1,893

CA 6 023 21 10 2611 3 W ood/Paper/Pulp SIMPSON PAPER CO MPANY SIMPSON PAPER CO 1,021 315 315

CA 6 089 23 2611 3 W ood/Paper/Pulp SHASTA PAPER-ANDERSON 216

CA 6 013 3257 11 2611 3 W ood/Paper/Pulp GAYLORD CONTAINER CORPORATION 263 0 0

CA 6 023 37 10 2611 3 W ood/Paper/Pulp LO UISIAN A-P AC IFIC C OR P. 302 <100 42 42

CA 6 077 191 11 2621 3 W ood/Paper/Pulp NEW ARK SIERRA PAPERBOARD CORP. 270 0 0

ID 16 045 2611 3 W ood/Paper/Pulp BOISE CASCADE - EMMETT 252

ID 16 069 0001 3 2621 3 W ood/Paper/Pulp POTLATCH 1,379 700 700 1,694

OR 41 009 1849 6 2621 3 W ood/Paper/Pulp Boise Cascade Company 2,453 685 746 1,834

OR 41 041 0005 5 2631 3 W ood/Paper/Pulp Georgia-Pacific W est, Inc. 56 207 322 452

OR 41 019 0036 5 2631 3 W ood/Paper/Pulp International Paper 874 602 1,006 0

OR 41 007 0004 5 2621 3 W ood/Paper/Pulp James R iver II, Inc. Ge orgia- Pacific (W auna Mill) 331 573 617 643

OR 41 043 3501 5 2621 3 W ood/Paper/Pulp Pope & T albot Pulp, Inc. 485 133 92 293

OR 41 071 6142 5 2621 3 W ood/Paper/Pulp Smurfit Newsprint Corporation 2 592 368 461 519

OR 41 043 0471 5 2631 3 W ood/Paper/Pulp W illamette Industries, Inc. 396 54 485 327

OR 41 039 8850 5 2631 3 W ood/Paper/Pulp Collins Products LLC W eyerhaeuser Co. (Particleboard) 202 0 3 1,721

OR 41 047 5398 5 2621 3 W ood/Paper/Pulp Ogden Martin Systems of Marion, Inc. Covanta Marion, Inc. 127 18 22

17,287 6,210 7,259 9,886
V-6
VI-1

CHAPTER VI

CEMENT MANUFACTURING

A. SECTOR DESCRIPTION AND SIGNIFICANT SO2 SOURCES

The cement industry involves the calcining of limestone in clinker and the

subsequent crushing of the clinker into cement. Cement manufacturing activities include

the process the mining and mixture of raw materials such as limestone and other materials,

the pryoprocessing of the raw materials into a clinker, and the grinding of the clinker and

other materials such as silicates into the final cement. As of December 2000, there were

201 kilns with a total capacity of 84 million tpy. The kiln is a predominate source of SO2

emissions. The SO2 emissions result from the combustion of the sulfur in the fuel and the

sulfur (generally in the form of pyrite) that can occur in the feedstock.

Kilns generally take five forms:

! wet (where the feedstock contains up to 43 percent water);

! dry;

! semi-dry;

! dry with a pre-heater;

! and dry with a pre-calciner.

SO2 emissions vary by kiln type generally based on how effectively the kiln type mixes the

SO2 containing gases with the alkaline calcium compounds. The pre-heater and precalciner kilns can remove 90+ percent of the SO2

 in the gas stream while the dry process

kiln removes about 70 percent. In addition, the type of particulate control devices can

impact the amount of SO2

 removed in the process. Fabric filters, both because they mix the

SO2 containing gases with the particles collected on the filter, and because they operate at a

generally lower temperature then electrostatic participators (ESPs), collect more SO2 than

ESPs.

B. FLOOR ALLOCATION ESTIMATION METHODS

Estimation of the floor allocation procedure for the cement industry poses several

difficulties. First, there is no demonstrated control technology for control of SO2

 emissions

from cement kilns. Second, emissions from kilns vary considerably due to numerous

variables including kiln type and sulfur content of feedstock. According to EPA AP-42

emission factors, emissions can vary by as much as a factor of 20. Emission data from two

similar kilns in Utah shows that changes in feedstock can cause a change in emissions up

to a factor of 100. Because of this variability and lack of predictability of emissions, the

floor allocation was based on the average emissions from each plant over the past several

years.

C. FLOOR ALLOCATION RESULTS

Table VI-1 shows the allocation results of the emissions to each plant. As discussed

above, the data are based on the emissions reported in State inventories unless otherwise

indicated (See Table VI-2). Several of the sources added new kilns in the past several

years. For these sources only emission data after the new kiln were included. Permit
VI-2

Table VI-1

Floor Allocations

State Plant Name SO2 Floor Allocation (tpy) State Totals (tpy)

AZ Phoenix Cement

Portland Cement Plant

3201

320

CO Holcim Portland 3,374

CO Holcim Laporte 1,402

CO Cemex 160

4,936

ID Ash Grove Inkom 522

522

NV Nevada Cement 305

NV Royal Cement 1432

448

NM Rio Grande 1,1033

1,103

UT Holcim 2672

267

W Y Centex 1654

165

TOTAL 7,761 7,761

NOTES: 1Pe rmit limited potential to em it.

2Only two years after new kiln included.

3Only one year of data available.

4New kiln in 1997.
VI-3

Table VI-2

Cement Manufacturing - Historical Emissions - 1990 to 2000

Sta te

Sta te

ID

Co unty

ID

Fac ility

ID

IAS

Region SIC

MTF

Sector Sector Description Facility Name (1990)

Current Facility Name

(if different from 1990)

SO2

 tpy

1990

SO2

 tpy

1996

SO2

 tpy

1998

SO2

 tpy

2000

AZ 4 019 3241 4 Ce m ent/C onc rete Arizona Portland 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 POR TLAN D C EM EN T C O. 429 245 245 245

CA 6 029 20 13 3241 4 Ce m ent/C onc rete CALAVERAS CEMENT CO 286 286 286 286

CA 6 085 17 11 3241 4 Ce m ent/C onc rete KAISER CEMENT CORPORATION HANSON PERMANENTE CEMENT 474 464 416 474

CA 6 087 11 11 3241 4 Ce m ent/C onc rete LONE STAR INDUST CEMENT PLANT RMC P ACIFIC MATE RIALS 250 286 393 314

CA 6 071 7000000 15 3241 4 Ce m ent/C onc rete MITSUBISHI CEMENT 28 574 946 298

CA 6 071 1200003 15 3241 4 Ce m ent/C onc rete RIVERSIDE CEMENT COMPANY 0 527 527 164

CA 6 071 100005 15 3241 4 Ce m ent/C onc rete CEMEX-CALIFORNIA CEMENT 0 0 0 427

CA 6 071 15 3241 4 Ce m ent/C onc rete SOUTHW ESTERN PORTLAND CEMENT C SOUTHDOWN-VICTORVILLE PLANT 108 0 0 0

CO 8 069 0002 52 3241 4 Ce m ent/C onc rete HOLNAM LAPORTE HOLC IM 623 623 375 404

CO 8 043 0001 58 3241 4 Ce m ent/C onc rete HOLNAM PORTLAND HOLC 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 FERNLEY PLANT 360 340 346 172

NM 35 001 3241 4 Ce m ent/C onc rete RIO GRANDE PORTLAND CEMENT 0 0 0 1,103

UT 49 029 0001 31 3241 4 Ce m ent/C onc rete Holnam Incorporated HOLC IM 911 3 247 288

9,496 7,533 7,709 9,387
VI-4

limits were selected, since the kiln is under construction and there was no actual emission

data. Table VI-3 provides an example of this calculation.

Table VI-3

Example Calculation

Facility

SO2 tpy

1996

SO2 tpy

1998

SO2 tpy

2000

Floor

Estimate1

Nevada Cement 340 346 172 286

Holcim Laporte 632 375 404 470

1

Floor estimate base d on the average o f these 3 years.

D. COMPARISON WITH HISTORICAL EMISSIONS

Table VI-2 shows a comparison of emissions to the historical emissions based on

State emissions inventories. Since the floor is based on historical emissions, the general

match is very close, but for any individual plant, the floor may be higher or lower than

recent emissions.

REFERENCES

EPA, 1995: U.S. Environmental Protection Agency, “Compilation of Air Pollutant Emission

Factors (AP-42),” Chapter 11.6, Cement Manufacturing, Office of Air Quality

Planning and Standards, Research Triangle Park, NC, 1995.

PCA, 2001: Portland Cement Association, U.S. and Canadian Portland Cement Industry

Plant Information Summary, Data as of December 31, 2000, Portland Cement

Association, Economic Research Department, 2001.
VII-1

CHAPTER VII

NATURAL GAS PROCESSING PLANTS

A. SECTOR DESCRIPTION AND SIGNIFICANT SO2 SOURCES

SO2 emissions from natural gas processing plants result from the combustion of sour

gases. Sour gases may contain less than 1 percent H2S to over 20 percent H2S.

H2S is removed from the natural gas by scrubbing with an amine solution. The

amine solution is heated to regenerate the amine solution. Heating the amine also produces

a very concentrated H2S stream. This H2S stream can be treated to produce sulfur. The

most common treatment is by using a Claus plant. The Claus plant can convert about 80-

98.6 percent of the H2S to sulfur depending on the number of stages and the concentration

of H2S. The average recovery percentage for a 3-stage Claus plant would be about 96

percent, on average. The residual H2S after the Claus plant is either flared or converted to

additional sulfur in a "tail gas" treatment plant like the SCOT or Stretford-Beavon process.

H2S conversion efficiencies of up to 99.9 percent are possible. Residual H2S may be flared.

In addition to the plant tail gas flare, SO2

 emissions also result from upset

conditions at the plant, or in the well field, or emissions when new wells are brought in.

Upsets at the plant cause the sulfur recovery plant to be bypassed and the H2S is flared to

produce SO2

. Upsets in the well field may result in sour natural gas being flared as a safety

precaution to reduce exposure to toxic levels of H2S.

B. FLOOR ALLOCATION ESTIMATION METHODS

The requirements for, and the economics of, sour gas control are a function of a

number of variables, including the amount of H2S in the offgas, the size and age of the

facility, and the air pollution control requirements in existence at the time the facility was

built. Existing sour gas processing plants may have been built in situations where no

regulations existed, under the 1987 NSPS, or under a BACT review under prevention of

significant deterioration regulations.

It was decided that the current NSPS would serve as the floor. The NSPS requires a

variable sulfur removal efficiency based on the H2S content of the acid gas and the amount

of sulfur in the gas. The required emission reduction for each facility was based on the

equations in Table VII-1 since these are the long term reductions called for in the NSPS. If

a facility had current control levels higher than the assumed floor, the actual average

emissions over the past three years were assumed to be the floor. Since emissions from

flaring operations, both in the plant and the well field, are not amenable to control, floor

emissions will be assumed to be the average of three years emissions, whenever the data is

available.
VII-2

Table VII-1

Sulfur Plants - Required Minimum SO2

 Emission Reduction Efficiency

H2S Content of

Acid Gas (Y), %

Sulfur Feed Rate (x), Long Tons per Day

2.0<X<5.0 5.0<X<15.0 15.0<X<300.0 X>300.0

Y>50 74.0 . . . . . . . 85.35X0.0144Y0.0128 . . . . . . .

or 99.8, whichever is smaller

20<Y<50 74.0 . . . . 85.35X0.0144Y0.0128 . . . .

or 97.5, whichever is smaller

97.5

10<Y<20 74.0 85.35X0.0144Y0.0128

or 90.8, whichever is smaller

90.8 90.8

Y<10 74.0 74.0 74.0 74.0

Data availability was a significant issue in determining the floor allocation for some

plants. The data from New Mexico was not adequate to distinguish between process plant,

upset flare, and well field emissions.

C. FLOOR ALLOCATION RESULTS

1. General Plants

Table VII-2 shows the floor allocation calculation for the natural gas processing

plants in the 8 non-California Western Regional Air Partnership (WRAP) States.

In Table VII-2, the plant name and SCC code are those provided in the State

inventory. The emission source column (process or flare) notes whether the emissions are

likely to come from the normal processing of natural gas (process) or the result of upset or

well field emissions (flare). The distinction was made on the basis of comments in the

emission inventory and confirmed in conversations with the State. Current emissions are

based on the average of several years data (2000, 1998, 1996) if available, and on one year's

data if that was all that was available. In some cases, new plants were under construction

and permit levels were used in lieu of actuals. Current reductions were based on data in the

State inventories and confirmed via conversations with State agencies.

Floor emissions vary by the H2S content of the gas, the amount of sulfur produced by

the plant, the age of the plant (older plants are not subject to the NSPS), and State

regulations. In Wyoming, although individual plants vary, the average H2S content of

natural gas is higher than in other States and the degree of control required under the

NSPS is greater. In addition, newer plants tend to be larger and have undergone a BACT

review. In New Mexico, the relatively low H2S content means that less control may be

required under the NSPS. This is due both to the H2S content as well as the small amount

of sulfur produced by the processing plants. However, a State rule (20.2.35 NMAC)

requires a minimum of a 90 percent reduction for plants that release more than 5 tons per

day of sulfur from existing plants regardless of the H2S content of the gas.

The level of control assumed to be the floor will be the most stringent of all of the

potential regulatory requirements. However, the application of the potential floor

procedures can result in no SO2 controls having to be applied on some sources. For

example, the Duke Energy Artesia plant in New Mexico processes less than 2 long tons per

day of sulfur (this is equivalent to about 1,600 tpy of SO2

 emissions) and therefore the

NSPS does not apply. State regulations do not apply, since the sulfur throughput is below

the regulatory threshold. The floor for this plant is based on the average emissions over the

past three years.
VII-3

2. Specific Example

The Burlington Northern Lost Cabin facility in Wyoming provided additional

information needed to demonstrate how the floor calculations could be applied to a specific

facility. The Lost Cabin facility consists of two existing gas processing lines with a capacity

of 133 MMCF/day and has one new train with a capacity of 133 MMCF/day. Both lines

process a gas with a methane concentration of 68 percent, a carbon dioxide concentration of

20 percent, and an H2S content of 12 percent.

Each train is controlled by a three stage Claus unit followed by a SCOT tail gas unit.

The unit is required to have a conversion efficiency of 99.8 percent. Plantwide emissions are

limited to 642 lbs/hr and 1,367 tpy.

The plant underwent a BACT review under PSD and exceeds all requirements of the

NSPS. Under the NSPS, a reduction of 97.5 percent would have been required since the

H2S content of the acid gas stream is 37 percent (which is defined as the gas stream leaving

the amine regenerator and can be calculated as the ratio of the acid gases [H2S and CO2

] in

the input gas stream) and the sulfur production exceeds 300 long tons per day (see Table

VII-1). Since the required reduction exceeds the floor level, the permitted levels represent

the floor.

Since much of the plant is new, no data on upset emissions is available. Emissions

from well-field activities are very variable. Wells are very large at this plant and one very

large well can have up to 1,000 tons of emissions. The plant estimates that annual SO2

emissions of about 500 tpy from well field activities can be expected.

D. COMPARISON WITH HISTORICAL EMISSIONS

Table VII-3 summarizes historical SO2

 emissions from natural gas processing plants

located in the 9 WRAP States. California facilities are included in this table. This table

provides a point of comparison with the floor allocations shown in Table VII-2. For

Wyoming, the historic emissions are close to floor for most sources due to the high level of

control. However, a direct comparison is difficult since the historical emissions may include

well field and upset emissions. Two New Mexico sources will require additional control or

additional emission allocations.
VII-4

Table VII-2

Possible Floor - Natural Gas Processing Units

State Plant SCC

Emission Source

(Process vs Flare) Current % Reduction

Pe rm it

Emissions

Floor

Emission

Reduction

Possible

SO2 Floor

(tpy)

NM Conoco-Maljamar 31000028 Plant 0 3,574 87 222

NM W estern Gas Reso urces 31000208 Plant 90 3,127 90 3,127

NM Agave Energy 31000205 Plant 0 2,983 86.3 365

NM Duke Energy

Eunice

31000208 Plant 90 2,756 90 2,250

NM Duke Energy

Artesia

31000208 Plant 0 1,459 0 1,192

NM Dynergy Midstream

Monument

31000208 Plant 90 1,431 90 675

NM Dynergy Midstream

Sau nders

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 Richardson 31000201 Plant 91.7 1,206 91.7 1,206

NM JL Davis Gas Processing

Denton Plant

31000205 Plant 0 1,158 0 840

NM Marathon 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 Plant

31000208 Plant 96 565 96 431

NM Duke Energy

Bu rton Flats

31000205 Plant 0 246 0 164

NM Duke Energy

Dagger Draw Plant

31000208 Plant 98 243 98 218

NM Duke Energy

Huber Gas Plant

31000205 Unknown 0 231 0 163

UT Tom Brown- Lisbon Plant Plant 95 1,593295 1,593

W Y Ho well Petroleu m - Elk Basin 31000205 Plant 93.5 1,200 93.5 1,200

W Y Burlington Resources

Lost Cabin

Plant 99.8 1,3672

99.8 1,367

W Y Burlington Resources

Lost Cabin

Flare 0 50010 500

W Y KC S M ountain

Ainsworth Flare

31000205 Flare 0 843 0 843

W Y KC S M ountain

Rushm ore Flare

31000205 Flare 0 11810 118

W Y Ma rathon Pitchfork Battery 31000205 Flare 0 6110 61

W Y Exxon Shute Creek 31000205 Plant 99.7 1,206 99.7 1,206

W Y Exxon Shute Creek 31000205 Flare 0 33010 330

W Y Amoco W hitney Canyon 31000205 Plant 99 5,379 99 5,379

W Y Amoco W hitney Canyon 31000205 Flare 0 22310 223

W Y Texaco Byron 31000205 Plant 0 200 0 200
Table VII-2 (continued)

State Plant SCC

Emission Source

(Process vs Flare) Current % Reduction

Pe rm it

Emissions

Floor

Emission

Reduction

Possible

SO2

 Floor

(tpy)

VII-5

W Y Chevron Carter Creek 31000205 Plant 99+ 0

3

0

W Y Chevron C arter Creek 31000205 Flare 0 200 0 200

W Y Hallwood Petroleum

Federal Packsaddle 1-24

31000205 Flare 0 133 0 133

W Y Hallwood Petroleum

Federal Packsaddle 1

31000205 Flare 0 96010 960

W Y Oregon Basin Gas Plant 31000205 Plant 90 391 90 391

W Y KC S Gold Eagle Flare 31000205 Flare 0 790 0 790

W Y Interenergy

Hiland Gas Plant

31000205 Flare 0 2811

0 281

W Y Marathon Oil

Mill Iron

31000205 Flare 0 247 0 247

Em ission Totals 39,606 28,884

NOTES: 1. Only one year of data available; 2. Floor based on permit levels; 3. Plant does not incinerate tail gas - no SO2 emitted; 4. Plant has no emissions listed

for the past three years.

State SO2 floor allocations based o n the e stimates in this tab le are N M (12,862 tpy), UT (1,593 tpy), and W Y (14,42 9 tpy).
VII-6

Table VII-3

Oil and Gas Production - Historical Emissions - 1990 to 2000

Sta te

Sta te

ID

Co unty

ID

Fac ility

ID

IAS

Region SIC

MTF

Sector Sector Description Facility Name (1990)

Current Facility Name

(if different from 1990)

SO2

 tpy

1990

SO2

 tpy

1996

SO2

 tpy

1998

SO2

 tpy

2000

CA 6 029 1141 13 1311 6 Oil/Gas SANTA FE ENE RGY TEXACO CA INC 1,539 855 2,050 2,050

CA 6 029 1129 13 1311 6 Oil/Gas TEXACO EXPLOR & PROD INC 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 INC. - COALINGA 809 0 0

CA 6 029 272 13 1311 6 Oil/Gas M H WHITTIER SENECA RESOURCES 347 0 0

CA 6 053 19 12 1311 6 Oil/Gas MOBIL OIL CORP - SAN ARDO AERA ENERGY 304 0 1 6

CA 6 029 1135 13 1311 6 Oil/Gas SHELL KERNRIDGE AERA ENER GY LLC 294 <100 82 55

CA 6 019 64 12 1311 6 Oil/Gas SHELL WESTERN E&P INC. - COALINGA 144 0 0

CA 6 029 331 13 1311 6 Oil/Gas SW EPI-WEST COAST DIVISION AERA ENER GY LLC 775 <100 10

CA 6 053 30 12 1311 6 Oil/Gas TEXACO INC - SAN ARDO 100 <100 36 32

CA 6 029 299 13 1311 6 Oil/Gas UNOCAL - BAKERSFIELD UNOCAL OIL & GAS DIVISION 159 0 0

CA 6 059 42775 14 1311 6 Oil/Gas W EST NEW PORT OIL 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 PLANT 962 962 962 2,983

NM 35 015 0002 65 1311 6 Oil/Gas ARCO PERMIAN/EMPIRE ABO GAS PLNT 700 565 565 565

NM 35 015 0006 65 1311 6 Oil/Gas GPM GAS/INDIAN HILLS AMINE PLNT 900 450 450 900

NM 35 025 0046 65 1311 6 Oil/Gas GPM GAS/LEE GAS PLANT 818 0 818 818

NM 35 025 0007 65 1311 6 Oil/Gas J.L. DAVIS GAS PROCESS/DENTON 385 890 891 1,158

NM 35 025 0052 65 1311 6 Oil/Gas TEXACO/EUNICE NORTH GAS PLANT 673 1,076 1,346 673

NM 35 025 0051 65 1311 6 Oil/Gas TEXACO/EUNICE SOUTH GAS PLANT 4,019 4,386 3,355 5,476

NM 35 015 0003 65 1311 6 Oil/Gas TRANSWESTERN PIPE DUKE ENERGY/HUBER GAS 221 231 231 231

NM 35 041 0001 63 1311 6 Oil/Gas W ARREN PETROLEUM/BLUITT GAS PLANT 270 3,348 582 270

NM 35 025 0061 65 1311 6 Oil/Gas W ARREN PETROLEUM/MONUMENT PLANT MONUMENT PLANT 1,460 1,709 1,432 1,432

NM 35 045 0247 60 1311 6 Oil/Gas W ESTERN GAS PROCESSORS/SAN JUAN RVR 5,475 980 980 3,138

NM 35 025 0128 65 1311 6 Oil/Gas CITATION/ANTELOPE 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 PETROLEUM/PATHFINDER AMINE 227 57 57
Table VII-3 (continued)

Sta te

Sta te

ID

Co unty

ID

Fac ility

ID

IAS

Region SIC

MTF

Sector Sector Description Facility Name (1990)

Current Facility Name

(if different from 1990)

SO2 tpy

1990

SO2 tpy

1996

SO2 tpy

1998

SO2 tpy

2000

VII-7

UT 49 037 35 1311 6 Oil/Gas UNOCAL CORPORATION TOM BROWN - LISBON PLANT 1,575 1,391 1,478 1,252

W Y 56 029 0012 9 1311 6 Oil/Gas AM OCO - ELK BA SIN HOW EL L PET ROLE UM - ELK B AS IN 1,096 1,218 1,422 2,638

W Y 56 041 0012 9 1311 6 Oil/Gas AMOCO - WHITNEY CANYON 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 EXXON - 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 - AINSW ORTH 807 845 0

W Y 56 029 0007 9 1311 6 Oil/Gas MA RAT HON GAS PLAN T - OREG ON BA SIN 406 456 388 358

W Y 56 017 9 1311 6 Oil/Gas MARATHON OIL - MILL IRON 234 260 0

W Y 56 003 0012 9 1311 6 Oil/Gas TEXAS-BYRON PLANT BIG HORN GAS PROCESSING - BYRON 192 169 605 257

W Y 56 037 0008 9 1311 6 Oil/Gas UNION PAC - BRADY RME PETRO LEUM - BRADY 415 331 576 300

W Y 56 013 008 9 1311 6 Oil/Gas DEVON SFS OPERATING CO. BEAVER CREEK 831

W Y 56 037 0014 9 1311 6 Oil/Gas COLORADO INTERSTATE GAS - TABLE ROCK 522 20 39

W Y 56 003 0013 9 1311 6 Oil/Gas MARATHON OIL COMPANY - GARLAND 257 7 10

W Y 56 013 9 1311 6 Oil/Gas LO UISIA NA LAN D & E XPLO R - LO ST CA BIN BU RLIN GTO N RE SO URCES -LO ST CA BIN 4,547 1,336 1,700

36,111 34,735 38,346 37,749
VII-8
VIII-1

CHAPTER VIII

ELEMENTAL PHOSPHORUS PRODUCTION

A. SECTOR DESCRIPTION AND SIGNIFICANT SO2 SOURCES

P4 Production has an elemental phosphorus facility near Soda Springs, Idaho. This

is one of the two elemental phosphorus production facilities in the United States. Year

2000 SO2 emissions from this facility are estimated to be 15,861 tpy. This reflects increased

utilization compared with 1996 and 1998 operations. This facility has no SO2 emissions

limit in its operating permit. The Idaho Department of Environmental Quality is currently

evaluating this facility’s SO2 emissions situation. For the purposes of this report, the floor

allocation for P4 Production is set at its year 2000 SO2 emissions level of 15,861 tons. It is

expected that the State of Idaho will perform a more detailed evaluation of this facility

during preparation of its regional haze State Implementation Plan (SIP).

B. FLOOR ALLOCATION ESTIMATION PROCEDURES

Recent historical emissions for P4 Production are listed below in Table VIII-1.
VIII-2

Table VIII-1

Elemental Phosphorus Production - Historical Emissions - 1990 to 2000

Sta te

Sta te

ID

Co unty

ID

Fac ility

ID

IAS

Region SIC

MTF

Sector Sector Description Facility Name (1990)

Current Facility Name

(if different from 1990)

SO2

 tpy

1990

SO2

 tpy

1996

SO2

 tpy

1998

SO2

 tpy

2000

ID 16 029 0001 7 2819 5 Chem icals/Plastics MONSANTO/P4 PRODUCTION P4 PRODUCTION 7,543 7,988 7,601 15,861
IX-1

CHAPTER IX

GLASS MANUFACTURING

A. SECTOR DESCRIPTION AND SIGNIFICANT SO2 SOURCES

The air emissions from glass manufacturing are in three zones: (1) raw material

blending and transport, (2) melting, and (3) forming and finishing. The majority of air

emissions are in the melting furnace operation.

Melting for container and flat glass is generally conducted in a continuous

reverbatory furnace fired by natural gas or oil. Electric boost furnaces have been

introduced in some operations to minimize flue gas emissions.

The major source of SO2 emissions in the glass industry is the glass melting

operation. Forming and annealing operations are minor sources. Furnace emissions

appear to be attributable to both the manufacturing process and the fuel burned. Fuelderived SO2

 emissions are lower from natural gas-fired furnaces than from oil-fired

furnaces, unless the oil has been desulfurized. Flue gases from furnaces burning natural

gas have been reported to contain 2 parts per million (ppm) SO2

, or less. About 600 ppm

SO2

 can be expected in flue gas from a furnace burning fuel oil containing one percent

sulfur. Greater use of electric furnaces or electric boosting may decrease SO2

 emissions.

Process modifications that may reduce SO2 emissions include altering the raw

material charge to reduce the sulfur content or to increase the fraction of recycled glass,

changing the furnace controls or equipment, and altering the pull rate. Process

modifications that reduce the salt cake content in the raw batch can significantly reduce

SO2

 emissions. For example, one California flat-glass plant reportedly reduced furnace

emissions of SO2 by 78 percent from 2.1 to 0.5 kilograms per megagram (kg/Mg) (5.0 to 1.1

lbs/ton) by reducing the salt cake in the raw batch 60 percent (from 12 to 5 kg/Mg, 30 to 12

lbs/ton of sand). Similarly, another California flat-glass plant has reportedly reduced its

SO2 emissions 75 percent (from 1.6 to less than 0.4 kg/Mg, 4 to less than 1 lbs/ton of batch

constituents) by reducing the input of salt cake. Glass quality was not compromised in

either case. The salt cake cannot be reduced below certain minimums without effecting

glass quality. The minimum salt cake required varies depending upon furnace type, pull

rate, glass type, and other variables.

Fuel changes have also been shown to reduce SO2 emissions. These include

switching to natural gas or low-sulfur fuel oil, switching to all-electric melting, and using

electric boosting for melting. Electric melters significantly reduce SO2, NOx, and

particulate emissions because they eliminate the combustion of fossil fuels. Electric

melting also is reported to minimize SO2 and other gaseous losses from the vaporization of

raw materials because the surface of the melt is insulated by a semisolid crust. Gases

discharged through the crust of the melt consist mainly of carbon dioxide and water. 

Today, borosilicate, opal, and green glass are produced with electric furnaces. The

capacities of such furnaces are about 100 to 110 Mg/day (110 to 120 tons/day). Electric

melters have not been demonstrated for larger operations, such as large container furnaces,

the nominal capacities of which are about 220 Mg/day (240 tons/day), and flat-glass

furnaces, which range from about 600 to 800 Mg/day (660 to 880 tons/day).

Several emission control systems that are available to the glass industry for

particulate control are also capable of achieving various levels of secondary SO2 control. 

For example, a venturi scrubber system can control SO2 emissions from commercial glass

plants. The system includes a packed tower where part of the sulfate particulates are

removed from the hot furnace flue gases, a dual-throat venture scrubber, where SO2 and
IX-2

additional particulates are removed by alkaline washing, and a cyclone for final particulate

collection. Currently, only the container glass segment of the glass industry is reported to

use scrubber systems for emission control.

Injecting a sorbent such as alumina, limestone, or nepheline syenite into a fabric

filter system can effectively remove SO2

 from furnace flue gases. The spent sorbent may be

landfilled or possibly recycled.

One patented system of dry removal involves the combined use of hydrated lime and

nepheline syenite for acid gas neutralization and fine particle agglomeration. In this

system, hot furnace flue gas is first mixed with quench water, hydrated lime for primary

SO2

 removal, and secondary air to cool the gas stream to a temperature range of 94o to

427oC (200o

 to 800oF). Next, nepheline syenite is added to the gas stream to capture

residual SO2 and submicrometer particulates. The gas stream enters the fabric filter where

the solid product is removed for either recycling to the furnace or landfilling.

Dry sorbent systems at several commercial glass furnaces reduced SO2 by 80 to 95

percent at a container glass furnace, 50 to 90 percent at a fiberglass furnace, and 88 to 98

percent at a flat-glass furnace.

Mist eliminators apparently have no effect on SOx gases. One sampling test

indicated no decrease in SO2 and SO3 concentrations through the control device (EPA,

1981).

B. FLOOR ALLOCATION ESTIMATION METHODS

It is expected that the floor allocation for glass manufacturing plants will be set

according to recent historical SO2 emissions from these facilities. These SO2 emissions are

listed in Table IX-1.

REFERENCES

AWMA, 2000: Air and Waste Management Association, “Air Pollution Engineering

Manual,” 2nd edition, Chapter 15 - Mineral Products Industry, 2000.

EPA, 1981: U.S. Environmental Protection Agency, “Control Techniques for Sulfur Oxide

Emissions from Stationary Sources,” Second Edition, EPA-450/3-81-004, Office of Air

Quality Planning and Standards, Research Triangle Park, NC, April 1981.
IX-3

Table IX-1

Glass Manufacturing - Historical Emissions - 1990 to 2000

Sta te

Sta te

ID

Co unty

ID

Fac ility

ID

IAS

Region SIC

MTF

Sector Sector Description Facility Name (1990)

Current Facility Name

(if different from 1990)

SO2

 tpy

1990

SO2

 tpy

1996

SO2

 tpy

1998

SO2

 tpy

2000

Floor

Allocation

CA 6 037 106797 14 3221 8 Glass BALL-FOSTER GLASS CONTAINER CO SAINT-GOBAIN CONTAINER <100 <100 166 174

CA 6 099 1662 11 3221 8 Glass GALLO GLASS 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 ILLINOIS OW ENS-BROCKWAY GLASS CONTAINER 319 285 218 248

CA 6 037 7427 14 3221 8 Glass OWENS-BROCKWAY GLASS CONTAINER - VERNON 193 323 280 435

CA 6 001 2086 11 3221 8 Glass ANCHOR GLASS CONTAINER CORPORA 119 0 0

CA 6 001 30 11 3221 8 Glass OW ENS-BROCKWAY GLASS CONTAINER - 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, Inc. 103 169 116 108 131

1,284 1,667 1,537 1,821
IX-4
X-1

CHAPTER X

COPPER SMELTERS

A. SECTOR DESCRIPTION AND SIGNIFICANT SO2 SOURCES

Primary copper smelters in the WRAP States process copper sulfide ore concentrate

to produce anode copper. There are six primary copper smelters in the WRAP region. Five

of the primary copper smelters are near the copper mines in the southwest United States. 

These smelters use a batch copper converting process (either Pierce-Smith or Hoboken

converter designs) to produce blister copper. Currently, only two of these smelters are

producing copper (the ASARCO smelter in Hayden, Arizona and the Phelps Dodge smelter

in Miami, Arizona). The other three smelters have suspended operations and are not

producing copper at this time.

The sixth primary copper smelter in the WRAP States is the Kennecott Utah Copper

Corporation near Garfield, Utah. The Kennecott smelter was built during the mid-1990s

(replacing the existing smelter at the site) and uses a flash copper converting technology. 

This technology allows blister copper to be produced in a continuous process.

All primary copper smelters in the region control SO2

 emissions by routing the

process off-gases from the smelting and converting processes to double contact sulfuric acid

plants.

B. FLOOR ALLOCATION ESTIMATION METHODS

Because of the uniqueness of the existing copper smelters, retrofit technology

analysis must be performed on a smelter-by-smelter basis. Currently, the Hidalgo smelter

is the only BART-eligible source in this category. A double contact acid plant is considered

the appropriate retrofit control equipment (all smelters in the western States are currently

equipped with double contact acid plants). On August 21, 2000, New Mexico completed an

engineering analysis that verified earlier determinations by the MTF that the fugitive SO2

capture system at Hidalgo satisfies BART at 96 percent overall SO2 capture.

The Annex to the Grand Canyon Visibility Transport Commission’s (GCVTC)

recommendations defines stepped reduction milestones through 2018 for SO2

 emissions

from large industrial sources in the 9-State Commission Transport Region. The current

year SO2 allocation for the six copper smelters in the 9-State region is 86,000 tons. This

allocation is reduced to 78,000 tons by 2013 and is the same in 2018. For the recent

Emission Forecasts to 2018 analysis, the plant-level difference SO2

 emissions difference

between 86,000 tons and 78,000 tons was simulated by subtracting 2,000 tons each from

the four largest smelters, which are ASARCO-Hayden, BHP-San Manuel, Phelps-Dodge

Chino Mines, and Phelps Dodge-Hidalgo. The resulting allocations of 2018 SO2

 emissions

by facility are shown in Table X-1. Note that the 78,000 tons of SO2

 allocation for copper

smelters is an aggregate value for the region, rather than a requirement for each smelter to

reduce emissions to prescribed levels. Table X-1 illustrates one way that this regional

allocation might be met. Many other examples are provided in the EPA regional haze rule.
X-2

Table X-1

Copper Smelter SO2 Emission Projections (tpy)

State Facility Name 2018

AZ ASARCO Smelter-Hayden 21,000

AZ BHP-San Manuel 14,000

AZ Cyprus Miami Mine 8,000

NM Phelps Dodge-Chino Mines 14,000

NM Phelps Dodge-Hidalgo Smelter 20,000

UT Kennecott Utah Copper Corp. 1,000

Total Copper Smelter 78,000

C. COMPARISON WITH HISTORICAL EMISSIONS

Table X-1 SO2

 emission estimates can be compared with recent historical (1990 to

2000) emissions for those smelters shown in Table X-2.
X-3

Table X-2

Recent Historical Copper Smelter SO2 Emissions

State

State

ID

County

ID

Fac ility

ID

IAS

Region SIC

MTF

Sector Sector Description Facility Name (1990)

Current Facility Name

(if different from 1990)

SO2 tpy

1990

SO2 tpy

1996

SO2 tpy

1998

SO2 tpy

2000

Smelter Sector

AZ 4 007 0004 45 3331 2 Copper ASARCO SMELTER - HAYDEN 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 CYPRUS MIAMI MINE 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/CHINO MINES 28,058 14,784 15,685 11,420

NM 35 023 0003 64 3331 2 Copper PHELPS DODGE/HIDALGO SMELTER 41,433 32,121 29,188 0

UT 49 035 0030 32 3331 2 Copper Kennecott Utah Copper Corp. 26,829 1,556 762 937

148,510 104,549 84,218 35,920
X-4
XI-1

CHAPTER XI

ALUMINUM PRODUCTION

A. SECTOR DESCRIPTION AND SIGNIFICANT SO2 SOURCES

Primary aluminum production plants in the United States produce aluminum metal

by electrolytically reducing alumina that have been refined from bauxite ore. There are 23

primary aluminum plants in the United States. There are only 2 plants in the study region

and both are located in Oregon.

Aluminum production is carried out in a semibatch manner in large electrolytic cells

called pots with a direct current input of up to 280,000 amperes at about 5 volts. The pot, a

rectangular steel shell ranging in size from 30-50 feet long, 9-12 feet wide, and 3-4 feet

high, is lined with a refractory insulating shell on which carbon blocks are placed to form

the cathode.

An aluminum pot will typically emit 20-35 kg per metric ton of gaseous and

particulate fluoride and roughly an equal amount of particulate matter. The NSPS limits

emissions to no more than 1 kg fluoride/Mg (2.0 lbs/ton) of aluminum produced for potroom

groups at Soderberg plants, 0.95 kg/Mg (1.9 lbs/ton) of aluminum produced at pre-bake

plants, and 0.05 kg/Mg (0.1 lbs/ton) of aluminum equivalent for anode bake plants.

The reduction cells in use for aluminum production in the United States are of two

basic types – prebake and Soderberg. There are two types of Soderberg cells that are

designated according to the manner of mounting the stud in the carbon anode: vertical stud

Soderberg (VSS) or horizontal stud Soderberg (HSS).

Prebake cells are so named because the anodes are preformed and then baked in a

separate facility often referred to as an anode bake plant. The anodes are then mounted in

the cell and are consumed in the aluminum production. The anode butts, which remain

after the anode is consumed, are recycled for use in the preparation of new anodes.

In the Soderberg process, continuously formed, consumable anodes are used. The

anode paste is baked by the heat generated in the reduction cell.

The primary source of sulfur oxide emissions in aluminum production is the sulfur

in the coke (normally petroleum coke) and the coal tar pitch binder used to produce the

anodes. In the prebake process, the combustion fuel to bake the anodes may be a

significant SO2 emission source. Petroleum coke usually contains 2.5 to 5 percent sulfur,

but may vary from 1.5 to 7 percent sulfur. Pitch normally contains about 0.5 percent

sulfur. The sulfur content of the coke depends on the crude petroleum stock and the

tendency of the sulfur to concentrate in the still bottoms at the refinery and thus in the

coke.

As the coke is processed (during prebake) or consumed in the reduction cell, sulfur

oxides are released. The emissions include those from the anode prebake operation

(prebake), the “primary” emissions (which are captured by the pot hood exhaust system),

and the “secondary” emissions (which escape the primary exhaust system and exit through

the roof monitors). The great majority of SO2 emissions are collected by the pot hood

exhaust system.

One source reports uncontrolled SO2 emissions from anode bake plants range from 5

to 47 ppm, which is 0.7 to 2 kg SO2/Mg aluminum produced (1.4 to 4 lbs SO2/ton aluminum
XI-2

produced). Other data indicate that emissions are in the range of 0.09 to 1.7 kg SO2/Mg

aluminum produced (0.18 to 3.4 lbs SO2

/ton aluminum produced).

The total amount of SO2 generated per unit of aluminum produced is essentially the

same for the prebake, VSS, and HSS cases. The “primary” cell hooding configuration for

collection of process fumes is affected by the characteristics of the different cell types. 

There are two types of prebake cells, center-worked prebake cells (CWPB) and side-worked

prebake cells (SWPB), as well as the two Soderberg processes, VSS and HSS, which are in

use by the domestic aluminum industry. Information from seven primary aluminum plants

indicates the following:

Cell Type

Primary Hood Collection

Efficiency, %

Primary Collector Exhaust Rate

(106

 square cubic feet per ton of aluminum)

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)

This information indicates that the gas volume associated with the production of a

fixed amount of aluminum is in the range of 5 to 12 times (average 8 times) greater for

CWPB, SWPB, or HSS than for VSS. Consequently, the concentration of SO2

 in a volume of

exhaust gas in the primary collector system can be expected to be about 8 times greater for

a VSS unit than for other units.

Reported data on uncontrolled “primary” exhaust system SO2 emissions are as

follows:

Unit Source SO2

 Concentration, ppm

Total SO2 emissions,

kg SO2

/Mg Aluminum

(lbs SO2

/ton aluminum)

Prebake Cell A 5 Not reported

B Not reported 20.9 to 23.4 (41.7 to 46.8)

[average of 22.4 (44.8)]

C Not reported 30 (60) [3% sulfur in the coke]

VSS Cell A 80 Not reported

B 200 to 300 17.5 to 25 (35 to 50)

C 200 (average) Not reported

The trend in construction of new aluminum plants is toward prebake systems. A

major factor influencing this trend is the lower power requirement of the prebake cell

compared with Soderberg cells. It is reported that 9 of the 11 aluminum plants opened

since 1960 are of the prebake type, and 99 percent of the 324 Gigagrams (357,000 tons)

capacity added since 1973 has been at prebake facilities. Of the 23 primary aluminum

production plants in the United States, 18 use the prebake process and 5 use the Soderberg

process.

B. FLOOR ALLOCATION ESTIMATION METHODS

There are two aluminum smelters located within the study region, and they are both

located in Oregon. The data provided by the Oregon Department of Environmental Quality

on the unit capacities and SO2 emissions potential for these two smelters is provided in

Table XI-1. This table shows that the SO2 emissions potential for Reynolds Metal, if

operated at its design capacity, is 4,700 tpy. This is the same as their permitted SO2

emission limit. For NW Aluminum, the SO2

 emissions potential is 518 tpy.
XI-3

The NSPS for primary aluminum plants limits fluoride emissions, but does not

affect SO2

 emissions. Washington is the only State that has established an SO2

 emission

limit specifically for primary aluminum plants. The rule limits the maximum allowable

total SO2 emissions from all sources within the plant to 60 lbs per ton of aluminum

produced on a monthly basis. Based on the SO2 emission rates by process for Reynolds

Metal, which is 65.3 lbs SO2

 per ton of aluminum produced, applying the State of

Washington rule would only provide an 8 percent reduction in SO2 emissions.

Comparing the capacity-based SO2 emission estimates in Table XI-1 with recent

historical emissions (see Table XI-2) shows that recent historic SO2 emissions from

Reynolds Metals are considerably below their capacity/permitted emission limit, and that

they vary considerably from year-to-year. NW Aluminum SO2

 emissions in the period 1996

to 2000 average about 80 percent of total capacity.

The floor control technology for aluminum smelters was determined by evaluating

the emissions performance of Reynolds Metals and NW Aluminum. NW Aluminum uses a

wet scrubber to achieve a 70 percent SO2 emission reduction. Therefore, a wet scrubber

with a 70 percent SO2

 reduction was selected as the floor technology for aluminum

smelters. The effect of this floor technology application is shown in the rightmost column of

Table XI-1.

REFERENCES

CFR, 2001: Code of Federal Regulations, “Subpart S - Standards of Performance for

Primary Aluminum Plants (60.190-60.195),” July 1, 2001.

EPA, 1981: U.S. Environmental Protection Agency, “Control Techniques for Sulfur Oxide

Emissions from Stationary Sources,” Second Edition, EPA-450/3-81-004, Office of Air

Quality Planning and Standards, Research Triangle Park, NC, April 1981.
XI-4

Table XI-1

Aluminum Plant Data Used to Estimate Floor Allocations

Company Em issions U nit Fuel Type

Actual

Capac ity

Capac ity

Units

Control

Device

SO2

 Emission

Factors

(lbs/ton)

SO2 Control

Efficiency

SO2

 Emissions

Actual Capacity

(tons/yr)

Floor Allocation

at 70% Control

(tons/yr)

Re ynold s M etals Carbon bakes

Potroom fugitives

Potroom emissions

Backup fuel

Plant total

Natural gas

N/A

N/A

#2 fuel 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 Aluminum Cell line

Cell line

Casthouse furnace

Plant total

N/A

Propane

Natural gas

97,500

144,000

80,000,000

TAP/yr

gallons/yr

cubic fee t/yr

W et scrubber

No

No

0.7

N/A

N/A

517 

<0.1 

1 

<518 

517 

<0.1 

1 

518 

Total 5,218 2,076 

NOTES: Control Device: While there are no physical control devices, the most effective form of SO2

 control is limiting the amount of sulfur in fuel oil. For example, the sulfur

content in distillate fuel oil sold in NW usually averages much less than 0.1, whereas the rule limit is 0.5. Actual Capacity Emission is limited by the SO2

 PSEL. SO2

emission factors are in lbs per ton of aluminum produced.
XI-5

Table XI-2

Aluminum Smelting - Historical Emissions - 1990 to 2000

Sta te

Sta te

ID

Co unty

ID

Fac ility

ID

IAS

Region SIC

MTF

Sector Sector Description Facility Name (1990)

Current Facility Name

(if different from 1990)

SO2

tpy

1990

SO2

tpy

1996

SO2

tpy

1998

SO2

tpy

2000

100 tpy or More SO2

OR 41 065 0001 5 3334 10 Me tals/Min ing/Min erals Northwest Aluminum Com pany, Inc. 423 448 375 397

OR 41 051 1851 5 3334 10 Me tals/Min ing/Min erals Reynolds Metals Company 3,340 0 503 1,510

3,763 448 878 1,907
XI-6
XII-1

CHAPTER XII

SULFURIC ACID PLANTS

Sulfuric acid is the most widely used industrial chemical. The chief uses of sulfuric

acid are in production of fertilizer, manufacture of chemicals, oil refining, pigment

production, iron and steel processing, synthetic fiber production, and metallurgical

operations. The predominant process used for the production of sulfuric acid is the contact

process. The entire discussion in this chapter focuses on the contact process.

Sulfuric acid is produced by burning sulfur or sulfur-bearing materials to form SO2. 

Sources of SO2

 include: (1) elemental sulfur; (2) spent acid; (3) smelter off-gas; (4) pyrites;

and (5) waste gas from fossil-fuel-fired boilers.

A. SECTOR DESCRIPTION AND SIGNIFICANT SO2 SOURCES

Contact sulfuric acid plants are classified as hot gas (sulfur burning) or cold gas

(metallurgical and spent acid) systems. Plants operating on elemental sulfur receive hot

SO2

 gas directly from the sulfur burner and waste heat recovery system. When SO2

 gas

from a metallurgical operation or other byproduct source (such as spent acid or iron pyrites)

is used, it is received cold from the wet scrubber-cooler and purification systems.

A basic variation of the contact process is the double absorption technique, also

known as double catalysis. This design is largely based on the need to meet air pollution

control regulations.

The only significant source of air emissions from a contact sulfuric acid plant is the

tail gas leaving the final absorbing tower. This gas contains small amounts of SO2

 and even

smaller amounts of SO3, sulfuric vapor, and sulfuric acid mist.

SO2 emissions are determined primarily by overall plant design (e.g., number of

catalyst passes, amount of catalyst, dual or single absorption, etc.). New plants are usually

designed to meet NSPS emission limits using the dual absorption process. In certain

situations, plants can achieve better than NSPS limits using the dual absorption process. 

For example, in a metallurgical acid plant, lower SO2

 emissions can sometimes be achieved

catalytically if the process gas from a smelter has a sufficiently high oxygen-to-SO2 ratio. 

Proper catalyst volumes and interpass cooling can be incorporated into the initial design,

however. Existing plants that are required to reduce their SO2 emissions usually choose to

convert to dual absorption or install a tail gas scrubber.

Dual absorption has been generally accepted as BACT. Conceptually, dual

absorption is the addition of another converter and absorbing tower on the tail end of a

single absorption plant (with appropriate heating and cooling of the gas stream) so there is

no new technology involved. Only sulfuric acid is produced in the dual absorption

equipment.

Various scrubbing, or tail gas, technologies are available for removing SO2 from gas

streams. Tail gas treatment is rarely used to achieve NSPS limits for new plants. A tail

gas process at the end of a dual absorption plant may be the preferred technology where

local regulations require substantially lower than NSPS emission rates.

Tail gas processes that produce a by-product that can be recycled to the acid plant

(e.g., weak sulfuric acid) are of special interest because they eliminate the need for off-site

by-product disposal. Two such processes are hydrogen peroxide scrubbing and SO2

oxidation with activated carbon.
XII-2

B. FLOOR ALLOCATION ESTIMATION METHODS

Based on the information available for sulfuric acid plants in the west, it was

determined that it is appropriate to estimate the floor allocation by applying the NSPS

requirements to each sulfuric acid plant.

Subpart H - Standards of Performance for Sulfuric Acid Plants

60.82 Standard for Sulfur Dioxide

On or after the date on which the performance test required to be conducted by Sec.

60.8 is completed, no owner or operator subject to the provisions of this subpart shall cause

to be discharged into the atmosphere from any affected facility any gases which contain SO2

in excess of 4 lbs per ton of acid produced. Achieving this standard requires a conversion

efficiency of 99.7 percent in an uncontrolled plant, or the equivalent SO2 collection

mechanism in a controlled facility.

Table XII-1 lists the sulfuric acid plants, their characteristics, and the estimated

annual SO2

 floor allocations. An initial SO2

 floor allocation was estimated by multiplying

the daily throughput limit by the NSPS emission rate (4 lbs SO2 per ton 100 percent acid

produced), times 365 days per year, converted from lbs to tons by dividing by 2000. In

equation form, this is:

This based on throughput initial floor allocation was found to exceed the annual SO2

permit limits for each of these units. Therefore, the estimated floor allocations for these

sulfuric acid plants was established using recent historic SO2

 emissions data. These

historic emission values are all slightly below the annual SO2 permit limits.

REFERENCES

AWMA, 2000: Air and Waste Management Association, “Air Pollution Engineering

Manual,” 2nd edition, Chapter 12 - Chemical Process Industry, 2000.

CFR, 2001: Code of Federal Regulations, Subpart H - Standards of Performance for

Sulfuric Acid Plants (60.82), July 1, 2001.

Idaho DEQ, 2002a: State of Idaho, Department of Environmental Quality, Air Quality Tier

1 Operating Permit, J.R. Simplot Co. - Don Siding Plant, 2002.

Idaho DEQ, 2002b: State of Idaho, Department of Environmental Quality, Air Quality Tier

1 Operating Permit, Nu-West Industries, Inc.; Agrium Conda Phosphate Operations,

2002.
XII-3

Table XII-1

Sulfuric Acid Plants

State Facility Name

Start

Date

Sulfuric Ac id

Plant ID Process

Control

Technique

Annual SO2

Pe rm it Lim it

(tons)

Da ily

Throughput

Limit (tons)

Based on

Throughput

SO2 Floor

Alloc ation (tpy)

Floor Allocation

Us ing His toric

Emissions

Average (tpy)

Idaho Nu-W est Industries East NA NA 945 1,550 1,131 612

Idaho JR Simplot 300 Single contact 2 stage scrubber system 750 1,750 1,277 1,939

400 Doub le contact Doub le contact with mist

eliminator

1,458 NA 1,458

W yom ing SF Pho sphates, Inc. 1995 Source 9b MEC 963.6 1,320 964 1,638

1984 Source 9a Lurgi 1,387 1,900 1,387

W yom ing Koch Sulfur

Pro ducts

EU -1 NA 719 NA 719 1,197

EU -5 NA 721 NA 721

NA = not available.
XII-4
XIII-1

CHAPTER XIII

METALLURGIC COKE PRODUCTION

A. SECTOR DESCRIPTION AND SIGNIFICANT SO2 SOURCES

Metallurgical coke is derived from coal and used in iron and steel industry processes. 

Coke is manufactured by pyrolysis, the heating of coal in the absence of air. In this process,

high grade, bituminous coal is heated in a enclosed chamber to approximately 1050°C

(1925°F), which removes all volatile components of the coal. The resulting product is a solid

material consisting of elemental carbon and any minerals that were not volatilized in the

heating process.

1. By Product Coke Ovens

In a typical coking operation, 35 to 100 coke ovens are located in a row referred to as

the oven battery. Each oven has three main parts: coking chambers, heating chambers,

and regenerative chambers. The coking chamber has ports in the top for charging (loading)

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 facilities.

All ovens currently operating in the United States are by-product recovery ovens. 

These ovens operate by reusing gases (volatiles) emitted by the hot coal. In by-product

recovery ovens, the volatiles from the coal are collected and sent to a by-product recovery

plant. The off gas is condensed and separated into a liquid fraction (coal tar) and a gaseous

fraction (coal gas). The coal gas contains a number of contaminants including hydrogen

sulfide. Some by-product recovery processes remove the sulfur from the gas prior to

combustion. Approximately 33 percent to 40 percent of the clean coal gas is then returned

to the oven battery to be used as fuel. The remaining coal gas can be used as fuel for other

processes at the plant or sold to other facilities.

Emissions of SO2 from coke ovens operations primarily result from combustion of the

byproduct coal gas in the oven. A small portion of SO2 emissions comes from uncontrolled

“charging”, the process of loading coal into the oven. Control of SO2

 from combustion of coal

gas is primarily accomplished by; (a) removing the sulfur from the gas prior to combustion

or (b) utilizing low sulfur coal in the coking process. There are a number of methods for

removing sulfur from the coal gas, such as wet scrubbing.

2. Rotary Calciners

There is only one known rotary calciner used for coke production in the United

States, P4 Production in Rock Springs, WY. It uses a Salem Brosius, 65 foot diameter,

continuous feed rotary hearth calciner. Basically, the process involves feeding a mixture of

coal and petroleum (pet) coke onto a rotating table located inside a furnace. The coal is

heated to a high temperature as it rotates to produce coke. The coke exits the hearth and

enters a cooling chamber. Like byproduct recovery ovens, the furnace operates by reusing

the volatile gases emitted from the coal. However, in this process, the furnace is initially

started with natural gas. Once started, the coal gas being emitted during the coking

process is utilized as fuel directly. The waste gas is then ducted to an incinerator.

Byproducts of the process include fine coke, ash, CO2, SO2, and rock.

Emissions of SO2

from a rotary hearth calciner are primarily due to the volatiles from

the heated coal. The waste gas is ducted to an incinerator and baghouse prior to being
XIII-2

emitted to the atmosphere. There is no desulfurization of the waste gas. The amount of

SO2

 emitted from the facility is a function of the properties of the feed coal. 

B. FLOOR ALLOCATION ESTIMATION METHODS

The analysis was limited to facilities which emit greater than 100 tpy of SO2 in total. 

There are three facilities which have been identified. Two are coking plants, Astaris

Coking Plant in Wyoming and Geneva Steel in Utah. There is one rotary calciner in

Wyoming, P4 Production, Rock Springs Coal Calcining Plant. The air pollution agencies for

Wyoming and Utah provided information on the coking and calcining facilities for

estimating floor allocations. 

Astaris Coking Plant was shut down in April of 2001. Therefore, this facility does

not receive an SO2

 allocation. 

Geneva Steel has committed to ceasing all SO2 emissions from the coke ovens and

the sinter plant. These emissions have been banked for future use or trading as precursor

pollutants within the current local Utah County PM10 SIP. The Utah Air Quality Board

approved this change on June 5, 2002. Since the SO2

 emissions for coking and sintering at

the plant are now essentially zero, the SO2 floor allocation for coking is also zero. 

The third facility is P4 Production, Rock Springs Coal Calcining Plant. The plant is

designed to process 220,000 tpy of feed materials to produce 110,000 tpy of coke product. 

The plant operates for up to 8,000 hours per year. This works out to a design process rate

of 27.5 tons per hour (tph) or 660 tons per day (tpd) of feed. According to the operating

permit, the total facility potential to emit is 2,841.1 tpy of SO2 based on 8,760 operating

hours. There are no NSPS requirements the facility must comply with for SO2

. This rotary

coker was built in 1972 and thus is "grandfathered" from the Wyoming Air Quality

Division's permit requirements. The historical emissions for this facility are presented in

Table XIII-1.

Table XIII-1

Historical SO2

 Emissions at P4 Production, Rock Springs, WY

Historical Emissions of SO2

 (tpy) Average Annual SO2

Emissions (tpy)

1990 1996 1997 1998 2000 1996 - 2000 

933 663 586 642 633 631

As stated previously, the SO2

 emitted is a function of the feed coal. The plant uses a

blend of coal and petroleum coke (pet coke). The 1994 annual inventory showed that the

pet coke blend was 7.2 percent for the year, with SO2 emissions of 420.0 tpy; up 15 percent

from the 365.6 tpy emitted in 1993, when straight coal was used as 100 percent of the

feedstock. The most recent year's data shows that the pet coke blend was 25 percent for

1998, the maximum allowable amount to maintain compliance with the SO2

 emissions

limit.

The procedure for estimating the floor allocation for P4 Productions is difficult for

several reasons. First, there are no identified control technologies available for the rotary

calciner. Second, there are no NSPS requirements. Third, P4 Production has a potential to

emit 2,841.1 tpy based on 8,760 hours of operation. This is much higher than the annual

emissions reported by the plant. Lastly, the SO2 emissions from the rotary calciner are a

function of the sulfur content of the feed which varies over time. Since the coking process

at P4 Production is unique and cannot be compared with emissions from other facilities, the

SO2

 allocations for P4 Productions will be based on its average annual emissions. This is
XIII-3

consistent with the allocation approach developed for source categories with no technology

available for reducing sulfur and variable sulfur content in the feed such as flaring.

The allocation for P4 Production will be based on emissions of SO2 from years 1996,

1997, 1998 and 2000. Averaging historical emissions results in a floor allocation of 631 tpy

of SO2 for the P4 Production facility. As stated previously, the SO2

 floor allocations for

Astaris and Geneva Steel are zero.

C. COMPARISON WITH HISTORICAL EMISSIONS

Table XIII-2 presents the historical SO2

 emissions and the SO2

 floor allocations for

all three coking facilities. Note that Geneva Steel has an SO2 allocation for its boilers,

which is discussed in Section IV.

Table XIII-2

Coking Plant - Historical Emissions - 1990 to 2000

Sta te Co unty

ID

Fac ility

ID SIC

MTF

Sector

Sector

Description

Facility Name

(1990)

Current Facility Name

(if different from1990)

SO2

 tpy

1990

SO2

 tpy

1996

SO2

 tpy

1998

SO2

 tpy

2000

SO2

 Floor

Allocation

W Y 037 0003 10 Metals/Mining/

Min erals

Sweetwater

Resources

P4 Production - Rock

Springs

933 663 642 633 631

W Y 023 001 10 Metals/Mining/

Min erals FMC Coking Plant Astaris Coking Plant 1,194 1,413 1,454 1,409 0

UT 049 0027 3312 10 Metals/Mining/

Min erals Geneva Steel 8,473 2,020 881 979 0

REFERENCES

AWMA, 2000: Air and Waste Management Association, “Air Pollution Engineering

Manual,” 2nd edition, Chapter 14 - Metallurgical Industry, 2000.

EPA, 1981: U.S. Environmental Protection Agency, “Control Techniques for Sulfur Oxide

Emissions from Stationary Sources,” Second Edition, EPA-450/3-81-004, Office of Air

Quality Planning and Standards, Research Triangle Park, NC, April 1981.

EPA, 1998: U.S. Environmental Protection Agency, “Compilation of Air Pollutant Emission

Factors,” AP-42, Fifth Edition, Volume I: Stationary Point and Area Source, Section

12.2 Coke Production” Office of Air Quality Planning and Standards, Research

Triangle Park, NC, 1998.
XIII-4
XIV-1

CHAPTER XIV

FLOOR ALLOCATION SUMMARY

Table XIV-1 summarizes the SO2 floor allocation estimates from all of the previous

chapters by State and by sector. California estimates listed in Table XIV-1 are based on

average SO2

 emissions in these sectors from 1996, 1998, and 2000. Table XIV-1 shows the

estimated SO2 floor allocation for non-utility sources in the 9-State Commission Transport

Region to be about 195 thousand tons. If copper smelter SO2

 allocations in 2018 are

subtracted from this amount, the floor allocation is 117 thousand tons. The non-smelter,

non-California SO2 emissions total is 89,000 tons.

Table XIV-2 provides a complete list of the facility-level SO2

 floor allocations, and

includes year 2000 SO2 emissions as a point of comparison.
XIV-2

Table XIV-1

State/Sector Summary of SO2 Floor Allocations

(tons per year)

Sectors

States Refineries

L im e

Manufacturing*

Industrial

Boilers

Pulp and

Paper

Cement

Manufacturing

Natural Gas

Processing

Elemental

Phosphorus **

Glass

Manu facturing***

Copper

Sm elters

Aluminum

Plants

Sulfuric

Acid Plan ts

Coke

Production Total

Arizona 1,365 978 320 43,000 45,663

Ca lifornia 27,335

Colorado 1,614 387 4,936 237 7,174

Idaho 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: *Based on 1998 and 2000 historical SO2 emission estimates.

**Based on year 2000 SO2

 emission estimates for P4 Production, which are substantially higher than 1996 or 1998 emissions.

***Based on 1996, 1998, and 2000 historical SO2

 emission estimates.
XIV-3

Table XIV-2

Facility-Level SO2 Floor Allocations

Comparison with Year 2000 SO2

 Emissions (tons per year)

State

Facility

ID Sector Description Facility Name (1990) Current Facility Name

In Current

Report Comments

 SO2

Emissions

Year 2000

SO2

 NonBoiler

Allocation

SO2

Boiler

Allocation

Total

SO2

Allocation

State

Totals

AZ Cement/Concrete Arizona Portland Cement X 320 0 0

AZ 0011 Metals/Mining/Minerals CHEMICAL LIME (CHEMSTAR) CHEMICAL LIME - NELSON X 702 632 632

AZ 0003 Metals/Mining/Minerals Chemical Lime (Douglas) X 742 733 733

AZ Cement/Concrete Phoenix Cement X 539 320 320

AZ 0007 Wood/Paper/Pulp STONE CONTAINER ABITIBI X 1,893 0 978 978

AZ 0001 Oil/Gas Intermountain Refining X Closed 0 0 0

AZ 0004 Copper ASARCO SMELTER - HAYDEN X 16,753 21,000 21,000

AZ 0032 Copper BHP(Magma Metals) BHP - San Manuel X 0 14,000 14,000

AZ 0006 Copper CYPRUS MIAMI MINE X 6,810 8,000 8,000

AZ 0040 Copper Cyprus Sierrita X 0 0 0

45,663

CO 0048 Metals/Mining/Minerals 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 MOUNTAIN BOTTLE 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 PLT. X 50 160 160

CO 9 Misc. GENERAL SERVICES ADMINISTRATION 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 RETORT-PARACHUTE 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/Cogeneration 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/Paper/Pulp Boise Cascade - Emmett 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 MONSANTO/P4 PRODUCTION P4 Production X Elemental Phosphorus 15,861 15,861 15,861

ID 0003 Chemicals/Plastics NU WEST INDUSTRIES Sulfuric acid plants 86 612

ID 0001 Wood/Paper/Pulp POTLATCH X Paper Mill 1,694 1,807 1,807

ID Misc. RICKS COLLEGE 0 0

ID 0006 Chemicals/Plastics SIMPLOT Sulfuric acid plants 543 1,939

ID 0010 Food TASCO (NAMPA) Amalgamated Sugar (Nampa) 1,697 242 242

ID 0001 Food TASCO (PAUL) Amalgamated Sugar (Paul) 1,322 155 155

ID 0001 Food TASCO (TWIN) Amalgamated Sugar (Twin) 1,053 203 203

ID Food Idaho Supreme 0 0

ID 0001 Misc. MTN. HM. AFB 144 0

21,341

NV 0003 Metals/Mining/Minerals CHEMSTAR APEX CHEMICAL LIME CO-APEX PLANT X Lime plant 210 193 193

NV 0387 Cement/Concrete NEVADA CEMENT COMPANY FERNLEY PLANT X 172 305 305

NV Cement/Concrete Royal Cement Not in previous report 143 143
Table XIV-2 (continued)

State

Facility

ID Sector Description Facility Name (1990) Current Facility Name

In Current

Report Comments

 SO2

Emissions

Year 2000

SO2 NonBoiler

Allocation

SO2

Boiler

Allocation

Total

SO2

Allocation

State

Totals

XIV-4

NV 0261 Metals/Mining/Minerals 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 Metals/Mining/Minerals BASIC INC.(Now PREMIER CHEMICALS LLC) PREMIER SERVICES (Gabbs Facility) 0

NV 0863 Misc. HAWTHORNE ARMY 0

NV Metals/Mining Independence Big Springs ANGLO GOLD 0

NV 0019 Metals/Mining/Minerals TITANIUM METALS 0

883

NM 0024 Oil/Gas AGAVE ENERGY/YATES PLANT 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 PLANT 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 VERSADO GAS PRODUCERS LLC X 2,759 0

NM 0011 Oil/Gas GPM GAS/ARTESIA GAS PLANT 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 PLANT Duke Energy Lee Plant X 818 0 0

NM 0035 Oil/Gas GPM GAS/LINAM RANCH GAS PLANT Duke Energy Plant 5 1,304 1,181 1,181

NM 0007 Oil/Gas J.L. DAVIS GAS PROCESS/DENTON X 1,158 840 840

NM 0008 Oil/Gas MARATHON OIL/INDIAN 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 ENERGY/BURTON FLATS GAS PLT Duke Energy Burton Plant X 246 164 164

NM 0285 Oil/Gas PAN ENERGY/DAGGER 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 PLANT 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 Resources X 3,127 3,127

NM 0128 Oil/Gas CITATION/ANTELOPE RDG GAS PLANT X 0

NM 0118 Oil/Gas CONOCO/BELL LAKE 2 WELL #6 X 0

NM 0125 Oil/Gas FEAGAN ENERGY/W DAGGER DRAW GAS PLT Duke Energy Dagger Draw X 0

NM 0050 Oil/Gas YATES PETROLEUM/PATHFINDER AMINE 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 Amalgamated Sugar Company, The X 987 0 74 74

OR Wood/Paper/Pulp X Not in previous report 0

OR 1849 Wood/Paper/Pulp Boise Cascade Company X 1,834 1,532 411 1,943

OR Oil/Gas X Not in previous report

OR 0005 Wood/Paper/Pulp Georgia-Pacific West, Inc. X 452 258 143 401

OR 0007 Metals/Mining Glenbrook Nickel Company 0 0

OR 2125 Metals/Mining/Minerals Globe Metallurgical Inc. 197 0

OR 0036 Wood/Paper/Pulp X 0 0

OR 0004 Wood/Paper/Pulp James River II, Inc. Georgia- Pacific (Wauna Mill) X 643 1,361 277 1,638

OR 0001 Metals/Mining/Minerals 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 Description Facility Name (1990) Current Facility Name

In Current

Report Comments

 SO2

Emissions

Year 2000

SO2 NonBoiler

Allocation

SO2

Boiler

Allocation

Total

SO2

Allocation

State

Totals

XIV-5

OR 3501 Wood/Paper/Pulp Pope & Talbot Pulp, Inc. X 293 248 107 355

OR 1851 Metals/Mining/Minerals Reynolds Metals Company X 1,510 1,558 1,558

OR 6142 Wood/Paper/Pulp Smurfit Newsprint Corporation 2 X No longer pulping 519 0 0

OR Wood/Paper/Pulp West Linn Paper Co. X Not in previous report 0 211 211

OR 8866 Wood/Paper/Pulp Weyerhaeuser Company SierraPine, Ltd. X 0 0 0 0

OR 0471 Wood/Paper/Pulp Willamette Industries, Inc. X 327 310 310

OR 8850 Wood/Paper/Pulp Collins Products LLC Weyerhaeuser Co. X Weyerhaeuser Springfield 1,721 1,668 362 2,030

OR 5034 Misc. Cascade Steel Rolling Mills, Inc. 0 0

OR 2028 Oil/Gas Kinder Morgan Energy Partners, L.P X

OR 0041 Chemicals/Plastics Georgia-Pacific Resins, Inc. 0

OR 0013 Wood/Paper/Pulp J. Peterkort & Company Collins Products LLC 0

OR 5398 Wood/Paper/Pulp Ogden Martin Systems of Marion, Inc. Covanta Marion, Inc. X 0

OR 2050 Misc. Oregon Health Sciences University OHSU X 0 0

OR 0015 Wood/Paper/Pulp Weyerhauser - Coos Bay Hog waste-fired boiler 882 0

9,169

UT 10572 Copper Kennecott Utah Copper Corp. X Smelter 2,534 1,000 700 1,700

UT 10096 CHP Sunnyside Cogeneration Associates 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 Young University X 125 1 1

UT 0001 Metals/Mining/Minerals Brush Wellman Inc. X 179 23 23

UT 0003 Oil/Gas Chevron Products Company X Refining 1,242 1,240 1,240

UT -9902 Metals/Mining/Minerals Continental Lime Inc. Graymont X Lime 331 303 303

UT 0008 Oil/Gas Flying J Incorporated X Refining 300 674 674

UT 0027 Metals/Mining/Minerals Geneva Steel X Shutdown coke ovens and sinter plant 979 17 17

UT 0001 Cement/Concrete Holnam Incorporated Holcim X Cement 288 267 267

UT 0013 Oil/Gas Phillips 66 Company X Refining 601 762 762

UT Oil/Gas Silver Eagle Refining Inc. X Not in previous report (Refining) 77 77

UT -9901 Oil/Gas Unocal Corporation Tom Brown-Lisbon Plant X Natural gas processing 1,252 1,593 1,593

UT 10676 Utelite Corporation 133 0 0

9,315

WY 0012 Oil/Gas AMOCO - ELK BASIN HOWELL PETROLEUM - ELK BASIN X 2,638 1,200 1,200

WY 0012 Oil/Gas AMOCO - WHITNEY CANYON 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 CANYON DEHY & WELLFIELD 167 0

WY 0010 Metals/Mining/Minerals FMC - GRANGER (TEXAS GULF) X 212 305 305

WY 48 Metals/Mining/Minerals FMC - GREEN RIVER X 4,901 956 956

WY 0001 Metals/Mining/Minerals 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 Metals/Mining/Minerals GENERAL CHEMICAL X 5,000 750 750

WY 0001 Food HOLLY SUGAR - TORRINGTON 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 MOUNTAIN RESOURCES - AINSWORTH X 0 843 843

WY 1 Oil/Gas KCS Mountain Resources Rushmore 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 CABIN b BURLINGTON RESOURCES - LOST CABIN b X 213 1,867 1,867

WY 0007 Oil/Gas MARATHON GAS PLANT - OREGON BASIN Oregon Basin Gas Plant X 358 391 391

WY Oil/Gas MARATHON OIL - MILL IRON X 0 247 247
Table XIV-2 (continued)

State

Facility

ID Sector Description Facility Name (1990) Current Facility Name

In Current

Report Comments

 SO2

Emissions

Year 2000

SO2 NonBoiler

Allocation

SO2

Boiler

Allocation

Total

SO2

Allocation

State

Totals

XIV-6

WY 1 Oil/Gas Marthon Oil Pitch Fork Battery X 61 61 61

WY 0003 Metals/Mining/Minerals SWEETWATER RESOURCES P4 PRODUCTION - ROCK SPRINGS X Rotary coker 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 @ SINCLAIR X Refining 3,407 1,066 1,066

WY Oil/Gas SNYDER OIL - RIVERTON DOME DEVON SFS - RIVERTON DOME 492 0

WY Metals/Mining/Minerals SOLVAY MINERALS X 52 294 294

WY 0012 Oil/Gas TEXAS-BYRON PLANT BIG HORN GAS PROCESSING - 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 REFINING - NEWCASTLE X Refining 876 449 449

WY 008 Oil/Gas DEVON SFS OPERATING CO. BEAVER CREEK X 831 0

WY 0003 Metals/Mining/Minerals AMERICAN COLLOID - WEST COLONY 0

WY 0002 Oil/Gas AMOCO REFINERY Closed 0 0

WY 0001 Metals/Mining/Minerals BENTONITE CORPORATION LOVELL 0 0

WY 0014 Oil/Gas COLORADO INTERSTATE GAS - TABLE ROCK 0 0

WY 0013 Oil/Gas MARATHON OIL COMPANY - GARLAND 0 0

WY Oil/Gas Hallwood Petroleum-Federal Packsaddle 1-24 X Not in previous report 133 133

WY Oil/Gas Hallwood Petroleum-Federal Packsaddle 1 X Not in previous report 960 960

23,828

TOTALS 170,226 167,583 167,583 

aSO2

 Allocation based on historical emissions.

bPlant has just added capacity and allocation is based on current (July 2002 capacity).
Appendix A-8 – SO2 Milestones/Backstop Arizona Regional Haze SIP

Appendix A-8b. Western Emissions Backstop (WEB) Emissions & 

Allowance Tracking Systerm (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. 
 

July 18, 2003WEB EATS Analysis

-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

States/Tribes Allocation System

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

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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.
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! 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.
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! 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.
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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. 
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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.
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! 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.
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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 Tribes 

regarding allocation 

status

WEB EATS imports 

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

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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.
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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 SO2 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.
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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

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WEB EATS compares 

allowances held in 

compliance accounts 

and the total level of 

emissions

Source Representatives 

place appropriate amount of 

allowances to be deducted in 

compliance 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

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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 SO2 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 SO2 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

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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

SO2 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

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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

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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 SO2 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.
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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

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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
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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
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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

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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
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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.
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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 active

sessions and assuming the identity of a user, session tokens need to be regularly revalidated.
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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.
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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
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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.
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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 SO2

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.
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! 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
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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
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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. 
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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. 
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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.
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! 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
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maximize understanding of and knowledge about the program among all interested

parties. 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.
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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.
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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. Recommendations 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 Committee, 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 Sundblom, 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 Quality; Alan Newman, Washington Department of 

Ecology; Lisa Reiner, Quinalt Indian Nation; Bruce Polkowsky and Kristi Gebhart, National 

Park Service; and Kristin Gaston and Bob Lebens, WESTAR. 

Prepared for: 

The Air Managers Committee of the Western Regional Air Partnership 

in fulfillment of the Western Governors’ Association contract #30203-13 

May 2003 
Acknowledgements 

The recommendations regarding the attribution 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 acknowledges the generous support of all the Working Group 

members. Alice Edwards, Alaska Department of Environmental Conservation; Mike Sundblom, 

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 Quality; 

Lisa Reiner, Quinalt Indian Nation; Bruce Polkowsky and Kristi Gebhart, National Park Service; 

and Kristin Gaston and Bob Lebens, WESTAR. 

Authors of the Attribution Techniques (Section VI) are Mike Sundblom (Monitoring); 

Kristi Gebhart (Receptor Modeling); and Dave DuBois (Source Modeling), with assistance from 

Ajith Kaduwela, California Air Resources Board. Bruce Polkowsky and Colleen Delaney 

drafted the certification section and provided liaison between the Western Regional Air 

Partnership Market Trading Forum and the Working Group. Alan Newman, Washington 

Department of Ecology drafted the portion of the report outlining the example process to which 

Dana Mount also contributed. Kristin Gaston drafted the regulatory context section and along 

with Bob Lebens, edited the report. 
EXECUTIVE SUMMARY 

This report recommends a general procedure and applicable technical approaches that may 

be used by states and tribes to assess reasonable attribution in response to a Federal land manager 

(FLM) certification of visibility impairment in a Class I area (Certification). 

WESTAR formed the Reasonably Attributable 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 knowledgeable about RA BART and associated monitoring 

and modeling techniques. To provide the necessary framework, the report provides background 

information about both the certification process and the attribution determination process. 

However, the recommendations focus on the general principles of the attribution assessment 

process and the technical criteria 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 and within a reasonable time frame. 

 No more complex than necessary. 

 Performed by state or tribal agency staff. 

 Adequate to determine whether or not visibility 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 pollutants of concern must be identified. 

 Factors to consider in assessing impairment 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 impairment 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. Background....................................................................................................... 1

 A. Introduction and Purpose 

 B. Regulatory Context 

II. Federal Land Manager Certification of Impairment ........................................ 7 

III. The Attribution Determination Process.............................................11 

IV. General Principles and Criteria ...................................................................... 17

 A. General Principles of the Attribution Process 

B. Technical Criteria 

C. Examples of the Attribution Process 

V. Techniques...................................................................................................... 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 Retrofit Technology (RA BART) is the portion of 

EPA’s visibility rule published in 1980 and codified in 40 CFR 51.302–51.306 that deals with 

visibility impacts from one source or a small groups of sources. RA BART refers to reasonably 

attributable visibility impairment and best available retrofit technology for eligible sources and 

emission limits, and emissions controls as defined by the statute and the rules. Some confusion 

exists regarding the application of RA BART, the process of assessing sources of visibility 

impairment, and the technical tools available for an RA BART attribution determination. RA 

BART is a statutory requirement, although certain of the requirements may no longer be 

applicable when a source complies with BART or installs BART-like controls or after a state 

implements a trading program under 51.308(e)(2) or any trading program under 51.309, and if no 

remaining visibility impacts continue from one source or a small group of sources. 

This report, therefore, addresses the RA BART attribution process and builds upon case 

studies WESTAR developed in 2001 to examine and document how Reasonably Attributable 

Visibility Impairment (RAVI) had been addressed in previous assessments.1

 

The Federal land managers (FLMs) advocate maintaining RA BART as a tool because RA 

BART is effective when new monitoring indicates that a previously un-monitored area has 

visibility problems differing from the regional visibility impairment conditions at other areas. In 

addition, RA BART is effective when BART-eligible sources in the vicinity of the protected area 

are causing or contributing to identified visibility impairment.2

 

First, this report recommends attribution process principles and assessment techniques a 

state or tribe may consider in an attribution assessment to identify if, and to what degree, an 

existing source or small group of sources causes or contributes to visibility impairment. The 

report focuses on RAVI and does not specifically address impairment due to regional haze. 

Although this report includes references to regional haze, such references serve only to place the 

attribution process in the larger context of the broad regulatory framework that addresses 

visibility impairment, including the regional haze regulations. 

Second, this report includes no recommendations with regard to establishing a threshold 

level at which reasonably attributable impairment exists. Instead, the working group outlined a 

recommended general process and recommended technical procedures that may be used as 

guidelines if an attribution assessment is necessary. Due to the circumstances unique to each 

attribution assessment and the requirement that the assessment be conducted on a case-by-case 

basis, recommending one specific analysis for every situation was not possible. A state or tribe 

should select from the techniques summarized in Section IV. Section IV(C) includes five 

examples of the attribution assessment process, each providing a range of techniques to be used 

 

1

 WESTAR Council, RA BART and RA BART-like Case Studies, June 2001. 2

 This document specifically relates to RA BART and does not address broader issues relating to long-term visibility

strategies. FLMs generally do not intend to issue Certifications citing specific sources except for situations involving

BART sources. 

1 
based on available data. The examples also recommend more refined analyses that may require 

additional data. 

Third, this report includes specific information about the current policy of FLM agencies 

regarding certifications of impairment (Certification), but makes no recommendations regarding 

the certification process. This report makes no recommendations regarding state process 

following an attribution determination nor examines options for performing the Best Available 

Retrofit Technology (BART) analysis or the incorporation of BART requirements into State 

Implementation Plans (SIPs). 

Tribal Implementation 

The recommendations in this document are intended to help states assess reasonable 

attribution following Certification by an FLM. Subject to the requirements of the Clean Air Act, 

42 USC 7601(d) and the Tribal Authority Rule, 40 CFR 49.1– 49.11, a tribe may accept 

responsibility for making reasonably attributable determinations in response to a Certification by 

an FLM when a BART-eligible source identified by the FLM in the Certification is on the tribe’s 

land. The regional haze rule also explicitly recognizes the authority of tribes to implement the 

provisions of that rule on tribal lands. Those provisions create the following framework: 

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

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

implement CAA programs (including visibility regulation), or “reasonably severable” 

elements of such programs. 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. Where a tribe does not seek delegation through a TIP, the Environmental Protection 

Agency (EPA), as necessary and appropriate, will promulgate a Federal Implementation 

Plan (FIP) within a reasonable timeframe to protect air quality on tribal lands. 

Accordingly, these recommendations also may assist a federally recognized tribe that 

chooses to adopt a TIP to implement the RA BART provisions. In some cases, a tribe may be 

able to utilize the recommendations in much the same way as states. In many other cases, 

however, the recommendations may be modified to meet the unique situation of the tribe and the 

nature of its air program, including its manner of defining “reasonably severable elements” and 

its method of dividing responsibilities between the tribe and EPA. Because of these differences, 

the recommendations that follow do not refer to tribes every time states are referenced. 

B. Regulatory Context 

The national goal for visibility is set forth in the Clean Air Act (CAA) at 42 USC 7491: “the 

prevention of any future, and the remedying of any existing, impairment of visibility in 

mandatory Class I Federal areas which impairment results from manmade air pollution.” The 

requirements apply to 156 designated Class I areas. 

2 
As stated previously, Congress required that states provide a remedy for visibility 

impairment that was “reasonably attributable” to one source or a small group of sources. (42 

USC 7491). Congress directed EPA to ensure that all SIPs contained measures necessary to 

make reasonable progress toward meeting the national goal, including requirements for 

identifying major sources of emissions causing or contributing to visibility impairment, and 

requirements for the application of BART on such sources. EPA promulgated rules pursuant to 

Congress’s directive to provide guidelines to the states on appropriate techniques and methods 

for implementing the SIP requirements. (40 CFR 51.302(c)). (Note: when this report refers to a 

“source” within the meaning of this regulation, the phrase “or a small group of sources” is 

implied.) 

The requirement to install Best Available Retrofit Technology controls on existing sources 

is a key element of the visibility protection provisions in the CAA demonstrating the need to 

focus on pollution emitted from a specific set of existing sources. Sources are potentially subject 

to BART controls if they meet the following criteria:

1. A major stationary source from 1 of 26 source categories identified in the CAA and 

regulations (see Appendix A); 

2. Potential to Emit (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 stationary facility” to define a 

facility that met the above criteria. However, to avoid any confusion about whether that term

encompassed a larger group of sources, EPA now uses the term “BART-eligible source.” The 

term “BART-eligible source” is used throughout this report for similar reasons, but the reader 

should be aware that some sections of the visibility rule still refer to “existing stationary 

facilities.” For purposes of the attribution discussion in this paper, these terms are 

interchangeable. 

In 1999, EPA added two new sections to the visibility rule to address regional haze (40 CFR 

51.308 and 51.309). Pollutants causing regional haze may be transported hundreds of miles, and 

therefore, regional haze must be addressed as a broader regional issue. The 1980 visibility rule 

focused on direct visibility impacts of an individual source or small group of sources. The 1999 

revisions are commonly referred to as the regional haze rule, although the 1999 rule incorporates 

the earlier requirements for BART as well as the new regional haze provisions. 

To remedy RAVI, the regulations outline a process to identify and control emissions from

sources that are directly impacting visibility at specific Class I areas (40 CFR 51.302). Three 

primary steps in this process are: 

1. The Federal land manager certifies impairment; 

2. The state identifies existing sources that cause or contribute to the visibility 

impairment; and 

3 
3. The state performs a BART analysis to determine what controls, if any, are required 

on any existing source that meets the BART criteria and has been identified as 

contributing to the impairment. 

Attribution Process 

The language of 40 CFR 51.302(c)(4)(i) provides the basic principle upon which the state 

will rely during the attribution process. That section states that the attribution must indicate each 

[BART-eligible source] “which may reasonably be anticipated to cause or contribute to 

impairment of visibility.” Whether or not the impairment is “reasonably attributable” is 

determined by “visual observation or other technique the state deems appropriate.” (40 CFR 

51.301(s)). Because the state is responsible for identifying sources, this report provides 

recommendations for the state to consider when it undertakes an attribution determination. 

Once visibility impairment is identified, RAVI is addressed on a case-by-case basis. Under 

the 1980 regulation, a state evaluates BART-eligible sources only after an FLM certifies the 

existence of visibility impairment. However, in the context of the current regional haze rule, 

states must also address BART requirements for regional haze (RH BART).3

 Several options 

exist for addressing RH BART. For example, rather than require a source-specific BART 

emission limit, a state may choose to develop a trading program, either regionally or within its 

own jurisdiction, that achieves greater reasonable progress than case-by-case RH BART. 

If a state develops a trading program, the time period to achieve the emissions reductions 

may be extended. As a result, visibility conditions at a specific Class I area initially may remain 

static or even deteriorate during the early implementation period. During this time, FLMs have 

indicated that the RAVI process may be utilized to provide steady and continuing improvement 

in visibility. Within the context of the regional haze rule, this may be an example of a 

“geographic enhancement.” As noted above, the recommendations in this report apply only to 

case-by-case applications of BART and are not intended to apply to the broader regional haze 

rule such as a market-based trading program implemented as part of the 1999 rule. 

A state may find it difficult to determine a source/receptor link for RAVI difficult when 

there are other sources located in the area, including international sources. However, the regional 

haze rule provisions do not alter the requirement to undertake the attribution assessment. 

State determines what controls, if any, are required 

After the attribution determination, the state is required to perform a BART analysis to 

determine what types of controls, if any, should be placed on the source(s) found to be 

contributing to the impairment. The following factors affect the BART determination: 

1. Available technology; 

2. Costs of compliance; 

3. Energy and non air quality environmental impacts of compliance; 

 

3

 The RH BART provision was remanded to EPA by the U.S. Court of Appeals as a result of the ruling in American

Corn Growers Association v. EPA, No. 9901348 (DC Cir. May 24, 2002) 

4 
4. Remaining useful life of the source; and, 

5. Degree of improvement that can be anticipated to result from the use of the controls. 

As noted above, this report does not provide guidance regarding state process following an 

attribution determination nor does it examine options for implementing the BART requirement. 

5 
 

6 
II. FEDERAL LAND MANAGER CERTIFICATION OF IMPAIRMENT 

The Federal land managers monitor visibility through a nationwide monitoring network, 

known as Interagency Monitoring of PROtected Visual Environments (IMPROVE). The 

IMPROVE network has recently been expanded and the FLMs 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 well as trends occurring over time to identify 

areas where visibility is not improving. 

 

The FLMs generally will use a screening process to identify Class I areas that may be 

affected by RAVI. This screening process will be influenced by the approach the state relies 

upon to address RH BART in its SIP. There are three approaches that may be used. 

1. Case-by-Case Review of RH BART under 51.308

No distinction exists between emission reductions needed to address RH BART and 

reductions to address RAVI, therefore, the BART process will address both types of visibility 

impairment. 

2. Trading Program under 51.308

The FLMs anticipate that the following screening criteria may be appropriate, but will not 

make a final decision until a 308 trading program has been developed. The screening criteria 

associated with this approach may be similar to the screening criteria associated with the trading 

program option under 51.309. However, the FLMs have indicated that the screening criteria 

ultimately selected for 51.308 will depend on how the trading program is structured, the selected 

emissions cap, and other aspects of the trading program. 

 

Potential Screening Process Criteria: 

(i) Sulfate, nitrate, organic carbon, other fine particulate, etc., levels in the Class I 

area are not decreasing.4

(ii) One or more BART-eligible sources of SO2, NOx, VOC, PM10, etc., are located 

within 100 miles of the mandatory federal Class I area. 

(iii) The BART-eligible sources identified in (ii) are not already well-controlled for 

pollutants that contribute to visibility impairment. 

3. Milestones and Backstop Trading Program under 51.309 

 

The FLMs plan to sign a Memorandum of Understanding (MOU) with the participating 

states to define the screening criteria the FLMs will use to certify impairment. 

 

4

 The decrease of a pollutant (or secondary species of that pollutant) would be measured from the beginning of the

market or emissions trading program, and such a trading program would take a long time (10 to 15 years) to reach 

the level of reduction that “meets” BART. The decrease would be tested over the first 5 to 10 years. A very quick 

time frame for reductions would negate the need for RA BART criteria. 

7 
Screening Process criteria:5

(i) Sulfate levels in the Class I area are not decreasing. 

(ii) One or more BART-eligible sources of SO2 are located within 100 miles of the 

mandatory federal Class I area. 

(iii) The BART-eligible sources identified in (ii) are not already well-controlled for 

SO2 (85% or better SO2 control for coal-fired utility boilers). 

Goal: For FLMs to complete the certification process between 2006 and 2008.6

These criteria were influenced by the design of the 309 trading program including emission 

reduction estimates, shape of the declining emission cap, inclusion of sources that were not 

BART-eligible, and inclusion of new source growth under the cap. 

Although geographic enhancements do not need to be addressed under the first approach, 

they must be addressed in the two trading programs described above because emission 

reductions may occur more gradually in the context of a trading program. The FLMs do not 

anticipate certifying impairment under these circumstances but do intend to notify the state as 

part of the SIP development process if concerns arise regarding “hot spot” impacts from sources 

that may directly affect specific Class I areas. 

Note: BART for regional haze has been addressed for SO2 under this option. Regional haze 

BART for NOx and PM will be addressed in SIP revisions that are due in 2008.

In all three cases discussed above, if the FLM determines that a certification of visibility 

impairment is necessary, the FLM will send an official Certification to the state. The 

Certification will generally include the following information: 

1. Class I area(s) impacted; 

2. Basis of certification (photographic documentation, monitoring, modeling, etc.); 

3. Type of impairment certified: plume impact, or layered or uniform haze; 

4. Pollutant(s) of interest; and, 

5. Preliminary identification of source(s) believed responsible for impact. 

FLM, State, and EPA roles in RA BART 

FLMs are responsible for certifying impairment. The Certification demonstrates the FLM’s 

determination that there is evidence of visibility impairment from one source or a small group of 

sources. 

 

5 Within the context of established regional milestones for SO2 and a backstop trading program, the FLMs have said

it is appropriate to use the following screening process in making these recommendations as part of the Certification.

Voluntary Emissions Reduction Program for Major Industrial Sources of Sulfur Dioxide in Nine Western States and 

A Backstop Trading Program. An Annex to the Report of the Grand Canyon Visibility Transport Commission. 

Submitted by the Western Regional Air Partnership to the U.S. Environmental Protection Agency, p. 61, September 

29, 2000. 

6

 This goal will not in any way restrict the ability of the FLMs to certify impairment at a later date if it is necessary 

to fulfill their statutory obligations. ibid. 

8 
Following the Certification, states have the following regulatory obligations: (1) identify 

facilities that “emit an air pollutant which may be reasonably anticipated to cause or contribute to 

any visibility impairment” in that Class I area, and (2) for sources subject to BART, the state 

must identify the BART level of control technology. If the source does not have adequate control 

in place, the state must establish a BART limit in the SIP. 

EPA has two major responsibilities for the RA BART requirement. First, in the states that do 

not have a SIP in place to address the RA BART requirements, but where the program is 

implemented through a FIP, EPA will conduct the BART analysis and establish any BART 

emission limits. Second, for the states with SIPs that include RA BART regulations, EPA will 

provide federal enforcement of state-established BART emission limits. 

9 
10 
III. THE ATTRIBUTION DETERMINATION PROCESS 

This section recommends a process for the state to follow in order to complete an attribution 

determination after receipt of a Certification from an FLM under 40 CFR 51.302(c)(1).

The Certification focuses on the existence of visibility impairment. While the FLM may 

identify sources or even sources areas that contribute to the Certification, the formal 

identification of sources is a state responsibility. 

The state should make a detailed review of the data supporting the Certification to determine 

which sources or source areas require further evaluation. If the data are insufficient to identify 

specific sources or source areas, the state may request that the FLM perform more detailed 

analyses to further substantiate the impairment set forth in the Certification. 

If the state determines sufficient information exists to proceed, the state should begin the 

process by: (1) evaluating which sources are BART-eligible, and (2) reviewing the impairment 

information provided by the FLM in support of the Certification. 

1. Evaluate which sources are BART-eligible

 

Congress and EPA established criteria to determine which sources are subject to BART. The 

categories of sources subject to BART are listed in 40 CFR 51.301, the definition of “existing 

stationary facility,” and also are included in Appendix A of this report. 

The state must confirm that the potential source or group of sources is subject to the RA 

BART process by examining the potential source emissions and the dates of operation. 

The criteria for determining if a source is BART-eligible may be complicated if a source has 

multiple units that were constructed at different times and a state may be unable to determine if a 

specific source would qualify as BART-eligible. EPA published guidelines in 1980 to aid states 

in implementing the 1980 rule.7

 In addition to the 1980 guidelines for determining BARTeligibility, EPA also has proposed guidelines that include criteria for determining if a source is 

BART-eligible.8

 These guidelines are expected to be re-proposed in 2004, promulgated in 2005 

and codified at 40 CFR Part 51 as Appendix Y. The state should refer to both sets of guidelines 

to determine if a source is BART-eligible, although the proposed guidelines are not binding until 

final promulgation occurs. 

When using the applicability criteria in Appendix Y, the state should look for information 

readily available from existing state data such as permitting history, emission inventory, or other 

similar databases. 

 

7

 U.S. Environmental Protection Agency, Guidelines for Determining Best Available Retrofit Technology for Coalfired Power plans and Other Existing Stationary Facilities, EPA-450/3-80-009(b), Office of Air Quality Planning

and Standards, Research Triangle Park, N.D., November 1980 (1980 BART Guidelines). 8

 66 FR 38108 Proposed Guidelines for Best Available Retrofit Technology (BART) (July 20, 2001). EPA will repropose these guidelines as a result of the remand in American Corn Growers v. EPA. 

11 
1. If a database of Potential To Emit (PTE) is not available, state emission inventories 

can be a useful screening tool to determine whether a source meets the size criteria 

(for example, identify all sources with emissions greater than 100 tons/year of 

visibility impairing pollutants). Operating permit applications may also contain 

information about the PTE of a source, or individual units within a source. 

2. State business records may be useful to determine when the facility was constructed 

or when it commenced operation. Newspaper article searches or a detailed historical 

review of each source may also provide useful information. 

3. The state should require the source to provide information regarding the construction 

dates of individual emission units. 

4. Institutional memory within the air agency can be invaluable if records of

construction dates of major emission units are not available, although memories will 

not withstand legal challenges like hard documentary data. 

5. New Source Review permitting records may be useful to identify new units that were

constructed after 1977, determine the PTE of the source, or determine if 

reconstruction has occurred. (Note: the draft guidelines in Appendix Y state that 

modifications at a source do not affect applicability 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 state should look in the vicinity of all the sources 

suspected of causing or contributing to the impairment identified in the Certification. If no 

BART-eligible sources exist, an attribution assessment is unnecessary. 

2. Review Support Information in the FLM Certification 

Initially, the state should acquire all the supporting information the FLM used in the 

Certification and independently evaluate the data. This initial review will help the state 

determine if the information is sufficient to support a reasonable attribution determination. 

The state should consider the type of impairment in the Certification: (a) plume impact 

visibility impairment, (b) uniform haze visibility impairment, or (c) layered haze visibility 

impairment: 

 

(a) Plume impact is the impairment addressed by the original visibility protection 

program under which the state must make a reasonable attribution 

determination before proceeding to the BART analysis (40 CFR 51.301-

51.307). 

(b) In some instances, uniform haze may be thought to be source-specific haze 

from a BART-eligible source. If a state can successfully demonstrate there is a 

source emitting any air pollutant that may reasonably be anticipated to cause or 

contribute to any impairment of visibility, the state should consider that portion 

of the uniform haze to be impact from the identified source(s) and, therefore, 

consider the source to be subject to BART. 

(c) The visibility impairment may also be defined as layered haze, a condition that 

results when aerosols are “trapped” under stagnant air mass conditions.

12 
Once the FLM has issued a Certification, the responsibility for the attribution assessment 

shifts to the state. If a state does attribute impairment to a source, the state must be able to defend 

its finding that one or more BART-eligible sources did cause or contribute to visibility 

impairment in the Class I area. However, the Ninth Circuit Court of Appeals established a low 

threshold for unacceptable visibility impairment.9

3. Evaluate Existing Data not included in the Certification

When analyzing supporting data, the state should determine if additional information exists 

that was not available to the FLM. Examples include special project camera studies or ambient 

monitoring data collected by the state or local air pollution control agency, the potential or actual 

PSD permit applicant,10 or the university. In certain situations, another agency may have

previously collected information that could be used in an attribution determination.11 These data 

should be reviewed to determine whether they support the FLM Certification. 

To conclude this portion of the attribution process, the state may wish to prepare a report that 

summarizes its initial evaluation of the Certification. The purpose of the report is to carefully 

document the state’s findings and conclusions about its decisions. The report would address two 

questions: 

First, the report would assess whether any BART-eligible source(s) exist that potentially 

contributed to visibility impairment as described in the Certification. The report would contain a 

preliminary determination of whether the sources are BART-eligible and, if possible, analyze 

each source’s relative contribution to the impairment (based on available source/receptor 

information). 

Second, the report would assess the impairment data. This assessment would include the 

state’s evaluation of the supporting data in the Certification and an analysis of any additional 

data used in the attribution assessment. The data gaps found in this review would be identified 

along with any recommendations for strategies to obtain the missing information. The state may 

use these recommendations to determine the next steps in the attribution process. 

If the state believes the Certification is supported by sufficient data, proceeds with an 

attribution assessment and makes a determination that the data does or does not indicate a source 

subject to BART, the attribution process is complete. However, if the state determines the data is 

insufficient to complete an attribution assessment, the evaluation process ends, and the state may 

proceed to the next step—identification of data gaps and the studies necessary to obtain this 

information. 

 

 

9

 See Central Ariz. Water Conservation Dist v. EPA, 990 F.2d 1531 (9th Cir. 1993); See also discussion in RA BART 

and RA BART-like Case Studies. 10 For example, a PSD permit applicant may be required to obtain pre-application ambient air quality information,

and that information may not have been available to or known to the FLM. 11 In Washington state, the plume of a defunct copper smelter has been traced by its arsenic deposition. If this were 

an active facility, this ground tracing of the plume could be used to support a source/receptor connection in an 

attribution determination.

13 
4. Identify data gaps and necessary studies to fill the gaps 

As part of the data review, the state should note gaps or inconsistencies in the available data. 

Examples of data gaps and inconsistencies may include: 

1. Missing photos in a sequence of photos, 

2. Poor resolution of the plume or its source in the photos, 

3. Back trajectory analyses done with a very large grid resolution or poor techniques, 

4. IMPROVE monitor data missing at critical periods, 

5. Lack of association between the source’s emissions and monitored data at the receptor, 

6. Special studies performed during a time when a source that potentially contributed to 

the impairment was not operating, 

7. Contemporaneous studies with contradictory results that cannot be explained, 

8. Ambient studies that use naturally occurring tracers and, when the suspected source(s) 

are tested, the tracers do not exist or exist at levels far below (or above) the level 

indicated by the ambient study results, 

9. Tracer studies where the tracer was not found at the anticipated receptors,

10. No explicit exploration of whether wildfire or other natural events significantly caused 

or contributed to one or more of the impairment episodes, 

11. Other differences or inconsistencies in the available data. 

Once any data gaps have been identified, the state should decide which studies are necessary 

to obtain the missing information sufficient to complete an attribution assessment. The state 

should design potential studies and determine the resource needs of those studies. The amount of 

work necessary will depend on the availability of the information and how critical the 

information is to the attribution assessment. Section IV provides technical criteria and examples 

of the technical process the state may consider at this point in the process. 

5. Consultation Process 

The WESTAR review of previous RAVI assessments demonstrated the importance of 

including all stakeholders in the design of any data collection plans or modeling protocols. 

Competing studies can be very inefficient, expensive, and time-consuming, and ultimately may 

not help the state make a final decision. 

If stakeholders are involved in the design of any data collection efforts or modeling 

protocols, disagreements may be resolved before the state or source continues with any

additional studies. The state should consider involving the following stakeholders in the 

consultation process: 

1. Affected sources 

2. Neighboring states and tribes 

3. Environmental Protection Agency 

4. Federal land managers 

5. Local environmental groups 

6. Local permitting agencies 

14 
7. Local government representatives 

6. Completion and Review of Additional Visibility Studies 

When the additional visibility studies, if any, are complete, the state should evaluate the 

resulting data. The technical staff may wish to finalize the report and make recommendations 

based on the scientific aspects of the data. 

7. Final Determination of Reasonably Attributable Visibility Impairment 

The state may reach any one of the following conclusions: 

1. The impairment certified by the FLM is reasonably attributable to the identified BARTeligible source(s) for specific pollutants; 

2. The impairment certified by the FLM is reasonably attributable to the source(s) 

identified by the FLM and additional sources not identified by the FLM for specific 

pollutants; 

3. There is inadequate data to support a determination that the impairment is due to the 

source(s) identified by the FLM; 

4. The impairment is reasonably attributable to other adjacent BART-eligible sources for 

specific pollutants; or 

5. The impairment certified by the FLM is not reasonably attributable to a BART-eligible 

source. 

15 
16 
IV. GENERAL PRINCIPLES AND CRITERIA 

This section provides general principles and technical criteria for the state to consider after 

receipt of an FLM Certification. After receipt of such a Certification, the state must determine 

whether BART-eligible sources “emit any air pollutant which may reasonably be anticipated to 

cause or contribute to any visibility impairment in any” Class I area. While these principles and 

technical criteria should generally be useful and applicable, each state must decide what is 

required to support its individual determination. 

Part A contains general principles to guide the development of a conceptual framework for 

the attribution assessment process. Part B contains evaluation criteria to guide the decisions 

regarding a technical framework for the attribution assessment process. 

Conceptually, the statutory framework for an attribution determination (“may reasonably be 

anticipated to cause or contribute to visibility impairment”) should be the general principle 

guiding the attribution process. EPA maintains, and the Ninth Circuit agreed, that an affirmative 

attribution decision is possible even with considerable uncertainty and a low triggering threshold. 

However, each state should decide individually what is required to support its determination. 

A. General Principles of the Attribution Process

Attribution process criteria address factors likely to influence the performance of the state 

attribution assessment. These criteria provide parameters to define and implement the attribution 

assessment process given resource constraints, legal considerations, administrative 

decisionmaking requirements, and other relevant factors. The general principles include the 

following: 

1. Whenever possible, an attribution assessment should be a collaborative process that 

relies on existing data with a minimum of additional analysis (see section III). If 

supplemental data are needed, field studies should be designed in a collaborative 

process between affected states and tribes, identified sources, Federal land managers, 

EPA, and the general public. Past experience has shown that competing technical 

studies often result in an unnecessarily expensive and unduly complicated process. 

2. Attribution assessments should be technically and legally defensible. 

3. Attribution assessments should be accomplished at a reasonable cost and within a 

reasonable time frame. 

4. Attribution assessments should be no more complex than necessary, recognizing that 

the circumstances surrounding a Certification may vary greatly. State or tribal agency 

staff should be capable of performing the attribution assessment and making the final 

determination, although contractors may be used for certain types of modeling or 

monitoring. 

5. Reasonably attributable visibility impairment can only be identified if a source/receptor 

17 
links a potentially BART-eligible source or small group of sources to a Class I area. 

B. Technical Criteria 

The technical criteria address the appropriateness of available analytical techniques from a 

scientific perspective. The rule defines visibility impairment to mean “any humanly perceptible 

change in visibility (light extinction, visual range, contrast, coloration) from that which would 

have existed under natural conditions.” 

The technical criteria include the following: 

1. The BART source must emit an air pollutant that may reasonably be anticipated to 

cause or contribute to any of the impairment. The visibility-impairing pollutants of 

concern must be identified. 

2. The attribution assessment should address the unique visibility impairment in the FLM 

Certification for the Class I area. Some factors to consider include: 

a. Duration: source’s length of effect on visibility per episode;12

b. Frequency: how often episodes of impairment occur; 

 

c. Geographic extent: how much of the Class I area is affected by the impairment; 

d. Magnitude: how much visibility impairment is due to the source’s emissions; and 

e. Time of occurrence: including time of day and time of year. 

These factors need to be considered together, because they affect each other. An 

infrequent occurrence of a large magnitude episode may meet the criteria. A frequent 

occurrence of a small magnitude episode may also meet the criteria. The FLM may 

provide information about these criteria in the Certification, and the state should review 

this information as a starting point for its assessment. The state may consider other 

factors and data, as appropriate. 

3. The attribution assessment should identify the distance from the source to the Class I 

area. This distance will affect the choice of tools appropriate for characterizing the 

specific source’s impact on visibility impairment. 

4. To the extent possible, the attribution assessment should be quantitative. Under certain 

circumstances, qualitative information, such as photographs or time-lapse video of 

distinct plumes or source-specific haze events, may be adequate. 

5. The state should use as many approaches or indicators of impairment as practicable 

12 Based on previous cases, most impairment episodes are relatively short—lasting one to several hours—which may 

affect monitoring and other assessment techniques.

18 
rather than relying on a single method. The assessment may rely on air monitoring and 

modeling techniques and other supporting scientific data. Consistency between source 

and observational techniques strengthens the analysis.13 

6. The state should consider the level of uncertainty in the assessment. 

7. EPA guideline models should be used whenever practicable. When other models are 

used, additional technical discussions with EPA may be necessary. 

C. Examples of the Attribution Process

The state should consult this section after evaluation of the FLM Certification. At this point, 

the state will already have decided what gaps need to be filled to complete the attribution 

assessment. 

The recommendations in this report recognize that each attribution determination will be 

unique. Because an attribution determination is a fact-specific and individual determination, it is 

not possible to recommended a single technical approach for a state to follow. A combination of 

monitoring and modeling techniques is usually appropriate, but instead of attempting to cover all 

possible combinations of techniques, this report provides five selected scenarios. The general 

principles and technical criteria identified in sections A and B are incorporated into these 

scenarios. The goal is to provide the state with references for use when it is creating its own 

individualized technical procedure. 

In addition to the scenarios, this report provides detailed tables and narrative descriptions of 

techniques that may be considered and/or substituted for the techniques in the scenarios (see 

Section V). 

Scenario 1: Limited data/one source 

Data input: Small amount of existing data (i.e., one IMPROVE site with data for 2-3 years) 

Evidence of “local” impact. 

Limited meteorological data. 

Where it is likely that one major source contributes to impairment, a combination of the 

following techniques is suggested: 

1. Examine IMPROVE data, including quality assurance 

2. Look at extinction budget to identify visibility-impairing pollutants 

3. Perform some analysis of when the episodes are occurring 

4. Perform a simple back trajectory analysis using a method such as HYSPLIT 

5. Look at relationships between particulate species 

6. Examine source emissions data for correlations with ambient monitoring 

7. Perform dispersion model based on data and capabilities such as VISCREEN or 

CALPUFF Lite 

 

13 WESTAR Council, RA BART and RA BART-like Case Studies, June 2001. 

19 
8. Examine other data such as source owner data, deposition data, or photographic 

evidence 

The results of this initial analysis may not always be conclusive. This level of review may be 

adequate if a source/receptor relationship can be identified. However, if the results are 

inconclusive, more data and/or more refined analyses may be necessary and may help the state 

reach an attribution determination. The state should consider how the available data and choice 

of techniques might affect its ability to assess the effectiveness of the controls in remedying the 

impairment. 

It may be efficient to look ahead to the data and analytical needs of a potential BART 

analysis. For example, the state may wish to use a more refined model that would be useful for 

both attribution and remedy assessment. 

 

Assuming there is a two-year time period14 to collect data and analyze additional information, 

the following techniques also can be considered: 

1. Better source characterization, including measurement of emissions of trace elements 

(source profiles) for use in CMB modeling 

2. Met monitoring or modeling 

3. Camera site, possibly with time-lapse video 

4. Additional aerosol monitoring, episodic or saturation 

5. In plume trajectory by aircraft, if available 

6. Fine time-resolved optical monitoring, such as nephelometer, transmissometer, 

aethelometer combined with pollutant monitoring (e.g., SO2, NOx, real time PM) for 

monitoring of episodes 

7. More refined chemical visibility model, such as CALPUFF 

8. Repeat initial techniques with new data 

The technical criteria are listed below, followed by techniques that may be used to obtain results 

about the criteria. 

1. The impairment must be related to emissions from specific sources. The visibilityimpairing pollutants of concern should be identified. 

Techniques: Back trajectory, species relationships, relationship between source 

emissions and ambient monitoring, dispersion model refined by camera, aerosol, in 

plume, optical monitoring, and refined dispersion models. 

2. The attribution assessment must address the unique visibility impairment certified by 

 

14 The 1999 regional haze rule revised the requirements for general plan requirements for visibility protection. As a 

result, plan revisions are required once every five years, rather than the Long Term Strategy review requirement of

every three years. If an FLM certifies RAVI at least 6 months prior to a plan revision, section 51.302 requires that

the State Plan revision address such Certifications. Given this 5-year cycle, we have presumed for this report that an

attribution analysis should take about two years to complete in order to allow time for the BART engineering

analysis, if needed. 

20 
the FLM for the Class I area. Some factors to consider include: 

a. Duration: source’s length of effect per episode 

Techniques: Monitoring, dispersion model, back trajectory, camera 

b. Frequency: how often the impairment occurs 

Techniques: Monitoring, dispersion model, back trajectory, camera 

c. Geographic extent: how much of the Class I area is impaired 

Techniques: Monitoring, dispersion model, additional data on deposition and other 

studies 

d. Magnitude: how much impairment is due to the source 

Techniques: Dispersion model, receptor model 

e. Time of occurrence 

Techniques: Monitoring, dispersion model, back trajectory, camera 

3. Uncertainty of results: Each analytical method will have its own level of uncertainty. 

These individual uncertainties should be kept in mind as outputs are compared within 

the overall assessment. If the results of different techniques are the same or similar 

(within the uncertainties of the techniques), then the overall level of uncertainty is likely 

to decrease.

Scenario 2: Moderate data/multiple sources 

Data input: Moderate amount of existing data (i.e., one IMPROVE site with data for six or 

more years)

Evidence of an increasing trend in sulfate 

Meteorological data likely from several stations 

Assuming the Certification identifies multiple BART sources of different types within a 100-

mile radius, a combination of the following techniques is suggested: 

1. Examine IMPROVE data, including quality assurance 

2. Look at extinction budget to identify visibility-impairing pollutants 

3. Perform some analysis of when the episodes are occurring 

4. Perform multiple back trajectory analyses using a method such as HYSPLIT 

5. Look at relationships between particulate species 

6. Examine source emissions data for correlations with ambient monitoring 

7. Perform dispersion model based on data and capabilities such as CALMET/CALPUFF 

8. Examine other data such as source owner data, deposition data, or photographic 

evidence 

9. Wind fields/Synoptic analyses 

10. Comparison of different episodes 

11. UNMIX, PMF and/or CMB 

21 
12. Analysis of any regional modeling already conducted, such as CMAQ 

13. Long term visual monitoring, such as camera data or transmissometer data, compared to 

met data to identify quadrants of concern 

The results of this initial analysis may not be conclusive. This level of review may be 

adequate if a source/receptor relationship can be identified. 

However, if the results are inconclusive, more data and/or more refined analyses may be 

necessary and may help the state reach an attribution determination. The state should consider 

how the available data might affect the ability to assess the effectiveness of the controls in 

remedying the impairment. It may be efficient to look ahead to the data and analytical needs of a 

potential BART analysis. For example, the state may wish to use a more refined model that 

would be useful for both attribution and remedy assessment. 

 

Assuming there is a two-year time period to collect data and analyze additional information, the 

following techniques also can be considered: 

1. Emissions inventory 

2. Analysis of a nested domain within the regional model 

3. Source profiles (natural tracers) 

4. Additional source measurements, such as stack testing 

5. Met monitoring or modeling 

6. Camera 

7. Additional aerosol monitoring, episodic or saturation 

8. Monitoring to measure additional parameters, such as precursors, ammonia and 

oxidants 

9. In plume trajectory by aircraft, if available, to characterize plume chemistry 

10. Fine time-resolved optical monitoring, such as nephelometer, transmissometer, 

aethelometer combined with pollutant monitoring (e.g., SO2, NOx, real time PM) for 

monitoring episodes. 

11. Repeat initial techniques with new data 

The technical criteria are listed below, followed by techniques that may be used to obtain results 

about the criteria. 

1. The impairment must be related to emissions from specific sources. The visibilityimpairing pollutants of concern should be identified. 

Techniques: Back trajectory, species relationships, relationship between source 

emissions and ambient monitoring, dispersion model refined by camera, aerosol, in 

plume, optical monitoring, and refined dispersion models. 

2. The attribution assessment must address the unique visibility impairment certified by 

the FLM for the Class I area. Some factors to consider include: 

a. Duration: each source’s length of effect per episode 

22 
Techniques: Monitoring, dispersion model, back trajectory, camera 

b. Frequency: how often the impairment occurs by source 

Techniques: Monitoring, dispersion model, back trajectory, receptor model, camera 

c. Geographic extent: how much of the Class I area is impaired 

Techniques: Monitoring, dispersion model, additional data on deposition and other 

studies 

d. Magnitude: how much impairment is due to each individual source 

Techniques: Dispersion model, receptor model 

e. Time of occurrence 

Techniques: Monitoring, dispersion model, back trajectory, camera 

Scenario 3: No IMPROVE data, Certification by modeling evidence 

Data input: Detailed modeling of a source and specific visibility impairment using a 

CALPUFF run, or detailed (nested) run of regional model. 

Detailed emissions data and meteorological data were input to the model. 

No IMPROVE data available for this specific Class I area (monitoring may be at a 

“representative site”) 

Some optical data, photographic data, and limited aerosol data from other 

networks 

Assuming the Certification points to a specific source, a combination of the following techniques 

is suggested: 

1. Examine IMPROVE data for any nearby Class I areas (especially those included in the 

modeling domain) to better understand the regional conditions and compare with model 

outputs of the unique effect 

2. Review the model’s outputs on “high impact” days and compare with actual 

meteorological data of the area (to confirm transport, inversions, or other aspects of the 

model which may create the unique impact) 

3. Review source emissions data used in the model 

4. Review other monitoring data (optical measurements, deposition data, ozone data, etc.) 

to collaborate model predictions 

5. Examine any photographic evidence 

The results of this initial analysis may not always be conclusive. This level of review may be 

adequate if a source/receptor relationship can be identified. Because no visibility-specific particle 

monitoring is available in this case, the key to attribution is to determine that the source 

emissions are indeed reaching the Class I area on days when impairment exists. If the results are 

inconclusive, more data and/or more refined analyses may be necessary and may help the state 

reach an attribution determination. The state should consider if the available data and modeling 

information supplied with this Certification could be used to determine the effectiveness of the 

23 
controls in remedying the impairment. It may be efficient to look ahead to the data and analytical 

needs of a potential BART analysis if additional or different modeling will be necessary. 

Additional data collection and analyses that might be considered: 

1. Better source profiles or newer emissions information 

2. Met monitoring or modeling 

3. Camera 

4. New aerosol monitoring (episodic or saturation)

5. In plume trajectory by aircraft, if available 

6. Repeat initial analytical techniques with new data 

The technical criteria are listed below, followed by techniques that may be used to obtain results 

about the criteria. 

1. The impairment must be related to emissions from specific sources. The visibilityimpairing pollutants of concern should be identified. 

Techniques: Confirm model inputs, compare with any new particle monitoring at Class I 

area. Examine performance of the model, and perform uncertainty analyses. 

2. The attribution assessment must address the unique visibility impairment certified by the 

FLM for the Class I area. Some factors to consider include: 

a. Duration: source’s length of effect per episode 

Techniques: Monitoring, dispersion model, back trajectory, camera 

b. Frequency: how often the impairment occurs 

Techniques: Monitoring, dispersion model, back trajectory, camera 

c. Geographic extent: how much of the Class I area is impaired 

Techniques: New monitoring and examination of dispersion model outputs, 

additional data on deposition and other studies 

d. Magnitude: how much impairment is due to the source 

Techniques: Dispersion model 

e. Time of occurrence 

Techniques: Monitoring, dispersion model, back trajectory, camera 

Scenario 4: Direct Photographic Evidence 

Data input: The FLM certified impairment in a wilderness area based on photographic 

evidence. Photographs taken over a period of two years showed a distinct haze 

in a valley located in the wilderness area when the wind is from the east. A 

series of photographs during two episodes showed a distinct plume that 

24 
originates at an existing stationary source constructed in 1965 and located ten 

miles east of the wilderness area. The photographic series showed that the 

plume traveled into the wilderness area. 

Aerial photos during one episode also show a distinct plume that travels into 

the wilderness area. The wilderness area does not have an IMPROVE site. A 

Class I area located 50 miles to the north has an IMPROVE site that was

representative for the area. This monitoring site does not show decreased 

visibility on the days when haze was photographed in the wilderness valley. 

Assuming the Certification identifies one BART source, the following steps are suggested: 

1. Review the photographic evidence and determine whether the photographs show a clear 

connection between the source and the haze documented in the wilderness area. 

In this example, the photographic evidence showed a clear connection between the 

source and the haze in the wilderness area. Qualitative information, such as 

photographic evidence that establishes a source/receptor link, is allowed under EPA 

regulations that define reasonable attribution as determined by “visual observation or 

other technique the State deems appropriate.” (40 CFR 51.301(s)). 

The results of this initial analysis may not always be conclusive. If the photographic 

evidence is not compelling, the state may reach a different conclusion. The state may determine 

that the impairment, as documented by the FLM, was not reasonably attributable to the source 

identified in the Certification. The FLM would then need to gather additional information to 

support a Certification. Alternatively, if the state determines that the source may be causing the 

haze but the qualitative evidence is not quite sufficient to determine attribution, the state could 

initiate a data collection effort to provide better information regarding visibility impairment at 

the Class I area. Such techniques may include: 

1. Better source characterization, including measurement of emissions of trace elements 

(source profiles) for use in CMB modeling 

2. Met monitoring or modeling 

3. Additional aerosol monitoring (episodic or saturation) 

4. In plume trajectory by aircraft, if available 

5. Fine time-resolved optical monitoring, such as nephelometer, transmissometer, or 

aethelometer combined with pollutant monitoring (e.g., SO2, NOx, real time PM) for 

monitoring of episodes. 

6. More refined chemical visibility model, such as CALPUFF 

The technical criteria are listed below, followed by techniques that may be used to obtain results 

about the criteria. 

1. The impairment must be related to emissions from specific sources. The visibilityimpairing pollutants of concern should be identified. 

Techniques: Back trajectory, species relationships, relationship between source 

emissions and ambient monitoring, dispersion model refined by camera, aerosol, in 

25 
plume, optical monitoring, and refined dispersion models. 

2. The attribution assessment must address the unique visibility impairment certified by 

the FLM for the Class I area. Some factors to consider include: 

a. Duration: source’s length of effect per episode 

Techniques: Monitoring, dispersion model, back trajectory, camera 

b. Frequency: how often the impairment occurs 

Techniques: Monitoring, dispersion model, back trajectory, camera 

c. Geographic extent: how much of the Class I area is impaired 

Techniques: Monitoring, dispersion model, additional data on deposition and other 

studies 

d. Magnitude: how much impairment is due to the source 

Techniques: Dispersion model, receptor model 

e. Time of occurrence 

Techniques: Monitoring, dispersion model, back trajectory, camera 

3. Uncertainty of results: Each analytical method will have its own level of uncertainty. 

These individual uncertainties should be kept in mind as outputs are compared within 

the overall assessment. If the results of different techniques are the same or similar 

(within the uncertainties of the techniques), then the overall level of uncertainty is likely 

to decrease.

The final step in the attribution process scenario would be to verify that the source was 

operating on the days when the haze was observed in the area. The state should also determine if 

the source was experiencing unusual upset conditions during the times identified. In this 

example, the source was determined to have been operating normally. The state would then issue 

a determination that the visibility impairment at the Class I area was reasonably attributable to 

the existing stationary facility. 

Scenario 5: Data Rich 

Data input: A large special visibility study recently was conducted. 

Four months of data spanning two seasons was collected including: 

1. At one “receptor” site in a Class I area there were multiple meteorological, optical, and

particulate samplers including extensive measurements of particle compositions, size 

distributions, scattering, absorption, light extinction, ions, oxidants, relative humidity, 

temperature, vertical wind profiles, SO2, photographs, and concentrations of four unique 

tracers released from four different sources of interest. There were co-located samplers 

measuring several parameters in more than one way. There are at least some one, six, 

and twelve-hour particle measurements in addition to twenty-four hour samples. 

26 
2. This receptor site has been an IMPROVE site for several years and these data are also

available. 

3. At thirty-five other sites in the region, called “satellite” sites there was an IMPROVE 

Module-A sampler taking daily twenty-four hour samples which were analyzed for fine 

mass, S, soil elements, trace metals, and elemental H from which organics can be 

estimated. The unique tracers were also measured at many of these sites. 

4. Aircraft sampling of plumes from source(s) of interest was conducted. 

5. An extensive current emissions inventory was created. 

6. Wind profilers were deployed at two to three sites in addition to the receptor site. 

7. Measurements of the chemical composition of resuspended local dust, smoke from

burning local fuels, and emissions from local point and area sources of interest were 

collected in order to create “source profiles” to be used in receptor modeling. 

Assuming the certification identifies a BART source within 100 miles of the Class I area 

from which a unique tracer was released, a combination of the following techniques is 

suggested: 

1. Examine fine particle data, including quality assurance. Use the collocated data to 

assess accuracy and precision. The one, six, and twelve-hour data should average up to 

match the twenty-four hour data and if reasonable, be used to examine the diurnal 

cycles in the fine particle concentrations. 

2. Look at the extinction budget to identify visibility-impairing pollutants. Because size 

distributions were measured, the extinction budget can be estimated from Mie scattering 

calculations as well as by using simple techniques that assume bulk scattering and 

absorption efficiencies. Check to see if measured scattering plus absorption add up to 

the measured and reconstructed extinction. 

3. Compare the special study data to historical IMPROVE and archived meteorological 

data to determine the representativeness of the study period. 

4. Perform some analysis of when the episodes are occurring. EOF analysis can be helpful 

to summarize the massive data set. Use the photographs to create a time-lapse 

visualization of the scene at the receptor site. 

5. Perform back trajectory analyses using HYSPLIT, CAPITA Monte Carlo or ATAD. 

Examine whether the trajectories change substantially when the study’s wind-profiler 

data are included. Determine whether trajectories are consistent with tracer 

concentrations. 

6. Look at relationships between particulate species (factor analysis) to see if they identify 

source types. 

7. Look at the spatial and temporal patterns of trace elements and the major constituents of 

the fine mass. This may suggest dominant source areas and transport patterns for 

different source types. Use EOF analysis to determine the patterns that explain most of 

the covariance in the data. Check to see how well these are reconciled with the back 

trajectory modeling and the deterministic modeling. Check to see if the same dominant 

sources were indicated. 

8. Examine source emissions data for correlations with ambient monitoring. 

9. Perform dispersion model such as CALMET/CALPUFF. 

27 
10. Analyze wind fields, synoptic conditions, and satellite photos. Check to see if they were 

consistent with more sophisticated meteorological modeling. Look for unusual 

conditions such as wild fires, hurricanes, stagnation episodes, etc. Look to see if 

modeled and observed cloud patterns were comparable. 

 11. Compare the meteorological and chemical characteristics of different episodes 

12. UNMIX, PMF and CMB can help determine major source types and when they were 

important. 

If, at this point, similar source/receptor relationships have been identified using several 

different techniques, this level of review is adequate. If the results are inconclusive, and there are 

differing points of view about the frequency, duration, or significance of the attribution to the 

BART-eligible source, more analyses may be necessary. Often in a large study, measurements 

are made, but not immediately analyzed in the lab due to cost. If this is the case, more samples 

could be analyzed. It is unlikely that any additional field monitoring would be required. 

The technical criteria are listed below, followed by techniques that may be used to obtain 

results about the criteria.

1. The impairment must be related to emissions from specific sources. The visibilityimpairing pollutants of concern should be identified. 

Techniques: Reconstructed particle mass and light extinction including examination of 

the reconstructions in different size ranges and at different sites in the region, analysis 

of responses of light scattering to relative humidity, back trajectory analyses, 

examination of inter-species relationships compared to measured source profiles, 

dispersion modeling with sophisticated models such as REMSAD and CMAQ, analysis 

of wind fields and dispersion by comparison to measured tracer concentrations, 

computer animation of spatial patterns of species of interest, use of receptor models 

such as TMBR, DMB, and TAGIT that utilize unique tracer information, or other 

receptor models such as CMB, UNMIX, and PMF that do not require tracer 

information, but can use it. When so many different models can be used, model 

reconciliation is usually a part of a data-rich scenario. 

2. The attribution assessment must address the unique visibility impairment certified by 

the FLM for the Class I area. Some factors to consider include: 

a. Duration: each source’s length of effect per episode 

Techniques: Monitoring, dispersion model, back trajectory, camera 

b. Frequency: how often the impairment occurs by source 

Techniques: Monitoring, dispersion model, back trajectory, receptor model, camera 

c. Geographic extent: how much of the Class I area is impaired 

Techniques: Monitoring, dispersion model, analysis of spatial patterns using data 

from the satellite sites. 

28 
d. Magnitude: how much impairment is due to each individual source 

Techniques: Dispersion model, receptor model 

e. Time of occurrence 

Techniques: Monitoring, dispersion model, back trajectory, camera 

3. Uncertainty of results: In this case, the ability of a model to predict the observed tracer 

concentrations is an indicator of the model’s uncertainty. 

29 
30 
V. TECHNIQUES 

A. Monitoring 

Introduction 

This section describes a variety of ambient air monitoring methods that, if appropriate, 

might be used to support an attribution analysis. The methods described include those most 

commonly used in pollution studies or ambient monitoring programs and should not be 

considered an exhaustive list of potential methods. Methods include, IMPROVE, filter based 

aerosol, continuous aerosol (includes optical methods such as the nephelometer), continuous gas 

and canister sampling, transmissometer, scene (includes film, video, digital), and tracer or 

aircraft methods. 

Several of the methods described are currently in use as a part of national, state, local, tribal, 

or private ambient monitoring networks. These sites are generally located in urban areas, but 

those near the area of study could be used in the attribution analysis thereby reducing the cost of 

monitoring. 

The IMPROVE network is designed to assess visibility in Class I areas and routinely 

measure visibility impairing pollutants. These sites offer value to the attribution analysis if they 

are located in the area of study. 

The RA BART case studies show additional examples of the methods used during source 

attribution studies. The case studies also show that methods, other than ambient monitoring, may 

be used to support the analysis. Existing programs such as CASTNET (dry deposition network), 

surface water deposition studies, or snow deposition studies may provide additional data for the 

attribution analysis. 

Although not specifically listed as a monitoring technique, meteorological monitoring is an 

important element the attribution analysis. Collection of meteorological data can range from

simple wind, temperature, and relative humidity measurement to an array of acoustic wind 

profilers. The complexity of the meteorological monitoring program depends on data needs and 

the availability of existing data. As with ambient monitoring, meteorological data may be 

available at sites located near the study area and offers reduced monitoring cost. 

1. IMPROVE

Overview: The Interagency Monitoring of PROtected Visual Environments (IMPROVE) 

program is a cooperative measurement effort governed by a steering committee composed of 

representatives from Federal and regional-state organizations. The IMPROVE monitoring 

program was established in 1985 to aid the creation of Federal and State implementation plans 

for the protection of visibility in Class I areas (156 national parks and wilderness areas) as 

stipulated in the 1977 amendments to the Clean Air Act. The objectives of IMPROVE are to: (1) 

establish current visibility and aerosol conditions in mandatory class I areas; (2) identify 

chemical species and emission sources responsible for existing man-made visibility impairment; 

31 
(3) document long-term trends for assessing progress towards the national visibility goal; and (4) 

with the enactment of the regional haze rule, provide regional haze monitoring representing all 

visibility-protected federal class I areas where practical. 

Magnitude: Possible when used in conjunction with appropriate analytical techniques. 

Frequency: Possible when used in conjunction with appropriate analytical techniques; Limited 

by twenty-four hour sample integration, and one-in-three day sampling frequency. 

Duration: Possible when used in conjunction with appropriate analytical techniques; Limited by 

24 hour sample integration, and one-in-three day sampling frequency. 

Principle: Twenty-four hour integrated filter-based ambient monitor; Gravimetric analysis for 

PM2.5 (Module D) and PM10); S from Particle Induced X-ray Emission (PIXE); NO3 from ion 

chromatography (denuded nylon filter from Module C); Organic and elemental carbon from

Thermal Optical Reflectance (TOR); H from Proton Elastic Scattering (PESA). 

Uncertainty: All elemental S if from sulfate; All sulfate is ammonium sulfate; NO3 (Denuder 

efficiency is close to 100%. All nitrate is from ammonium nitrate); 

Average organic molecule is 70% carbon; Carbon (organic and elemental) is defined by the 

analytical method; Fine soil based on elemental composition; Course mass (PM10 – PM2.5) 

consists only of insoluble soil particles. 

Strengths: Regulatory indicator for regional haze rule; Long term data record in or near many 

federal Class I areas; Extensive network currently in place. 

Limitations: Integrated twenty-four hour sample; one-in-three day sampling interval; Nitrate 

losses due to volatilization from filter; Not capable of distinguishing between primary particulate 

and atmospherically transformed particulate. 

Level of Expertise Required: Standard operating procedures available for routine operation and 

maintenance; Chemical analysis must be conducted by appropriate laboratory. 

Regulatory Context: Regional Haze rule; Included in SIP Visibility Plan 

2. FILTER-BASED AEROSOL

Overview: Filter-based aerosol monitoring is used to identify chemical species and obtain 

concentration measurements of atmospheric constituents that contribute to visibility impairment. 

Primary techniques include filter-based aerosol samplers that collect samples on various 

substrates in various size ranges such as PM2.5 or PM10. Aerosol monitoring can provide fine 

mass concentration, course mass concentration, optical absorption, major and trace elements, 

organic and elemental carbon, and sulfate, nitrate, and chloride ions. A variety of methods are 

available to conduct filter based aerosol monitoring. Many methods are approved as an EPA 

reference method, while some are not, but may offer variability that the reference method does 

not. 

32 
Magnitude: Possible when used in conjunction with appropriate analytical techniques. 

Frequency: Possible when used in conjunction with appropriate analytical techniques; Limited 

by 24-hour sample integration and sampling frequency (daily sampling is possible depending on 

instrument selected). 

Duration: Possible when used in conjunction with appropriate analytical techniques; Limited by 

24-hour sample integration and sampling frequency (daily sampling is possible depending on 

instrument selected). 

Principle: The methods used for analyses of these filter media include gravimetry (electromicrobalance) for mass; X-ray fluorescence (XRF) and particle induced X-ray emission (PIXE) 

for trace elements; Ion chromatography (IC) for anions and selected cations; Controlledcombustion for carbon; Gas chromatography/mass spectroscopy (GC/MS) for semi-volatile 

organic particles; Special measurement needs may include determining particle size and 

morphology through optical and/or electron microscopy. 

Strengths: Large network of urban monitoring available; Filter based sampling allows for a 

variety of chemical/elemental analysis. 

Limitations: Integrated twenty-four hour sample; Generally operated on one-in-three or one-insix day sampling interval (daily sampling is possible depending on instrument selected); Not 

capable of distinguishing between primary particulate and atmospherically transformed 

particulate. 

Level of Expertise Required: Standard operating procedures available for routine operation and 

maintenance; Chemical analysis must be conducted by appropriate laboratory. 

Regulatory Context: Commonly used in NAAQS/SIP compliance monitoring networks. 

3. CONTINUOUS AEROSOL 

Overview: Aerosols can be measured continuously using several different methods. Optical 

measurement of aerosols can be measured using an instrument such as a nephelometer to 

measure light scattering (bscat) or a aethelometer to measure light absorption (babs) by aerosols 

(black carbon). Continuous instruments such as TEOM or BETA can provide PM10 or PM2.5

aerosol concentration. 

Magnitude: Possible when used in conjunction with appropriate analytical techniques. 

Frequency: Possible when used in conjunction with appropriate analytical techniques; Limited 

by twenty-four hour sample integration and sampling frequency (daily sampling is possible 

depending on instrument selected). 

33 
Duration: Possible when used in conjunction with appropriate analytical techniques; Limited by 

twenty-four hour sample integration and sampling frequency (daily sampling is possible 

depending on instrument selected). 

Strengths: Continuous measurement with at least hourly time resolution; Nephelometers and 

Aethelometers are commonly used to support Class I area monitoring programs and an existing 

data record may be available in some areas. 

Limitations: Continuous aerosol measurement with methods such as TEOM and BETA are 

generally made in urban areas to support NAAQS compliance networks; Not capable of 

distinguishing between primary particulate and atmospherically transformed particulate. 

Level of Expertise Required: Standard operating procedures available for routine operation and 

maintenance. 

Regulatory Context: Commonly used in Class I area monitoring networks or urban NAAQS 

compliance networks. 

4. CONTINUOUS GASEOUS 

Overview: A variety of gaseous pollutants, such as Ozone (O3), Carbon Monoxide (CO), 

Nitrogen Dioxide (NOx), nitric oxide (NO), ammonia (NH3), hydrogen peroxide (H2O2), sulfur 

dioxide (SO2), Organics, and HAPS/TOXICS, can be measured continuously. Gaseous 

monitoring is generally conducted with instruments that continuously draw sample air and 

periodically (as frequently as once per second) analyze the sample. Canister systems collect an 

ambient air sample over a specific period of time in clean evacuated canisters. The canisters are 

then subject to subsequent analysis at a laboratory using a method such as GC/FID. This method 

is able to provide time-integrated samples from several hours to twenty-four hours or more. 

Regular checks of the flow rate, stability, reproducibility, precision, and accuracy of these 

instruments must be conducted on a regular schedule in order to ensure data quality. 

Magnitude: 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: Continuous measurement with hourly time resolution; Monitors available to identify 

variety of pollutants. 

Weaknesses/Limitations: Generally require conditioned environment and frequent performance 

checks. 

Practical Considerations: Data may be available from established urban area monitoring 

networks and some Class I area monitoring networks; Additional cost ($/year) for new sites. 

34 
Level of Expertise Required: Standard operating procedures available for routine operation and 

maintenance. 

Regulatory Context: Commonly used in urban NAAQS compliance and HAPS/TOXICS 

networks. 

5. TRANSMISSOMETER 

Overview: Transmissometers measure the amount of light transmitted through the atmosphere 

over a known distance (generally between 0.5 km and 10.0 km) between a light source of known 

intensity and a receiver. The transmission measurements are electronically converted to hourly 

averaged light extinction (bext). 

Magnitude: 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. 

Uncertainties: A transmissometer must be installed in stable locations with a clear and

unobstructed path to avoid interference with the signal. 

Strengths: Continuous measurement of bext in many Class I areas and some urban areas. 

Limitations: Not capable of identifying pollutants contributing to visibility impairment. 

Level of Expertise Required: Standard operating procedures available for routine operation and 

maintenance; Data processing/quality assurance requires high level of expertise. 

Regulatory Context: Commonly used in Class I area monitoring networks and in some urban 

areas.

6. SCENE

Overview: Scene monitoring refers to the use of still and/or time-lapse photography (including 

digital imagery) to provide a qualitative representation of visual air quality. Scene monitoring 

data quality objective recommendations are to document the appearance of scenes of interest 

under a variety of air quality and illumination conditions at different times of day and different 

seasons. Scene monitoring documents the visual condition observed at a monitoring site. The 

data collection schedule can be tailored to capture the periods when visibility impairment is most 

likely to occur at specific sites. Time-lapse movies (generally time-lapse video or super 8 mm

film) can be used at monitoring sites and during special studies to document the visual dynamics 

of a scene or source. 

Magnitude: Cannot provide a quantitative measurement of visibility impairment but can 

qualitatively illustrate various levels of visibility impairment. 

35 
Frequency: Possible depending on the method used. Time-lapse video may be able to 

demonstrate the frequency of the impairment. The use of still photography to document 

impairment frequency depends upon the number of images acquired over time. 

Duration: Possible depending on the method used. Time-lapse video may be able to demonstrate 

the impairment frequency. The use of still photography to document impairment frequency 

depends upon the number of images acquired over time. 

Uncertainties: n/a 

Strengths: Provides image/video record 

Limitations: Not capable of identifying pollutants contributing to visibility impairment. 

Level of Expertise Required: Standard operating procedures available for routine operation and 

maintenance. 

Regulatory Context: Commonly used in Class I area monitoring networks and in some urban 

areas. 

7. TRACER METHODS, LIDAR SYSTEMS, AIRCRAFT BASED MEASUREMENTS 

Overview: The methods described in this section are more specialized methods generally 

reserved for special studies as opposed to the previously described methods that are used more 

routinely. Tracer methods, lidar systems and aircraft based measurements will be described 

individually. 

Tracer Methods: 

A tracer element or compound is a substance with unique characteristics that allows positive 

identification at very low concentrations. The tracer compound of choice will vary by source 

type and composition of the plume being tracked. In general, the tracer must have very low 

natural background concentrations and ideally would have the same chemical form and 

properties as the compound being tracked. In ambient applications where use of the ideal tracer 

is not possible due to potential environmental risk, a near-substitute compound may be used. 

When used to determine potential source impacts, the chosen compound is released from a 

source stack and downwind monitors are used to detect the presence of the compound. 

Lidar Methods: 

A lidar transmits short pulses of laser light into the atmosphere. The laser beam loses light to 

scattering as it travels. At each range, some of the light is backscattered into a detector. Because 

the light takes longer to return from the more distant ranges, the time delay of the return pulses 

can be converted to the corresponding distance between the atmospheric scatterer and the lidar. 

The end result is a profile of atmospheric scattering versus distance. Analysis of this signal can 

yield information about the distribution of aerosols in the atmosphere. The amount of backscatter 

indicates the density of the scatters. This can be used to measure cloud base height or track 

36 
plumes of pollution. Other properties of the atmosphere can also be deduced from the lidar return 

signals. A frequency shift in the light because of the Doppler effect permits measurement of 

wind speeds. By detecting the amount of depolarization, one can discriminate between liquid 

droplets and nonspherical ice particles. Differential Absorption Lidar (DIAL) uses absorption, as 

evidenced by reduced backscatter from greater distances, to measure the concentration of 

atmospheric gases. A Raman lidar detects particular atmospheric components (such as water 

vapor) by measuring the wavelength-shifted return from selected molecules (NOAA).

Aircraft Based Measurements: 

Aircraft based measurement systems utilize specially equipped aircraft to make pollutant and 

meteorological measurements at various elevations throughout the study domain. The aircraft 

can be equipped with a multitude of gaseous, aerosol, optical and meteorological equipment. 

This measurement method provides the advantage of vertical profiles of various parameters, the 

ability to track point source plumes, and the ability to establish boundary conditions for future 

analytical and modeling exercises. 

References:

NOAA, Atmospheric Light Division, Environmental Technology Laboratory, 

http://www2.etl.noaa.gov/DIAL_lidar.html

U.S. Environmental Protection Agency, Visibility Monitoring Guidance (EPA-454/R-99-003), 

June 1999. 

National Research Council, Protecting Visibility in National Parks and Wilderness Areas, 

National Academy Press, Washington D.C., 1993, pp. 315-357. 

37 
38 
Table 1. Monitoring Techniques 

Criteria Monitoring Method 

IMPROVE Filter Based

Aerosol 

Continuous Aerosol Gaseous; 

Continuous 

methods, canister 

sampling, etc. 

Transmissometer Scene 

35mmfilm/8

video, dig

PollutantPM10 Yes Yes Yes No No No PM2.5 Yes Yes Yes Yes No No NOx (Site specific) No No Yes No No SO2 (Site specific) No No Yes No No Sulfate Yes Yes No No No No Nitrate Yes Yes No No No No Carbon Yes Yes No No No No Organics Yes Yes No Yes No No Other Reconstructed 

extinction 

Nephelometer - 

Bscat 

Aethelometer - Babs 

HAPS, TOXICS Total 

Extinction 

Visual 

Paramete

Visibility/Concentration ChangesMagnitude Yes Yes All Possible All Possible All Possible No Frequency Yes Yes Yes Duration Yes Yes Yes Time of Day No No 

All Possible All Possible All Possible

Yes 

Likely Part of FLM Certification?

Possible 

39 
Monitoring Techniques (continued)

PrincipalQualitative/Quantitative

Quantitative Qualitati

Strengths Reconstructed 

extinction calculation, historical record 

various chemical analysis, large network nationwide 

Continuous measurement, nephelometer commonly located in or near Class I areas 

Continuous measurement, variety of possible pollutants 

Continuous measurement, provides light extinction value, historical record 

Relatively inexpensivuncomplicaoperational requiremen

Weaknesses/ Limitations 

Fixed location in or near ClassI areas, also located in several urban areas 

Integrated 24 hour sample generally collected on onein-three schedule, commonly in urban areas 

TEOM, BETA, etc, commonly located in urban areas 

Generally require conditioned environment for proper operation, commonly located in urban areas 

Fixed location in or near ClassI areas 

Number of images limvideo requistorage and routine rev

Distinguish BART Sources?

Possible with other analysis 

Possible with otheranalysis 

No Possible with other

analysis 

No Possible wi

other analy

Practical ConsiderationsCost Moderate; varies depending on the number of instruments Low 

40 
 B. Source Modeling 

Introduction

Given the complex natural environment, the state must choose the configuration of modeling 

techniques that will provide the most information on the contributing source or sources of 

impairment within the limited resources of current technology, data, budgets, time and staff 

availability.

1. Physical Models

Physical models are those that simulate the meteorology and air quality over an area. 

Modeling relies on a numerical or analytical model to estimate particulate concentrations in 

space and time. Because of its nature and sources, particulate matter is difficult to model over all 

spatial scales. Many air quality models that are currently available were designed to be applied 

over the regional scale with grid sizes from four to forty kilometers. Modeling requires detailed 

meteorological fields and emissions inventory over the entire domain. The compilation of data 

required to run these models can require much effort and expertise. Efforts are underway by 

government agencies in the U.S. to generate and archive both emissions and estimated activity 

levels of many source types in geographical information systems. 

Numerical source-oriented models are designed to simulate atmospheric diffusion or 

dispersion and estimate concentrations at defined receptors. Numerical source models can be 

grouped as kinematic, first-order closure, or second-order closure models (Bowne and 

Lundergan, 1983). Kinematic models are the simplest both mathematically and conceptually. 

These models simplify the non-linear equations of turbulent motion, thereby permitting a closed 

analytical approximation to describe pollutant concentration (Green et al., 1980). First-order 

closure models are based on the assumption of an isotropic pollutant concentration field. 

Consequently, turbulent eddy fluxes are estimated as being proportional to the local spatial 

gradient of the transport quantities. The Eulerian grid models, Lagrangian particle models, and 

trajectory puff/plume models are included in this category. Second-order closure models involve 

a series of algorithm transformations of the equations of state, mass continuity, momentum, and 

energy by using the Boussinesque approximation and Reynold’s decomposition theory (Holton, 

1992; Stull, 1988). 

2. Spatial Scales 

The model’s applicable spatial scales play a large role meeting the analysis' objectives and 

its ability to accurately assess spatial variability. PM10 and PM2.5 concentrations modeled or 

measured at any receptor result from the complex interaction of meteorology, chemical 

transformations and emissions from nearby and distant sources. For example, a monitor located 

near an operating construction site will be impacted more by the daily construction activity than 

the surrounding area. That site may be classified as representing an area of a few tens of meters 

to no more than one kilometer depending on the size of the construction area and fugitive dust 

control measures. 

The dimensions given below are nominal rather than 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 relevant to the attribution 

problem. Modeling at the microscale is usually done by simple Gaussian plume models such as 

ISCST3. Measurements in urban areas can show considerable variations at this scale while those 

in pristine areas would not. Variations often occur when monitors are located close to a low-level 

emissions source, such as a busy roadway, construction site, within a community that uses wood 

stoves, or a short industrial stack. Fortunately, compliance monitoring site exposure criteria 

avoids microscale influences even for source-oriented monitoring sites. 

b. Middle Scale (100 to 500 m): Middle-scale monitors show significant differences between 

locations that are ~0.1 to 0.5 km apart. These differences may occur near large industrial areas 

with many different operations or near large construction sites. Monitors with middle-scale zones 

of representation are often source-oriented, used to determine the contributions from emitting 

activities with multiple, individual sources to nearby community exposure monitors. 

c. Neighborhood Scale (500 m to 4 km): Neighborhood-scale monitors do not show significant 

differences in particulate concentrations with spacing of a few kilometers. This dimension is 

often the size of emissions and modeling grids used in large urban areas for PM source 

assessment, so this zone of representation of a monitor is the only one that should be used to 

evaluate such models. Sources affecting neighborhood-scale sites typically consist of small 

individual emitters, such as clean, paved, curbed roads, uncongested traffic flow without a 

significant fraction of heavy-duty vehicles, or neighborhood use of residential heating devices 

such as fireplaces and wood stoves. 

d. Urban Scale (4 to 100 km): Urban-scale monitors show consistency among measurements 

with monitor separations of tens of kilometers. These monitors represent a mixture of particles 

from many sources within the urban complex, including those from the smaller scales. PM 

measurements at urban-scale locations are not dominated by any particular neighborhood, 

however. Urban-scale sites are often located at higher elevations and away from highly traveled 

roads, industries, and residential heating. 

e. Regional-Scale Background (100 to 1,000 km): Regional-scale background monitors show 

consistency among measurements for monitor separations of a few hundred kilometers. 

Background concentrations are often more consistent for specific chemical compounds, such as 

sulfate or nitrate, than they are for PM mass concentrations. Regional-scale PM is a combination 

of naturally-occurring aerosol from windblown dust and marine aerosol as well as particles 

generated in urban and industrial areas that may be more than 1,000 km distant. Regional-scale 

sites are best located in rural areas away from local sources, and at higher elevations. National 

parks, national wilderness areas, and many state and county parks and reserves are appropriate 

areas for regional-scale sites. Many of the IMPROVE sites characterize PM regional scale 

background in different regions of the United States. 

f. Continental-Scale Background (1,000 to 10,000 km): Continental-scale background 

monitors show little variation even when they are separated by more than 1,000 km. They are 

hundreds of kilometers from the nearest significant emitters. Though these sites measure a 

mixture of natural and diluted manmade source contributions, the manmade component is at its 

minimum expected concentration. The Jarbidge Wilderness IMPROVE site in northern Nevada 

is a good example of a continental-scale background site for particulate matter in North America. 

42 
e. Global-Scale Background (>10,000 km): Global-scale background monitors are intended to 

quantify concentrations transported between different continents as well as naturally-emitted 

particles and precursors from sea spray, volcanoes, and windblown dust. Yellow sand from

China has been detected at the Mauna Loa, HI, laboratory (Darzi and Winchester, 1982; Braaten 

and Cahill, 1986), as well as on the North American continent. Red dust from Africa’s Sahara 

desert has been detected at Mt. Yunque, Puerto Rico and over the southeastern United States. 

Other global-scale sites include McMurdo, Palmer, and Ahmundson-Scott stations in Antarctica 

(Lowenthal et al., 1996), Pt. Barrow, Alaska, and Mace Head, Ireland. 

3. Chemical Composition 

This section illustrates how the chemical composition of aerosols is an important 

consideration in the choice of particulate matter models. The knowledge of how the aerosol's 

composition varies over an area will play a key role in the attribution study design. 

The relative abundance of chemical components in the atmosphere closely reflect the 

characteristics of emission sources. Major chemical components of PM2.5 and PM10 mass in 

urban and rural areas consist of nitrate, sulfate, ammonium, carbon, geological material, sodium

chloride, and liquid water. 

Chemical compositions can vary spatially in all scales of the atmosphere and depend on 

sources surrounding the monitoring site. For example, on the continental scale, the eastern U.S. 

fine particulate chemical compositions are different than those of the western states. In the 

eastern portion of the U.S., nonurban PM2.5 is dominated by secondary sulfate, organics and 

elemental carbon (EPA, 1996). The data to support this conclusion are based on the IMPROVE 

and CASTNET networks. These networks provide a background fine-fraction aerosol database 

because the monitoring sites are primarily located in national parks and wilderness areas. 

Analysis of this network shows that the western U.S. nonurban PM2.5 aerosol is predominantly 

carbon in nature. Nitrate also contributes significantly to the fine particle mass budget 

particularly in central and coastal California. Within these generalizations, obvious departures 

will be found especially near sources such as near the ocean and urban areas where the aerosol 

will be primarily influenced by sea salt and combustion particles, respectively. 

The typical PM2.5 chemical compositions vary by season (Chow et al., 1993a; 1996a, 

Watson et al., 1997), and consist of the following major components: 

a. Organic Carbon: Organic carbon is composed of gases and particles containing 

combinations of carbon and hydrogen atoms. Organic compounds found in ambient air may also 

be associated with other elements and compounds, particularly oxygen, nitrogen, sulfur, 

halogens, and metals. Particulate organic carbon consists of hundreds, possibly thousands, of 

separate compounds (Rogge et al., 1993a). The mass concentration of organic carbon can be 

accurately measured, as can carbonate carbon (Chow et al., 1993b), but only about ten percent of

the specific organic compounds that it contains have been measured. Vehicle exhaust (Rogge et 

al., 1993b), residential and agricultural burning (Rogge et al., 1998), meat cooking (Rogge et al., 

1991), fuel combustion (Rogge et al., 1997), road dust (Rogge et al., 1993c), and particle 

formation from heavy hydrocarbon gases (Pandis et al., 1992), are the major sources of organic 

carbon in PM2.5. 

43 
b. Elemental Carbon: Elemental carbon is black, often called “soot.” Elemental carbon 

contains pure, graphitic carbon, but it also contains high molecular weight, dark-colored, 

nonvolatile organic materials such as tar, biological material (e.g., coffee), and coke. Elemental 

carbon usually accompanies organic carbon in combustion emissions, with diesel exhaust 

(Watson et al., 1994a, 1998) being the largest contributor. 

c. Sulfate: Ammonium sulfate ((NH4SO4), ammonium bisulfate (NH4HSO4), and sulfuric acid 

(H2SO4), are the most common sulfate compounds in PM2.5. These compounds are water-soluble 

and reside almost exclusively in the PM2.5 size fraction. Sodium sulfate (Na2SO4) has been found 

in coastal areas where sulfuric acid has been neutralized by sodium chloride (NaCl) in sea salt. 

Although gypsum (Ca2SO4) and some other geological compounds contain sulfate, these are not 

easily dissolved in water for chemical analysis and are more abundant in the coarse fraction than 

in PM2.5; they are usually classified in the geological fraction.

d. Nitrate: Ammonium nitrate (NH4NO3) is the most abundant nitrate compound, a large 

fraction of PM2.5 occurs during winter, and a moderate fraction occurs during fall. Sodium nitrate 

(NaNO3) is found in the PM2.5 and coarse fractions near the oceans and salt playas. Small 

quantities of sodium nitrate have been found in summertime particulate matter inland owing to 

transport from the ocean (Chow et al., 1996b). 

e. Ammonium: Ammonium sulfate (NH4SO4) and ammonium nitrate (NH4NO3) are the most 

common compounds containing ammonium from reactions between sulfuric acid, nitric acid, and

ammonia gases. While most of the sulfur dioxide and oxides of nitrogen originate from fuel 

combustion in stationary and mobile sources, most of the ammonia derives from living things, 

especially animal husbandry practiced in dairies and feedlots. 

f. Geological Material: Suspended dust consists mainly of oxides of aluminum, silicon, 

calcium, titanium, iron, and other metal oxides. In areas surrounded by substantial terrain (i.e., 

mountains), eons of runoff produce mineral compositions in soils that can be fairly 

homogeneous, with the exception of places where dry lake beds exist that have accumulated salt 

deposits. Industrial processes such as steel making, smelting, and mining have distinct geological 

compositions. For instance, cement production and distribution facilities may use alcareous, 

siliceous, argillaceous, and ferriferous minerals that may not be natural to the region, with 

limestone (CaCO3) being the most abundant (Greer et al., 1992). Suspended geological material 

resides mostly in the coarse particle fraction (Houck et al, 1989,1990), and typically constitutes 

~50% of PM10 while only contributing 5 to 15% of PM2.5 (Watson et al., 1994b). 

g. Sodium Chloride: Salt is found in suspended particles near oceans, open playas, and after 

de-icing materials are applied. Bulk sea water contains 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 often neutralized by nitric or sulfuric acid in urban air where it is 

encountered as sodium nitrate or sodium sulfate. 

h. Liquid Water: Soluble nitrates, sulfates, ammonium, sodium, other inorganic ions, and some

organic material (Saxena and Hildemann, 1997) absorb water vapor from the atmosphere, 

especially when relative humidity exceeds 70% (Tang and Munkelwitz, 1993). Sulfuric acid 

absorbs some water or deliquesces at all humidities. Particles containing these compounds grow 

44 
into the droplet mode as they take on liquid water. Some of this water is retained when particles 

are sampled and weighed for mass concentration. The precise amount of water quantified in a 

PM2.5 depends on its ionic composition and the equilibration relative humidity applied prior to 

laboratory weighing. 

Ambient mass concentrations contain both primary and secondary particles. Primary 

particles are directly emitted by sources and usually undergo few changes between source and 

receptor. Atmospheric concentrations of primary particles are, on average, proportional to the 

quantities that are emitted. 

Secondary particles are those that form in the atmosphere from gases that are directly 

emitted by sources. Sulfur dioxide, ammonia, and oxides of nitrogen are the precursors for 

sulfuric acid, ammonium bisulfate, ammonium sulfate, and ammonium nitrate particles. “Heavy” 

volatile organic compounds or HVOC (those containing more than eight carbon atoms) may also 

change into particles. The majority of these transformations result from intense photochemical 

reactions that also create high ozone levels. Secondary particles usually form over several hours 

or days and attain aerodynamic diameters in the accumulation mode between 0.1 and 1 μm.

Several of these particles, notably those containing ammonium nitrate, are volatile and transfer 

mass between the gas and particle phase to maintain a chemical equilibrium. This volatility has 

implications for ambient concentration measurements as well as for gas and particle 

concentrations in the atmosphere. 

Ambient concentrations of secondary aerosols are not necessarily proportional to quantities 

of emissions since the rate at which they form may be limited by factors other than the 

concentration of the precursor gases. Secondary particulate ammonium nitrate concentrations 

depend on gaseous ammonia and nitric acid concentrations as well as temperature and relative 

humidity. A nearby source of ammonia may cause a localized increase in PM2.5 concentrations 

by shifting the equilibrium from the gas to the particulate ammonium nitrate phase (Watson et 

al., 1994c). Ammonium sulfate may form rapidly from sulfur dioxide and ammonia gases in the 

presence of clouds and fogs, or slowly in dry air. Because fine particle deposition velocities are 

slower than those of the gaseous precursors, PM2.5 may travel much farther than the precursors, 

and secondary particles precursors are often found far from their emissions sources and may 

extend over scales exceeding 1,000 km. 

4. Particle Formation 

Ammonium nitrate and ammonium sulfate aerosols are the most prevalent secondary 

particles found at urban and non-urban sites throughout the U.S. during the winter. These 

particles can form when gas molecules are attracted to and adhere to existing particles.

Sulfur dioxide gas changes to particulate sulfate through gas- and aqueous-phase 

transformation pathways. In the gas-phase pathway, ultraviolet sunlight induces photochemical 

reactions creating oxidizing species that react with a wide variety of atmospheric constituents. 

The gas-phase transformation rate appears to be controlled more by the presence or absence of 

the hydroxyl radical and its competing reactions of other gases than by the sulfur dioxide 

concentrations. 

45 
In the presence of fogs or clouds, sulfur dioxide dissolves in droplets where it experiences 

aqueous reactions that are much faster than gas-phase reactions. When ozone and hydrogen 

peroxide are dissolved in the droplet, the sulfur dioxide is quickly oxidized to sulfuric acid. 

When ammonia is dissolved in the droplet, the sulfuric acid is neutralized to ammonium sulfate. 

If the fog or cloud evaporates and relative humidity decreases below 100 percent, the sulfate 

particle exists as a small droplet that includes a portion of liquid water. As the relative humidity 

further decreases below 70 percent, the droplet evaporates and a small, solid sulfate particle 

remains. The reactions within the fog droplet are very fast, and the rate is controlled by the 

solubility of the precursor gases. Aqueous transformation rates of sulfur dioxide to sulfate are 10 

to 100 times as fast as gas-phase rates. These chemical reactions are critical to understanding PM 

concentrations in areas and downwind of areas that emits large amounts of SO2. The location and 

SO2 emissions output of large point sources such as coal and oil fired power plants need to be 

mapped and compared with transport patterns in order to determine the impact of ammonium

sulfate particles on ambient surface concentrations. 

Fogs serve as an environment for creating particles and as vehicles for particle removal. 

During heavy fogs, particles and precursor gases are scavenged as fog droplets grow to sizes that 

settle rapidly to the surface. The extent and intensity of these fogs is so poorly characterized, 

however, that it is not yet possible to determine where and when particle formation overtakes 

particle deposition, thereby adding to the PM2.5 concentration loading. 

Nitrogen oxide converts to nitrogen dioxide, primarily by reaction with ozone. Nitrogen 

dioxide can: 1) change back to nitrogen oxide in the presence of ultraviolet radiation; 2) change 

to short-lived species which take place in other chemical reactions; 3) form organic nitrates; or 4) 

oxidize to form nitric acid. The major pathway to nitric acid is a reaction with hydroxyl radicals 

that transforms nitrogen dioxide to nitric acid. Nitric acid deposits from the atmosphere fairly 

rapidly but, in the presence of ammonia, it is neutralized to particulate ammonium nitrate. This is 

an important process in secondary particle production because many agricultural areas 

surrounding populated urban areas contain large ammonia sources. Chow and Egami (1997) 

show that San Joaquin Valley ammonia concentrations are large during winter. Conversion rates 

for nitrogen dioxide to nitric acid, ranging from less than one percent per hour to ninety percent 

per hour. These rates are typically five to ten times the conversion rates for sulfate formation. 

Though they vary throughout a twenty-four hour period, these rates are significant during both 

daytime and nighttime hours, in contrast to the gas-phase sulfate chemistry that is most active 

during daylight hours. The important nitric acid-ammonia reaction has implications to network 

design by the need to locate and map possible sources of ammonia. Significant sources of 

ammonia are associated with animal husbandry and fertilizer applications. Locating and 

estimating ammonia emissions will be a difficult task because it is not traditionally tabulated in 

emission inventories and requires further research to refine the methodology to measure the 

emissions. 

While ammonium sulfate is a fairly stable compound, ammonium nitrate is not. Its 

equilibrium with gaseous ammonia and nitric acid is strongly influenced by temperature and 

relative humidity. Atmospheric particle nitrate can occur in atmospheric aerosol particles as solid 

ammonium nitrate or as ionized ammonium nitrate in aerosol particles containing water. In both 

46 
the solid and ionized forms, ammonium nitrate is in equilibrium with gas-phase nitric acid and 

ammonia. 

For fixed relative humidity, increasing temperature decreases the particle nitrate fraction. 

This is a consequence of the direct relation between the equilibrium constants and temperature. 

As temperature increases, the equilibrium constants increase, which means higher gas-phase 

pressures can be supported, thereby reducing the particle nitrate fraction. For fixed humidity, 

decreasing temperature increases the particle nitrate fraction. As temperatures approach 0°C, the 

curves approach limiting values. Particle fractions of one are used for ion ratios greater than or 

equal to one, and particle fractions are determined by the amount of available ammonia for ion 

ratios less than one. For the higher temperatures, increasing relative humidity increases the 

particle nitrate fraction. This is a consequence of liquid water present for the 60% and 80% 

relative humidity cases. When there is sufficient ammonia present with 30% relative humidity, 

more than 90% of the nitrate is in the particle phase for temperatures less than 20°C. More than 

half of the particle nitrate is gone at temperatures above 30°C, and all of it disappears at 

temperatures above 40°C. 

Atmospheric water is another important component of suspended particulate matter. The 

sharp rise in liquid water content at relative humidities between 55% and 75% is known as 

deliquescence. A precise humidity at which soluble particles take on liquid water depends on the 

chemical mixture and temperature. Particles containing these compounds grow into the droplet 

mode as they take on liquid water, so the same concentration of sulfate or nitrate makes a much 

larger contribution to light extinction when humidities are high (>70 percent) than when they are 

low (<30 percent). Excess liquid water is also measured as part of the PM2.5 mass when sampled 

by light scattering continuous monitors or when filters have not been equilibrated at relative 

humidities less than 30% prior to weighing. 

Some of the organic carbon in suspended particles is also of secondary origin. Secondary 

organic compounds in particulate matter include aliphatic acids, alcohols, aromatic acids, nitroaromatics, carbonyls, esters, phenols, and aliphatic nitrates (Grosjean and Seinfeld, 1989; 

Grosjean, 1992, Pandis et al., 1992, 1993; Seinfeld and Pandis, 1998). Normally, primary 

organic carbon particles are more prevalent than secondary organics with exceptions such as 

those found in Los Angeles where conditions of clear skies and high photochemical smog are 

frequent. Although secondary organic aerosol was thought to be minimal during winter in central 

California, recent analyses (Strader et al., 1998) demonstrate that it could be as much as 20% of 

twenty-four hour organic carbon in some samples. This occurs because low wintertime 

temperatures lower the saturation vapor pressure for semi-volatile organic compounds. This is 

probably minor during winter and fall when photochemical reactions are not dominant. 

The exact precursors of secondary organics are not well understood, but they are believed to 

consist of heavy hydrocarbons with more than seven carbon atoms. Odum (1997) identifies 

aromatics as the major group of commonly measured reactive organic gases that affect both 

ozone and secondary aerosol formation. 

47 
5. Source Modeling Techniques 

Before selecting a modeling technique, it is wise to establish a conceptual model. A 

conceptual model describes the relevant physical and chemical processes that affect emissions, 

transport, and transformation specific to the region of interest. It is the starting point for any 

source apportionment process. Conceptual models take advantage of the large body of scientific 

knowledge already acquired. They identify the sources that are likely to be present and eliminate 

those that are not. They examine meteorological conditions that affect concentrations and focus 

further modeling on the conditions conducive to the high concentrations. 

Modeling techniques relevant to attribution are split into several categories depending

complexity, physical attributes, purpose and cost to execute. The following tables on pages 55 to 

62 provide a matrix of detailed information on specific models grouped in these categories. 

a. Puff Modeling Techniques 

These models are based on a Lagrangian framework where air parcels are tracked spatially 

and temporally. They can include chemical mechanisms as well as deposition effects. The most 

commonly used puff model is the CALMET/CALPUFF (Scire et al., 2000). 

b. Grid Modeling Techniques 

For estimating PM2.5 levels, Eulerian models that include aerosol modules simulating the 

physical and chemical processes governing particulate concentrations in the atmosphere are more 

suitable than Lagrangian models such as plume trajectory models. Eulerian three-dimensional 

models may use either a simplified treatment of atmospheric chemistry (usually used to address 

long-term particulate concentrations at urban sites) or include a more detailed atmospheric 

chemistry treatment (usually used to simulate only a few days of episodes due to their 

compositional cost). 

Commonly used long-term Eulerian models with simplified atmospheric processes include 

(Seigneur et al., 1997): 

• Urban Airshed Model Version V (UAM-V). 

• Urban Airshed Model with version V with Linear Chemistry (UAM-LC) 

• Regulatory Modeling System for Aerosol and Deposition (REMSAD). 

Short-term Eulerian models with complex atmospheric processes include: 

• Urban Airshed Model Version V with Aerosols (UAM-AERO), 

• Urban Airshed Model with Aerosol Inorganic Module (UAM-AIM). 

• SARMAP Air Quality Model with Aerosols (SAQM-AERO). 

• Community Multi-scale Air Quality Model (CMAQ) 

48 
• Comprehensive Air Quality Model with extensions (CAMx) 

All of the above mentioned Eulerian models have been developed by various scientists from

universities, federal and state agencies, and the private sector. These particulate air quality 

models provide a three-dimensional treatment to simulate the fate and transport of atmospheric 

contaminants. All of these Eulerian models include gas phase chemistry and aerosol dynamics 

and simulate atmospheric inorganics (such as sulfate, nitrate, and ammonium), but some of these 

models do not include the treatment of organics (i.e., REMSAD and UAM-LC). 

c. Lagrangian Trajectory Model Techniques 

The advantages of using Lagrangian models are the ease of use, the ability to perform many 

trajectories and perform back trajectories. Commonly used Lagrangian models include 

HYSPLIT (Draxler and Hess, 1997) and FLEXPART (Stohl and Siebert, 2001). 

d. Meteorological Modeling Techniques 

Meteorological models describe transport, dispersion, vertical mixing, and moisture in time

and space. Meteorological models consist of straight line, interpolation (termed diagnostic), and 

first principle (termed prognostic) formulations, with increasing levels of complexity and 

requirements for computational and data resources. 

The straight line model is applied to hourly wind directions from a single monitor, assuming 

an air mass travels a distance equal to the wind velocity in the measured direction, regardless of 

the distance from the monitoring site. This model is applicable for a few hours of transport in flat 

terrain, typically for evaluating a single emissions source. 

Interpolation models integrate wind speed and directions from multiple measurement 

locations, including upper air measurements provide by remote sensors or balloon launches. The 

more advanced of these models allow barriers, such as mountains, to be placed between 

monitors. Wind fields, therefore, show different directions and velocities at different horizontal 

and vertical positions. Interpolation wind models are applicable to domains with a large number 

of well-placed monitors and for estimating the movement of air masses from many sources over 

transport times of more than half a day. The number and placement of monitors, especially upper 

air monitors, is especially important in mountainous terrain and in coastal areas where winds are 

unusual. 

First principle models (Stauffer and Seaman, 1994; Seaman et al., 1995; Koracin and Enger, 

1994) embody scientists’ best knowledge of atmospheric physics and thermodynamics, 

employing basic equations for conservation and transfer of energy and momentum. Also known 

as “prognostic models,” first principle models purport to need no data other than values from a 

sparse upper air network for interpolation. They are computationally intensive, often requiring 

supercomputers but have become more practical and cost-effective as workstation and desktop 

computers become more powerful. Modern versions use “four-dimensional data assimilation” or 

FDDA that compare model-calculated wind, humidity, and temperature fields with 

measurements and “nudge” model outputs toward observations. 

49 
A more complex meteorological model is not necessarily a better model for a specific

application. One of the most widely used first principle model is the Fifth-Generation 

NCAR/Penn State Mesoscale Model or MM5 model (Grell et al., 1995). The MM5 

meteorological model has been adopted as the platform for central California air quality studies 

(Seaman et. al., 1995). MM5 input data consist of wind speed, wind direction, temperature, 

atmospheric pressure, and relative humidity at ground level, within the boundary layer, and 

above the boundary layer. In many cases in valley situations ten-meter vertical resolution is 

needed within the surface 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 (Watson et al., 1998). Time

resolution is at least hourly for these measurements. Measurements are needed where large 

differences are expected, although this is largely unknown for winter.

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1616. Prepared by Electric Power and Research Institute, Palo Alto, CA. 

Braaten, D.A.; and Cahill, T.A. (1986). Size and composition of Asian dust transported to 

Hawaii. Atmos. Environ., 20:1105-1109. 

Chow, J.C.; Watson, J.G.; Lowenthal, D.H.; Solomon, P.A.; Magliano, K.L.; Ziman, S.D.; and 

Richards, L.W. (1993a). PM10 and PM2.5 compositions in California's San Joaquin 

Valley. Aerosol Sci. Technol., 18:105-128. 

Chow, J.C.; Watson, J.G.; Pritchett, L.C.; Pierson, W.R.; Frazier, C.A.; and Purcell, R.G. 

(1993b). The DRI Thermal/Optical Reflectance 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). Descriptive analysis of PM2.5 and PM10 at regionally 

representative locations during SJVAQS/AUSPEX. Atmos. Environ., 30:2079-2112. 

Chow, J.C.; Watson, J.G.; Lowenthal, D.H.; and Countess, R.J. (1996b). Sources and chemistry 

of PM10 aerosol in Santa Barbara County, CA. Atmos. Environ., 30:1489-1499. 

Chow, J.C.; and Egami, R.T. (1997). San Joaquin Valley Integrated Monitoring Study: 

Documentation, evaluation, and descriptive analysis of PM10 and PM2.5, and precursor 

gas measurements - Technical Support Studies No. 4 and No. 8 - Final report. Prepared 

for California Regional Particulate Air Quality Study, California Air Resources Board, 

Sacramento, CA, by Desert Research Institute, Reno, NV. 

Darzi, M.; and Winchester, J.W. (1982). Aerosol characteristics at Mauna Loa Observatory, 

Hawaii, after east Asian dust storm episodes. J. Geophys. Res., 87:1251-1258. 

Draxler, R.R.; and Hess, G.D. (1997). Description of the Hysplit_4 modeling system. Report No. 

NOAA Tech Memo ERL ARL-224, December 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 

plume model. JAPCA, 30:773-776. 

Greer, W.L.; Johnson, M.D.; Morton, E.L.; Raught, E.C.; Steuch, H.E.; and Trusty, C.B. (1992). 

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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 Model (MM5). Report No. NCAR Technical Note, NCAR/TN398+STR, June 1995. Prepared by National Center for Atmospheric Research, Boulder, 

CO. 

Grosjean, D.; and Seinfeld, J.H. (1989). Parameterization of the formation potential of secondary 

organic aerosols. Atmos. Environ., 23:1733-1747. 

Grosjean, D. (1992). In-situ organic aerosol formation during a smog episode: estimated 

production and chemical functionality. Atmos. Environ., 26A:953-963. 

Holton, J.R. (1982). An Introduction to Dynamic Meteorology. Academic Press, New York, NY. 

Houck, J.E.; Chow, J.C.; and Ahuja, M.S. (1989). The chemical and size characterization of 

particulate material originating from geological sources in California. In Transactions, 

Receptor Models in Air Resources Management, Watson, J.G., Ed. Air & Waste 

Management Association, Pittsburgh, PA, pp. 322-333. 

Houck, J.E.; Goulet, J.M.; Chow, J.C.; Watson, J.G.; and Pritchett, L.C. (1990). Chemical 

characterization of emission sources contributing to light extinction. In Transactions, 

Visibility and Fine Particles, Mathai, C.V., Ed. Air and Waste Management Association, 

Pittsburgh, PA, pp. 437-446. 

Koracin, D.; and Enger, L. (1994). A numerical study of boundary-layer dynamics in a mountain 

valley. Part 2: Observed and simulated characterisitcs of atmospheric stability and local 

flows. Boundary Layer Meteorology, 69:249-283. 

Lowenthal, D.H.; Chow, J.C.; Watson, J.G.; Dipple, W.A.; and Mazzera, D.M. (1996). PM10

source apportionment at McMurdo Station, Antarctica. EM, 28-30. 

Odum, J.R.; Jungkamp, T.P.W.; Griffin, R.J.; Forstner, H.J.L.; Flagan, R.C.; and Seinfeld, J.H. 

(1997). Aromatics, reformulated gasoline, and atmospheric organic aerosol formation. 

Environ. Sci. Technol., 31:1890-1897. 

Pandis, S.N.; Harley, R.A.; Cass, G.R.; and Seinfeld, J.H. (1992). Secondary organic aerosol 

formation and transport. Atmos. Environ., 26A:2269-2282. 

Pandis, S.N.; Wexler, A.S.; and Seinfeld, J.H. (1993). Secondary organic aerosol formation and 

transport - II. Predicting the ambient secondary organic aerosol size distribution. Atmos. 

Environ., 27A:2403-2416. 

51 
Pytkowicz, R.M.; and Kester, D.R. (1971). The physical chemistry of sea water. Oceanogr. Mar. 

Biol., 9:11-60. 

Rogge, W.F.; Hildemann, L.M.; Mazurek, M.A.; and Cass, G.R. (1991). Sources of fine organic 

aerosol. 1. Charbroilers and meat cooking operations. Environ. Sci. Technol., 25:1112-

1125. 

Rogge,W.F.; Mazurek, M.A.; Hildemann, L.M.; Cass, G.R.; and Simoneit, B.R.T. (1993a). 

Quantification of urban organic aerosols at a molecular level: identification, abundance 

and seasonal variation. Atmos. Environ., 27A:1309-1330. 

Rogge, W.F.; Hildemann, L.M.; Mazurek, M.A.; Cass, G.R.; and Simoneit, B.R.T. (1993b). 

Sources of fine organic aerosol. 2. Noncatalyst and catalyst-equipped automobiles and 

heavy-duty diesel trucks. Environ. Sci. Technol., 27:636-651. 

Rogge, W.F.; Hildemann, L.M.; Mazurek, M.A.; Cass, G.R.; and Simoneit, B.R.T. (1993c). 

Sources of fine organic aerosol. 3. Road dust, tire debris, and organometallic brake lining 

dust: Roads as sources and sinks. Environ. Sci. Technol., 27:1892-1904. 

Rogge, W.F.; Hildemann, L.M.; Mazurek, M.A.; Cass, G.R.; and Simoneit, B.R.T. (1997). 

Sources of fine organic aerosol. 8. Boilers burning No. 2 distillate fuel oil. Environ. Sci. 

Technol., 31:2731-2737. 

Rogge, W.F.; Hildemann, L.M.; Mazurek, M.A.; Cass, G.R.; and Simoneit, B.R.T. (1998). 

Sources of fine organic aerosol. 9. Pine, oak, and synthetic log combustion in residential 

fireplaces. Environ. Sci. Technol., 13-22. 

Scire, J.S.; Strimaitis, D.G.; and Yamartino, R.J. (2000). A user's guide for the CALPUFF 

dispersion model (version 5). Prepared by Earth Tech, Inc., Concord, MA. 

Seaman, N.L.; Stauffer, D.R.; and Lario-Gibbs, A.M. (1995). A multiscale four-dimensional data 

assimilation system applied in the San Joaquin 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 models for particulate matter. Report No. CP015-97-1a. Prepared for American

Petroleum Institute, Washington, D.C., by Atmospheric & Environmental Research, Inc., 

San Ramon, CA. 

Seinfeld, J.H.; and Pandis, S.N. (1998). Atmospheric Chemistry and Physics. John Wiley & 

Sons, New York. 

Stauffer, D.R.; and Seaman, N.L. (1994). Multiscale four-dimensional data assimilation. J. Appl. 

Meteorol., 33:416-434. 

Stohl, A.; and Seibert, P. (2001). The FLEXPART particle dispersion model version 4.0 user 

guide. June 4, 2001. 

52 
Strader, R.; Pandis, S.N.; and Lurmann, F.W. (1998). Evaluation of secondary organic aerosol 

formation in winter. Prepared for California Air Resources Board, Sacramento, 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. (1993). Composition and temperature dependence of the 

deliquescence properties of hygrosopic aerosols. Atmos. Environ., 27A:467-473. 

Watson, J.G.; Chow J.C.; Lowenthal, D.H.; Pritchett, L.C.; Frazier, C.A.; Neuroth, G.R.; and 

Robbins,R. (1994a). Differences in the carbon composition of source profiles for dieseland 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). 

Chemical mass balance source apportionment of PM10 during the Southern California Air 

Quality Study. Aerosol Sci. Technol., 21:1-36. 

Watson, J.G.; Chow, J.C.; Lurmann, F.W.; and Musarra, S. (1994c). Ammonium nitrate, nitric 

acid, and ammonia equilibrium in wintertime 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 PM10 and PM2.5 measurements in Central California. Prepared for California 

Air Resources Board, Sacramento, CA, by Desert Research Institute, Reno, NV. 

Watson, J.G.; Fujita, E.M.; Chow, J.C.; Zielinska, B.; Richards, L.W.; Neff, W.D.; and 

Dietrich,D. (1998). Northern Front Range Air 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.; Kaduwela, A.; Magliano, K.; McDade, C.; Mueller, 

P.K.; Ranzieri, A.; Roth, P.M.; and Tanrikulu, S. (1998). Aerometric monitoring program

plan for the California Regional PM2.5/PM10 Air Quality Study. Report No. DRI 

document No. 9801.1D5. Prepared by Division of Atmospheric Sciences, Desert 

Research Institute, Reno, NV.

53 

Source Modeling and Back Trajectory Attribution Techniques 

Table 2. Puff, Visibility and Trajectory Modeling Attribution Techniques 

Air Quality Models

Visibility Models Lagrangian Trajectory Models Evaluation Criteria 

CALPUFF VISC

R

E

E

N

P

L

U

V

U

EII H

YSP

LIT

RA

P

T

A

D FL

E

X

Chemical Mechanisms

Does the model simulate aqueous phase chemistry? (Ifit does what chemistrymechanis

m is used and does it

include fog/cloud chemistry) 

Yes; reactions for 

SO4 and NO3

N

O

N

O

N

O

N

O

N

Does the model simulate gas phase chemistry? (if it does,what chemical mechanis

m is

implemented) 

Yes N

O

N

O

N

O

N

O

N

Simulate secondary organic aerosols 

4 species model NO NO NO NO N

Inorganic PM (i.e. ions, SO4, 

NO3, etc) 

SO4, N

O3 N

O

N

O

N

O

N

O

N

Size distributions (sectional ormodal) 

Coarse and fine

modes 

NO NO Only for deposition NO 

Applicable spatial scales

Micro- to regional 

scale 

Neighbor-hood to 

urban scale 

Neighborhood to

global scale 

Neighborhood to global 

scale 

Neighborhood 

Applicable temporal scales(episodic or long term applications) 

Episodic or Long

term

N/A

N/A

Episodic or Long

term

Episodic or Long term Episodic o

Does the model have the capability to distinguish BART sources? 

Y

ES Y

ES Y

ES Y

ES Y

ES Y

Does the model have the capability to ingest fieldmeasurements (

P

M, HNO3, 

H2O2, N

H3, etc)

NO; only as

background values 

N

O

N

O

N

O

N

O

N

55 
Air Quality Models (continued) 

Visibility Models Lagrangian Trajectory Models Evaluation Criteria 

CALPUFF VISCREEN PLUVUEII HYSPLIT RAPTAD FLEX

Visibility Modeling 

Does the model simulate background regional haze 

NO NO NO NO NO N

Point source treatment (plumerise, plume in grid) 

YES YES YES YES YES Y

Does the model have the capability to calculate wet and dry deposition?

YES NO NO YES NO Y

Visibility treatment:(extinction, deciview, visualrange) 

Extinction (total

and for SO4, NO3, 

EC, OC, fine, 

coarse), Deciviews

* * NO NO N

Input Requirements

Meteorological data required (single site, gridded, numberof levels, etc) 

Gridded; able to

run with single site

* * Gridded 

(FNL, EDAS,

MM5) 

 Gridded 

(Use HOTMAC’s 

prediction) 

 Gridded (EC

Emission data required (single stack, multiple point sources, gridded, etc) 

 Multiple point,

area, volume

* * Multiple point

sources, gridded 

inventory

Single stack or multiple

point sources 

Allow for initial and boundaryconditions (is it required or not applicable) 

YES NO NO NO NO N

Has the model been comparedagainst field program data?Has the model been peerreviewed?

YES YES YES YES YES N

Does enough data exist now to run the model (Does data exist in a format ready for the model? Are current databasesadequate for the model?) 

Use CALMET 

with existing 

stations or MM 

data 

YES YES Gridded met data

available on NOAA 

ARL ftp site (FNL, 

EDAS); adaptable 

to read in MM5 

Use HOTMAC to obtain 

wind and turbulence data 

56 
Air Quality Models (continued) 

Visibility Models Lagrangian Trajectory Models Evaluation Criteria 

CALPUFF VISCREEN PLUVUEII HYSPLIT RAPTAD FLEX

Practical Considerations

Costs to run (hardware platforms, file storage,operating system) 

Inexpensive; PC, 

Windows, up to 

20GB (with 

CALMET) 

Inexpensive; PC, 

DOS, 1MB 

Inexpensive; 

PC, DOS, 

1MB 

Inexpensive; PC, 

Windows, 20MB 

Inexpensive: Linux PC, 

Redhat 

Inexpensive; Linux compiled on PC 

Have protocols or procedures been developed to run andinterpret the model?

FLAG for Class I 

AQRVs 

FLAG for Class I 

AQRVs 

FLAG for 

Class I 

AQRVs 

NO NO N

Is the source code available? YES YES YES NO YES YAre beginning user trainingclasses available?

YES; by

EarthTech, BEELine 

EPA; APTI EPA; APTI NO YES N

Are user support groups available?

YES; one list-serve YES; through EPA 

SCRAM 

YES; through 

EPA SCRAM 

NO YES N

Level of expertise required torun and interpret results (Level of Linux, UNIX, PC skills required) 

Moderate; able to

run PC DOS 

programs; 

knowledge of

atmospheric 

chemistry &

physics 

Simple; able to run on 

PC DOS and windows 

Simple; able

to run on PC 

DOS and 

Windows 

Simple; able to run 

on PC running 

Windows 

 Simple to run: GUI 

allows the user to easily

run the program

Knowledge is needed to 

interpret results 

Moderate; must com

PC, Linux or UNIX

input 

Output visualization requiredto interpret output numbers 

YES NO NO YES; has built in 

visualization 

YES; has built in 

visualization 

Y

Other strengths * * * * Applicable from building

scale to terrain scale.

Availability EarthTech

www.src.com

EPA EPA NOAA Air

Resource 

Laboratory;

www.arl.noaa.gov/s

s/models/hysplit.ht

ml

Yamada Science & Art;

http://www.ysasoft.com 

http://ww

muenchen.de/EXT/

lexpa

* No information available at this time

57 
Source Modeling and Back Trajectory Attribution Techniques 

Table 3. Eulerian Grid Based Modeling Attribution Techniques 

Air Quality Models

Grid Models Evaluation Criteria 

C

M

A

Q

R

E

MSA

D

C

A

Mx U

A

M-A

E

R

O UAM-V

P

M

Chemical Mechanisms

Does the model simulate aqueous phase chemistry? (If it does, what chemistry mechanis

m is used and does it include

fog/cloud chemistry)

35 equilibria and 99 

reactions for S

O4 and 

NO3

1 reaction for SO4 1 reaction for SO4 35 equilibria and 99 

reactions for S

O4 and 

NO3

* 2 

Does the model simulate gas phase chemistry? (if it does, what chemicalmechanis

m is implemented) 

CBM-IV (93 

reactions) or RADM2 

(158 reactions) 

CBM-IV 

(93 reactions) or

RADM2 (158 

reactions) 

CB-IV with enhanced

isoprene or

SAPRC97 

SAPRC97 

(185 reactions) 

C

B

(

Simulate secondary organic aerosols Primary from

emissions; secondary 

from organics 

Primary from 

emissions 

Primary from 

emissions; secondary 

from gas phase 

reactions of organic 

precursors using

yields 

Secondary from gas 

phase reactions of 

organic precursors 

using yields 

Primary from 

emissions 

e

Inorganic PM (i.e. ions, SO4, NO3, etc) SO4, N

O3 and other 

material

SO4, N

O3, N

H4, and 

other material 

SO4, N

O3, N

H4, Cl, 

other ions and

materials 

SO4, N

O3, N

H4, Cl, 

other ions and

materials 

SO4, N

O3, N

H4, and 

other materials 

Size distributions (sectional or modal) Lognormal; three 

modes: Aitken, 

Accumulation and 

coase 

PM2.5 fraction, coarse

mode 

Discrete bins, user 

specified up to 10

Discrete bins, user 

specified up to 10

Lognormal bins; user 

specified 

Applicable spatial scales

Mesoscale 

Mesoscale 

Mesoscale Urban scale Urban scale 

Applicable temporal scales (episodic or longterm applications) 

Episodic Long term

Episodic Episodic Episodic 

Does the model have the capability todistinguish BAR

T sources?

YES; using plu

me in 

grid 

N

O

Y

ES N

O

N

O

58 
Air Quality Models (continued) 

Grid Models Evaluation Criteria 

CMAQ REMSAD CAMx UAM-AERO UAM-VPM 

Chemical Mechanisms (continued) 

Does the model have the capability to ingest field measurements(PM,HNO3,H2O2,NH3,etc) 

YES; as initial and 

boundary conditions 

Uses default profiles YES; as initial and 

boundary conditions 

YES; as initial and 

boundary conditions 

YES; as initial and 

boundary conditions 

Visibility Modeling 

Does the model simulate background regional haze 

YES YES YES YES (with

processing) 

YES 

Point source treatment (plume rise, plume ingrid) 

Plume in grid NO Plume in grid NO NO 

Does the model have the capability tocalculate wet and dry deposition?

YES YES YES YES YES 

Visibility treatment: (extinction, deciview,visual range) 

Extinction (total and 

for SO4, NO3, EC, 

OC, fine, coarse), 

Deciviews

Extinction (total and 

for SO4, NO3, EC, 

OC, fine, coarse), 

Deciviews

NO YES (with 

processing) 

* 

Input Requirements

Meteorological data required (single site, gridded, number of levels, etc) 

Gridded Gridded Gridded Gridded Gridded 

Emission data required (single stack, multiplepoint sources, gridded, etc) 

Gridded Gridded Gridded Gridded Gridded 

Allow for initial and boundary conditions (isit required or not applicable) 

YES YES YES YES YES 

Has the model been compared against fieldprogram data? Has the model been peerreviewed?

YES YES YES YES YES 

Does enough data exist now to run the model (Does data exist in a format ready for the model? Are current databases adequate forthe model?) 

Extensive need for 

detailed emissions 

and meteorological 

fields 

Extensive need for 

detailed emissions 

and meteorological 

fields 

Extensive need for 

detailed emissions 

and meteorological 

fields 

Extensive need for 

detailed emissions 

and meteorological 

fields 

Extensive need for 

detailed emissions 

and meteorological 

fields 

59 
Air Quality Models (continued) 

Grid Models Evaluation Criteria 

CMAQ REMSAD CAMx UAM-AERO UAM-VPM 

Practical Considerations

Costs to run (hardware platforms, file storage,operating system) 

Can be run 

inexpensively; Linux 

PC, up to 1 TB 

(annual runs) 

Can be run 

inexpensive; Linux 

PC 

Can be run 

inexpensively; Linux 

PC 

Can be run 

inexpensively; Linux 

PC 

Can be run 

inexpensively; Linux 

PC 

i

Has a protocol or procedures been developedto run the model?

NO; but RPOs have 

regional haze 

protocols 

NO; but RPOs have 

regional haze 

protocols 

NO NO NO 

Is the source code available? YES * YES YES YES Are beginning user training classes available? YES; through EPA 

and RPOs 

NO YES; through SAI 

and RPOs 

NO NO 

Are user support groups available? YES; through EPA 

and RPOs 

NO NO NO NO 

Level of expertise required to run and interpret results (Level of Linux, UNIX, PC skills required) 

Considerable

expertise in UNIX or 

Linux; knowledge of 

atmospheric 

chemistry & physics 

 * Moderate to

extensive 

 Moderate to

extensive 

* 

Output visualization required to interpret output numbers 

YES; use PAVE YES; use PAVE YES YES YES 

Availability EPA; Sharon LeDuc 

919-541-1335 

SAI; Sharon Douglas 

415-507-7108 

ENVIRON; Ralph 

Morris 415-899-0700 

SAI; Sharon Douglas 

415-507-7108 

SAI; Sharon Douglas 

415-507-7108 

R

* No information available at this time 

60 
Table 4. Meteorological Modeling Attribution Techniques 

Diagnostic Models Mesoscale Prognostic Models

Evaluation Criteria CALMET Diagnostic Wind Model RAMS MM5 Eta * ARPS 

Applicable spatial scales Urban to regional 

scale 

Urban to regional 

scale 

Urban to global 

scale 

Urban to global 

scale 

Urban to global 

scale 

Urban to global 

scale 

Applicable temporal scales

Hourly to annual Hourly to annual Hourly to annual Hourly to annual Hourly to annual Hourly to annual H

Does enough data exist inorganization now to runthe model? Are the existing monitoring networks adequate within the domain?

Depends on area Depends on area Depends on area Depends on area Depends on area Depends on area D

For the prognostic models: Capable of FDDA?

N/A N/A Yes Yes Yes Yes 

For the prognostic models: Are files available (archived) fromreal-time?

N/A N/A NOAA is running 

the model for the 

east coast 

Several federal 

agencies and 

regional 

consortiums are 

running MM5 

NOAA is running 

the Eta model and 

fields available 

through NCEP ftp 

site 

It can be

initialized using 

NCEP analyses

files as well as

individual 

observations 

Data storage/archivalrequirements forsimulation of episodic and annual events

Depends on 

modeling domain, 

grid size, number of 

species and length 

of simulation 

Depends on 

modeling domain, 

grid size, number 

of species and

length of 

simulation 

Depends on 

modeling domain, 

grid size, number 

of species and

length of 

simulation 

Depends on 

modeling domain, 

grid size, number 

of species and

length of 

simulation 

Depends on 

modeling domain, 

grid size, number 

of species and

length of 

simulation 

Depends on 

modeling domain, 

grid size, number 

of species and

length of 

simulation 

m

g

Simulate clouds/precipitation fields? At what timeintervals?

No No Yes – minutes to 

days

Yes – minutes to

days

Yes – minutes to

days

Yes – minutes to

days

Y

Has the model been compared against field program data? Has the model been peerreviewed?

Yes Yes Yes Yes Yes Yes 

61 
Meteorological Modeling Attribution Techniques (continued) 

Diagnostic Models Mesoscale Prognostic Models

Evaluation Criteria CALMET Diagnostic Wind Model RAMS MM5 Eta * ARPS 

Tools available tovisualize output fields?What operating systems?

Yes – Unix, Linux, 

Windows 

Yes – Unix, 

Linux, Windows 

Yes – Unix, Linux Yes – Unix, Linux Yes – Unix, Linux Yes – Unix, Linux 

G

Are user groups, listservers available whenproblems arise?

Yes Yes Yes Yes No Yes 

Cost to run (hardware,software) 

PC Windows, PC 

Linux; Free source 

code 

PC Linux, UNIX; 

Free 

PC Linux; licensed 

source code

PC Linux, UNIX; 

Free source code

PC Linux, UNIX; 

Free source code

PC Linux, UNIX; 

Free source code

PC 

Level of expertise required to run and interpret results (Level ofLinux, UNIX, PC skills required) 

Moderate Moderate High High High High 

Availability of user training 

Yes Yes Yes Yes No Yes 

Is the source codeavailable?

Yes Yes Yes Yes No Yes 

Has a protocol orprocedures beendeveloped to run the model?

Yes Yes Yes Yes Yes Yes 

Strengths Relatively easy to 

use; little observed 

data needed 

Relatively easy to 

use; little observed 

data needed 

Detailed 3-D,

complex flow in 

time 

Detailed 3-D,

complex flow in 

time 

Detailed 3-D,

complex flow in 

time 

Detailed 3-D,

complex flow in 

time 

c

Weaknesses/ Limitations 

Parameterization

depended; may not 

capture various 

flows 

Parameterization

depended; may not 

capture various 

flows 

Large computer

time; time 

consuming to 

debug 

Large computer

time; time 

consuming to 

debug 

Large computer

time; time 

consuming to 

debug 

Large computer

time; time 

consuming to 

debug 

N

* While the Eta is not considered a mesoscale model, it has been used to simulate meteorology down to 10 km grid scales. The workstation Eta is ava

 NOAA and used experimentally by some NWS offices.

* No information available at this time

62 
C. Observational Modeling Techniques 

Introduction 

Observational or receptor modeling refers to a group of analysis techniques in which 

monitoring data collected at or in the region of a receptor are analyzed in various ways in order 

to infer information about the pollutants and the sources of the pollutants causing visibility 

impairment. 

These types of models often are used as the first technique for source apportionment in order 

to get an initial understanding of the source-receptor relationships in a region. They are also used 

to verify or reconcile deterministic models, and to aid in planning intensive monitoring studies. 

Results of observational models can either be quantitative or qualitative. Quantitative results 

are estimates of the fractions of a measured species that can be attributed to a single source or 

attributed among several sources or source areas. Qualitative results include such information as 

the wind directions and other meteorological conditions most associated with high 

concentrations, or inferences about probable source types based on the relationships between 

trace elements at a single site, or information about source areas based on the spatial and 

temporal patterns in the concentrations of a single species. Often several observational models 

are used together to form hypotheses about the important source areas and source types affecting 

the concentrations at a receptor. 

Advantages of receptor models are that they are generally quick and inexpensive to run and 

require relatively little input data. Disadvantages include the necessity of employing simplifying 

assumptions such as linear relationships and often the results are limited to averages over long 

periods of time or large spatial areas. Subjective user judgment is required to choose appropriate 

input data and/or interpret the results of many receptor models. As an example, suppose the 

UNMIX model data located a source associated with high concentrations of Br, K, elemental 

carbon, and organic carbon, and another source associated with high Se and S. It is the judgment 

of the modeler regarding the relationship of the individual species to a specific source that 

determines that first source is “smoke” and the second is “coal-fired power plants.” 

Receptor models could potentially be grouped in several different ways, based on their 

different attributes. Here they are somewhat arbitrarily put into four categories, with each 

category requiring incrementally more particulate data at the receptor: 1) back-trajectory 

analyses; 2) analyses of interspecies relationships; 3) analyses of spatial and temporal patterns; 

and 4) analyses that require a unique tracer. Some models that fall into each category are listed 

below: 

Category 1. Back-Trajectory Analyses 

a. Residence Time Analyses including residence time, source contribution function, 

conditional probability, and so forth. These give qualitative information about source 

areas and transport patterns. 

63 
b. Trajectory Mass Balance – Regression of residence time of back trajectories in selected 

source areas against concentrations yielding quantitative source attributions. 

Category 2. Analyses of Interspecies Relationships 

a. Chemical Mass Balance (CMB) - Quantitative source attributions are obtained by a 

weighted regression of known source profiles against measured concentrations of several 

species. 

b. UNMIX – By looking for “edges” in the relationships between species, UNMIX 

estimates both the source profiles and the quantitative source contributions from each 

source. 

c. Positive Matrix Factorization (PMF) – PMF, like UNMIX, uses the relationships between 

species to estimate the number and composition of the sources and the quantitative source 

contributions. 

d. Enrichment Factors (EF) – The “enrichment” of certain ratios of trace elements is used to 

qualitatively infer source types impacting a receptor. 

Category 3. Analyses of Spatial and Temporal Patterns 

a. Empirical Orthogonal Function Analysis (EOF) – Analysis of spatial and temporal 

patterns leading to qualitative information about locations of dominant source areas, 

frequency and timing of source impacts and meteorological conditions associated with 

them. 

b. Receptor Model Applied to Patterns in Space (RMAPS) – With additional assumptions 

applied to EOFs, quantitative source attributions are estimated. 

Category 4. Tracer Analyses 

a. Tracer Mass Balance Regression (TMBR) – Tracer concentrations, possibly weighted by 

other factors, are regressed against concentrations of the species of interest to give a 

quantitative estimate of the contribution from the source that emitted the tracer. 

b. Differential Mass Balance (DMB) - The differential ratios of tracer to pollutant between 

source and receptor are adjusted based on simple chemistry and meteorology to give an 

estimate of the contribution of the tracer source to the receptor. 

c. Tracer-Aerosol Gradient Interpretive Technique (TAGIT) – By comparing the ratios of

tracer to concentration of interest at “background” sites to the ratios at tracer-affected 

sites, a quantitative attribution of the tracer source to the receptor is estimated. 

Following are brief descriptions of each of these models and a few references giving further 

details and examples of their use. 

1a. Qualitative Back Trajectory Residence Time Analyses 

There are several methods of statistically analyzing the relationships between where air 

masses arrived from and the concentrations measured at a receptor. These include, but are not 

limited to: 1) where was air most likely to arrive from when concentrations are high; 2) if air 

arrived from a given area, what is the probability that the concentration at the receptor was high 

when the air mass arrived there; 3) what is the mean (or median or maximum or distribution) of 

64 
concentrations at the receptor when air masses arrived from a given area. Selected References: 

Ashbaugh et al. (1985), Gebhart et al. (2001), Poirot and Wishinski (1986). 

Data Needed: A time series of concentrations of the species of interest. One or more back 

trajectories of three to five days duration corresponding to each concentration. Back trajectories 

can be calculated by any of several methods including ATAD, Hysplit, the CAPITA Monte 

Carlo Model, as well as others. Standard National Weather Service upper air data can be used as 

input, though more detailed meteorological data can be input if available. Dispersion can be 

included in some of these models. 

Model Assumptions: Errors in trajectory placement are random and uncorrelated. Variations 

in deposition, chemistry, emissions, and so forth, have less influence on measured concentrations

on average than variations in transport directions. 

Biggest Potential Problems: Results of these types of analyses are qualitative rather than 

quantitative. Results are more statistically robust when averaged over long time periods, usually 

a minimum of one season and preferably several years. Nearby sources cannot be resolved. User 

judgment is required to choose trajectories of an appropriate type, height, and length and also to 

choose appropriate definitions of “high” concentrations. Some concentrations that vary 

seasonally may have all “high” concentrations in a single season, necessitating some

compensation in the analysis. Model results are probably more appropriate for species such as 

particulate sulfate that are relatively uniform over large spatial scales, rather than, for example, 

particulate nitrate, which is more volatile and seems to be more related to local sources than 

long-range transport. 

1b. TrMB (Trajectory Mass Balance) 

This is a multiple linear regression of the frequency of occurrence of trajectory endpoints in 

each of several source areas against the corresponding concentrations at the receptor. The result 

is the average attribution of a single species among up to about 25 source areas over a long time, 

for example, one season or year, or several years. Selected references: Gebhart and Malm (1989), 

Stohl (1998). 

Data Needed: Time series of concentrations of the pollutant of interest at a single site. One 

or more back trajectories associated with each concentration. Input data for these are upper air 

winds, temperatures, and moisture over a large area. Often data are obtained from the standard 

National Weather Service observations, but other data such as higher resolution wind fields, 

wind profiler data specific to a given study, can also be used if available. Emission data can be 

used if available, but must vary in time to be useful. Simple chemistry and/or deposition can be 

used if data are available. The user defines the size and locations of the source areas to be 

considered. 

Model Assumptions: Average contributions of each source area can be written as a linear 

combination of the contributions from several source areas. Average chemistry and deposition 

are adequate to explain average source contributions. Errors in back trajectories are random and 

normally distributed. 

65 
Biggest Potential Problems: No attribution to single sources—only to source areas. 

Attributions must be averaged over long time periods. Nearby sources cannot be modeled 

accurately. Subjectivity in choosing source areas. Violation of assumptions of linear chemistry. 

2a. Chemical Mass Balance (CMB)

CMB is a multiple linear regression of measured concentrations against known source 

profiles. It is used for the attribution of all measured chemical species among several sources for 

each concentration measurement period for a single monitoring site. Regressions are weighted by 

the uncertainties in both the source profiles and the concentrations. Selected References: Watson 

et al. (1984 and 2001). 

Data Needed: Concentrations and measurement uncertainties of both the chemical species of 

interest and of as many trace elements as possible are necessary for each time period and location 

for which attributions are desired. IMPROVE data can be used. A source profile is needed for 

each source. These are the relative amounts of each emitted chemical species and the 

uncertainties in these values. 

Model Assumptions: Compositions of source emissions are constant over the period of 

ambient and source sampling. Chemical species do not react with each other, for example, they 

add linearly. All sources with a potential for significantly contributing to the receptor have been 

identified and have had their emissions characterized. The sources’ compositions are linearly 

independent of each other. The number of sources or source categories is less than or equal to the 

number of chemical species. Measurement uncertainties are random, uncorrelated and normally 

distributed. 

Biggest Potential Problems: The model cannot directly apportion secondary species such as 

sulfates, nitrates, and secondary organics. There are some workarounds for this. The usual tactic 

is to apportion these species between the known primary sources and a source designated as 

“secondary particles.” It is also possible to use “fractionated” or “aged” source profiles where an 

attempt is made to pre-determine the chemical processes that occurred between source and 

receptor and then adjust the source profile accordingly. Obtaining all necessary source profiles 

can be difficult. In some studies, other receptor models have estimated source profiles.

2b. UNMIX

For a selection of measured species, UNMIX uses singular value decomposition with 

additional non-negativity constraints to estimate the number of sources, the source compositions, 

and the source contributions to each sample at a single monitoring site. UNMIX attempts to find 

the “edges” in the relationships between species and relates these to sources. Selected 

References: Henry (1997a, 1999), Lewis et al. (1998). 

Data Needed: A time series of concentrations of several species measured at a single site. 

IMPROVE data can be used. 

66 
Model Assumptions: Concentrations are linear combinations of an unknown number of 

sources of unknown composition. Contributions from sources are positive. Source compositions

are approximately constant in time. For each source there are some samples that contain little or 

no contribution from that source. 

Biggest Potential Problems: A maximum of seven sources can be identified. There is some

subjectivity in choosing fitting species, number of sources, how to deal with missing or below 

detection limit values, and which time periods and species should be analyzed together. Sources 

of secondary species will probably violate the assumption of constant source composition. This 

can cause multiple sources to be identified for a single physical source that impacts the receptor 

under differing conditions. Supplemental analysis may be required to deconvolute these. 

2c. Positive Matrix Factorization (PMF) 

PMF uses an iterative weighted least squares method to decompose a time-by-species matrix 

to estimate the number and composition of the sources and the contributions of each source to 

each measured species. It will also calculate error estimates for these values. Selected 

References: Paatero and Tapper (1994), Paatero (1997); Xie et al. (1999). 

Data Needed: A time series of concentrations and their uncertainties for several species at a 

single monitoring location. IMPROVE data can be used. 

Model Assumptions: Concentrations are linear combinations of an unknown number of 

sources of unknown composition. Contributions from sources are positive. Source compositions

are approximately constant in time. 

Biggest Potential Problems: Correlations in detection limits or uncertainties as well as in 

concentrations can influence the results. For example, PMF may detect positive correlations 

between species either due to source activity (desirable) or measurement protocol changes 

(undesirable). 

2d. Enrichment Factors (EF) 

The differences in ratios of elemental concentrations between a reference sample and a 

measured sample are used to determine how sources may have “enriched” the concentrations of 

certain species. Some examples include: high Al/Ca has been linked to Saharan dust, high Br/Pb 

may indicate lead is linked to autos rather than industry, high Se is linked to coal burning, heavy 

metals are linked to smelting, V and Ni are linked to residual oil combustion. Selected 

References: Lawson and Winchester (1979), Parekh et al. (1989), Perru (1997), Roshid and 

Griffiths (1993). 

Data Needed: Time series of concentrations of trace elements and the species of interest. 

Some historical information about the “standard” crustal, sea salt, or other ratios for a region. 

Model Assumptions: Elemental ratios depend mostly on enrichment of trace elements by a 

source and have less dependence on meteorology. The reference ratios are constant. 

67 
Biggest Potential Problems: Attributions are generally to source areas, not to single sources. 

3a. Empirical Orthogonal Function Analysis (EOF) 

A few (typically two to six) spatial patterns that explain most of the covariance in the spatial 

and temporal patterns of a measured species are obtained by singular value decomposition. 

Associations between the spatial patterns and source areas and/or transport of air pollutants into 

the study area can often be inferred, but are qualitative. The original data matrix can be 

approximately reconstructed by linearly recombining these few patterns. Selected References: 

Gebhart and Malm (1997), Henry et al. (1991), Malm et al. (1990), Malm and Gebhart (1997). 

Data Needed: Measurements of a single air pollutant of interest at several sites for several 

time periods. Typically used are concentrations measured at fifteen to forty sites for thirty or

more time periods. There must be more time periods than sites. Data from special studies are 

often analyzed in this way. 

Model Assumptions: Only a few spatial patterns are required to explain a large majority of 

the covariance in the spatial and temporal patterns. These patterns have a physical meaning that 

can be inferred, such as transport of emissions from a source into the study area or local 

stagnation. 

Biggest Potential Problems: Source attributions are qualitative, not quantitative and 

interpretation of the spatial patterns is subjective. The model requires a site by time matrix with 

no missing values, so some method of eliminating or filling in both missing and below detection 

limit values is necessary.

3b. Receptor Model Applied to Patterns in Space (RMAPS) 

Determines the average attribution of a single species among a few source areas by 

decomposing the time by site matrix of concentrations into a source matrix and a time weighting 

matrix. Similar to UNMIX, the edges in the scatterplots between sources and non-negativity 

requirements are used to constrain the identification of sources. Selected References: Henry 

(1997 b, c, d), White (1999). 

Data Needed: Time series of concentrations of the pollutant of interest at several sites within 

a region. The model 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 months. 

Model Assumptions: Average contributions of each source area can be written as a nonnegative linear combination of the major principal components of the data. The spatial scale of

the pollutant is large compared to the spacing of the sampling sites. 

Biggest Potential Problems: If the second major assumption is violated, the concentrations 

of the pollutant at each site will have little correlation with the other sites; therefore the model 

would not apply because it relies on the common variations among sites. 

68 
4a. Tracer Mass Balance Regression (TMBR) also called Multiple Linear Regression 

(MLR) on Marker Species 

Estimates the attribution of the aerosol species of interest by a source or source type, which 

emitted or emits a unique tracer. Uncertainty estimates are also generated if included in the 

regression. The model is a regression of the tracer, possibly weighted by other factors against the 

species of interest. Selected References: Malm et al. (1989 a, b, c). 

Data Needed: Time series of ambient concentrations and their uncertainties for the aerosol 

species being apportioned and also the tracer species. 

Model Assumptions: The tracer(s) are uniquely emitted by non-overlapping groups of 

sources. Source emissions are constant over the period of ambient sampling. Deposition and 

conversion are constant for all sampling periods and can be estimated by first-order 

approximations. In the WHITEX application, sulfate oxidation rates were assumed to be related 

to RH, where RH was a surrogate for time the air mass spent in clouds. Measurement errors are 

random, uncorrelated, and normally distributed. 

Biggest Potential Problems: Tracer concentrations are not often available. Source profiles, 

deposition, and conversion all vary in time and space. 

4b. Differential Mass Balance (DMB) 

DMB estimates the fraction of a species of interest attributable to a single source that can be 

tagged with a unique tracer. The ratio of measured tracer to measured sulfate or nitrate is 

assumed to be related to the fractional contribution of the traced source. The ratio is adjusted 

based on the estimated difference between the ratio at the source to the ratio at the receptor. 

Travel times between the source and receptor are estimated based on winds, and then by using 

simple estimates of dispersion, deposition and oxidation, the tracer to secondary species ratio is 

adjusted. Selected References: Malm (1989b, c). 

Data Needed: Time series of tracer concentrations and concentrations and emission rates of 

the species of interest and its precursors, for example, sulfur dioxide and sulfate. Estimates of 

wind speed and direction, mixing heights, deposition and oxidation rates. 

Model Assumptions: Wind direction does not change during transport time. The rates for 

deposition and conversion are first-order and invariant in space and time along the transport path

between the source and the receptor. The ratio of the emission rates for the species of interest or 

its parent species and the tracer is known. 

Biggest Potential Problems: Simple chemistry and meteorology may not be adequate, 

especially for long transport times, complex terrain, and/or changing chemical regimes. Tracer 

concentrations unique to a single source are often not available. The fraction of attributable 

concentration may only be calculable to within a range based on the reasonable ranges of rate 

coefficients.

69 
4c. Tracer-Aerosol Gradient Interpretive Technique (TAGIT) 

Results are the attribution of primary or secondary species associated with the source 

“tagged” by a tracer release. TAGIT computes attributions on a sample period-by-sample period 

basis. For each sample period, background concentration of the species of interest is determined 

by averaging the concentrations of the species at nearby sites that do not have tracer 

concentrations and are significantly above background. These sites are presumed to be 

unaffected by the tracer-tagged source and thus represent the average background. This 

background for each sample period is then subtracted from the concentration of the species of 

interest at impacted receptor sites for corresponding sample periods. The difference is the 

concentration attributable to the tagged source. Green (2001), Kuhns et al. (1999), Pitchford et 

al. (2000). 

Data Needed: Concentrations of a unique tracer from a source of interest and simultaneous 

concentrations of a pollutant of interest at several sites in a region. 

Model Assumptions: There is no impact from the tagged source if the tracer concentration is 

less than the level considered to be “significantly” above its’ background. Background 

concentrations of the species of interest do not vary systematically in space. 

Biggest Potential Problems: Assuming no impact from the tagged source when tracer is not 

statistically above background can lead to an underestimation of attribution. Measured tracer 

concentrations often have large uncertainties. Some sampling periods will have a negative 

concentration attributed to the tagged source. 

References: 

Ashbaugh, Lowell L., William C. Malm, Willy Z. Sadeh (1985) “A Residence Time Probability 

Analysis of Sulfur Concentrations at Grand Canyon National Park,” Atmospheric 

Environment, 19, 1263-1270. 

Gebhart, Kristi A., Sonia A. Kreidenweiss, and William C. Malm (2001) “Back-Trajectory 

Analyses of Fine Particulate Matter Measured at Big Bend National Park in the Historical 

Database and the 1996 Scoping Study” Science of the Total Environment, 276, 185-204. 

Gebhart, Kristi A. and William C. Malm (1989) “Source Apportionment of Particulate Sulfate 

Concentrations at Three National Parks in the 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. Malm (1997) “Spatial and Temporal Patterns in Particle Data 

Measured during the MOHAVE Study,” J. of the Air & Waste Management Assoc., 47, 

119-135 

Green, Mark, 2001 (Informal paper, BRAVO) 

70 
Henry, R.S. (1997a) “History and fundamentals of multivariate air quality receptor models,” 

Chemometrics and Intelligent Laboratory Systems, 37, 37-42. 

Henry, R.C. (1997b) “Receptor Model Applied to Patterns in Space (RMAPS) Part I – Model 

Description” JA&WMA, 47, 216-219. 

Henry, R.C. (1997c) “Receptor Model Applied to Patterns in Space (RMAPS) Part II –

Apportionment of Airborne Particulate Sulfur from Project MOHAVE” JA&WMA, 47, 

220-225. 

Henry, R.C. (1997d) “Receptor Model Applied to Patterns in Space (RMAPS) Part III – 

Apportionment of Airborne Particulate Sulfur Western Washington State” JA&WMA, 47, 

226-230. 

Henry, R.C. (1999) “Comparing a new algorithm with the classic methods for estimating the 

number of factors,” Chemometrics and Intelligent Laboratory Systems, 48, 91-97. 

Lewis, C.W., R.C. Henry, and J.H. Shreffler (1998) “An Exploratory Look at Hydrocarbon Data 

from the Photochemical Assessment Monitoring Stations Network” J. Air & Waste 

Management Assoc. 48, 71-76. 

Henry, Ronald C., Yi-Jin Wang, and Kristi A. Gebhart (1991) “The Relationship Between 

Empirical Orthogonal Functions and Sources of Air Pollution,” Atmospheric 

Environment, 25A, 503-509. 

Kuhns et al. (1999) 

Lawson, D.R. and J.W. Winchester (1979) “A Standard crustal aerosol as a reference for 

elemental enrichment factors,” Atmospheric Environment, 13, 517-523. 

Malm, William C, Hari K. Iyer, and Kristi Gebhart (1989a) “Application of Tracer Mass Balance 

Regression to WHITEX Data” in Transactions of the A&WMA/EPA Specialty 

Conference: Visibility and Fine Particles, Estes Park, CO, Oct. 15-19, 1989, pp. 806-818, 

C.V. Mathai, Ed. 

Malm, William C., Hari K. Iyer, John Watson, and Douglas A. Latimer (1989b) “Survey of a 

Variety of Receptor Modeling Techniques,” Transactions of the A&WMA/EPA Specialty 

Conference-Visibility & Fine Particles, Estes Park, CO, Oct. 15-19, 1989, pp. 781-805, 

C.V. Mathai, Ed. 

Malm, William, Kristi Gebhart, Douglas Latimer, Thomas Cahill, Robert Eldred, Roger Pielke, 

Roger Stocker, and John Watson (1989) “National Park Service Report On the Winter 

Haze Intensive Tracer Experiment” National Park Service, Air Quality Division, 

Research Branch, Fort Collins, CO, Dec. 4, 1989 

71 
Malm, William C. and Kristi A. Gebhart (1997) “Source apportionment of sulfur and light 

extinction using receptor modeling techniques,” Journal of the Air & Waste Management 

Association, 47, 250-258. 

Malm, William C., Kristi A. Gebhart, and Ronald C. Henry (1990) “An Investigation of the 

Dominant Source Regions of Fine Sulfur in the Western United States and their Areas of 

Influence,” Atmospheric Environment, 24A, 3047-3060. 

Paatero, P. (1997) “Least squares formulation of robust non-negative factor analysis,” 

Chemometrics and Intelligent Laboratory Systems, 37, 15-35. 

Paatero, P. and U. Tapper (1994) “Positive Matrix Factorization – a Nonnegative Factor Model 

with Optimal Utilization of Error-Estimates of Data Values,” Environmetrics, 5, 111-126. 

Parekh, P.P., B. Ghauri, and L. Husain (1989) “Identification of Pollution Sources of 

Anomalously Enriched Elements,” Atmospheric Environment, 23, 1435-1442. 

Perru, K.D., T.A. Cahill, R.A. Eldred, and D.D. Dutcher (1997) “Long-range Transport of North 

African dust to the eastern United States,” J. Geophys. Res., 102, 11,225-11,238. 

Pitchford, Marc, Mark Green, Hampden Kuhns, and Robert 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 

may be a conference paper.) 

Poirot, Richard L. and Paul R. Wishinski (1986) “Visibility, Sulfate and Air Mass history 

Associated with the Summertime Aerosol in Northern Vermont,” Atmospheric 

Environment, 20, 1457-1469. 

Roshid, M. and R.F. Griffiths (1993) “Ambient K, S, and Si in fine and coarse aerosols of Kuala 

Lumpur, Malaysia,” Journal of Aerosol Science, 24, 597-601. 

Stohl, A. (1998) “Computation, Accuracy and Applications of Trajectories - A Review and 

Bibliography,” Atmospheric Environment, 32, 947-966. 

Watson, John G., John A. Cooper, and James J. Huntzicker (1984) “The Effective Variance 

Weighting for Least Squares Calculations Applied to the Mass Balance Receptor Model,” 

Atmospheric Environment, 18, 1347-1355. 

Watson, John G., Judith C. Chow and Eric M. Fujita (2001) “Review of volatile organic 

compound source apportionment by chemical mass balance” Atmospheric Environment, 

35, 1567-1584. 

White, Warren H. (1999) “Phantom Spatial Factors: An Example,” J. of the Air & Waste 

Management Assoc., 49, 345-349. 

72 
Xie, Yu-Long, Philip K. Hopke, Pentti Paatero, Leonard A. Barrie, and Shao-Meng Li (1999) 

“Identification of Source Nature and Seasonal Variations of Arctic Aerosol by Positive 

Matrix Factorization,” J. of the Atmospheric Sciences, 56, 249-260. 

73 
74 
Table 5. Observational Modeling Techniques 

Analyses of Back Trajectories 

Criteria Residence Ti

me & 

Source Contribution Function 

Conditional Probability 

Concentration Statistics by Air Mass History (

Mean, Max,

Median)

Cluster Analysis 

Hit – No H

Quantitative Source Attribution?

No No No No No 

Nu

mber of sources that can be distinguished? Typically only about 

10 or fewer transport patterns are distinguishable 

Maximum of 10-15 1/grid cell, typically

50x50 (2500), though usually only about 5-20 transport patterns are distinguishable 

2-15 1 

Averaging Ti

me of Result? Weeks to years Weeks to years Weeks to years Weeks to years Daily, 

possiblyhourly

Previous use at Class I Areas? (See Text for References) Yes Yes Yes Yes Yes Magnitude of impacts? No No Yes No No Frequency of impacts? Yes No No Yes Yes Duration of impacts? Yes No No Yes Yes Time of Day of impacts? Depends on particle 

data 

Depends on particle data 

Depends on particle data 

Depends on particle data 

Yes 

Ti

me of Year of i

mpacts? Yes Yes Yes Yes Yes 

Appropriate for what source-receptor distances? Regional Scale Regional Scale Regional Scale Regional Scale Regional 

Scale 

Attribution of Secondary Species? Yes Yes Yes Yes Yes Cost to run? Minimal Minimal Minimal Minimal Minimal Code Available? No No No No No Equations and/or algorith

ms available? Yes Yes Yes Yes None need

Co

mputer Hardware Needed PC PC PC PC PC 

Additional software necessary? Any program

ming 

language or statistical package and graphics and/or mapping software that allowsoverlay of data on a map

Any program

ming 

language orstatistical package and graphics and/ormapping softwarethat allows overlay of data on a 

map 

Any program

ming 

language or statistical package and graphics and/or mapping software that allowsoverlay of data on a map

Any program

ming 

language orstatistical package and graphics and/ormapping software that allows overlay of data on a 

map 

Graphing mapping software tallows overlay of data on a map

EPA Approved Model? No No No No No 

75 
Observational Modeling Techniques(continued)

Analyses of inter-species relationships Analyses o

Patterns 

Criteria C

M

B

P

M

F UNMI

X Factor Analysis E

O

F 

Quantitative Source Attributio

n? Yes Yes Yes No No 

Number of sources that can be distinguished?

Usually < 10 

Usually < 10 

7 < Number of s

pecies 

analyzed 

Usually 4-8 transport patt

A

veraging Time of Result? Same as

monitoringdata

Same as monitoringdata

Same as monitoring data

Same as

monitoring d

Pre

vious use at Class I Areas? (See Text for 

References) 

Yes No? No? Yes Yes 

Magnitude of impacts? Yes Yes Yes No No Frequency of impacts? Yes Yes Yes Yes Yes Duration of impacts? Yes Yes Yes No Yes Ti

me of Day of impacts?

Depends on

input data 

Depends oninput data 

Depe

n

ds o

n input

data

Depe

n

ds o

n input

data

Depe

n

ds o

n i

data

Time of Year of impacts? Yes Yes Yes Yes Yes Appropriate for what source-receptor distances?

Urban toregionalscales 

Urban toregionalscales 

Urban to regionalscales 

Urban to regionalscales 

Regional Sca

Attribution of Secon

dary Species?

With

ad

ditional 

informatio

n

Withad

ditional 

informatio

n

With ad

ditional 

informatio

n

Yes Yes 

Cost to run? Free to

purchase, minimal torun 

$700 to purchase, minimal torun 

Currently free to purchase, minimal to run, $100 (student)-1500 (full) for MATLAB 

Minimal Minimal 

Code A

vailable? Yes Yes Yes No No 

Equations and/or algorithms available? Yes Yes Yes Yes Yes Computer Hardware Nee

ded

P

C

P

C

P

C

P

C

P

C

Additional software necessary? No No MATLAB with

optimizatio

n

tool

box

Any statistics packa

ge 

Any statistics packa

ge with 

ability to dosingular val

u

decompositio

EPA Model? Yes No? Yes? No No 

76 
Observational Modeling Techniques (continued)

Analyses of Unique Tracer Data 

Criteria 

T

M

B

R

D

M

B TAGIT

Quantitative Source Attribution? Yes Yes Yes Number of sources that can be distinguished?

1-3 1-3 1/tra

c

er

Averaging Tim

e of Result? Sa

m

e as 

particulate data 

Sa

m

e as particulat

Previous use at Class I Areas? (See Text for References) 

Y

es Y

es Y

es

Magnitud

e o

f i

mpacts? Yes Yes Yes 

Frequency of i

mpacts? Yes Yes Yes 

Duration of impacts? Yes Yes Yes Tim

e of Day of i

mpacts? Depends on particulate data Depends on 

particulate data 

Depends on partic

Tim

e o

f Year of impacts? Yes Yes Yes 

Appropriate for what source-receptor distances? 

Urban to Regional Scale Urban to Regional 

Scale 

Regional Scale 

Attribution of Secondary Species? Yes Yes Yes Cost to run? Minim

al Minim

al Minim

al 

Code Available? No No No Equations and/or algorithmsavailable? 

Y

es Y

es Y

es

Co

mputer Hardware Needed PC PC PC 

Additional software necessary? Any programming language, 

spreadshe

et, or statistical 

package 

Any programming language, spreadsheet, or statistical package 

Any programming or statistical packa

EPA Model? No No No 

77 

Appendix A: RA BART Rule (40 CFR 51.300-306) 

Sec. 51.300 Purpose and applicability. 

 Authority: Secs. 110, 114, 121, 160-169, 169A, and 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 primary purposes of this subpart are to require States to develop programs to 

assure reasonable progress toward meeting the national goal of preventing any future, and 

remedying any existing, impairment of visibility in mandatory Class I Federal areas which 

impairment results from manmade air pollution; and to establish necessary additional procedures 

for new source permit applicants, States and Federal Land Managers to use in conducting the 

visibility impact analysis required for new sources under Sec. 51.166. This subpart sets forth 

requirements addressing visibility impairment in its two principal forms: ``reasonably 

attributable'' impairment (i.e., impairment attributable to a single source/small group of sources) 

and regional haze (i.e., widespread haze from a multitude of sources which impairs visibility in 

every direction over a large area). 

 (b) Applicability. (1) General Applicability. The provisions of this subpart pertaining to 

implementation plan requirements for assuring reasonable progress in preventing any future and 

remedying any existing visibility impairment are applicable to: 

 (i) Each State which has a mandatory Class I Federal area identified in part 81, subpart D, of 

this title, and Each State in which there is any source the emissions from which may reasonably 

be anticipated to cause or contribute to any impairment of visibility in any such area. 

 (ii)The provisions of this subpart pertaining to implementation plans to address reasonably 

attributable visibility impairment are applicable to the following States: Alabama, Alaska, 

Arizona, Arkansas, California, Colorado, Florida, Georgia, Hawaii, Idaho, Kentucky, Louisiana, 

Maine, Michigan, Minnesota, Missouri, Montana, Nevada, New Hampshire, New Jersey, New 

Mexico, North Carolina, North Dakota, Oklahoma, Oregon, South Carolina, South Dakota, 

Tennessee, Texas, Utah, Vermont, Virginia, Virgin Islands, Washington, West Virginia, 

Wyoming. 

 (3) The provisions of this subpart pertaining to implementation plans to address regional haze 

visibility impairment are applicable to all States as defined in section 302(d) of the Clean Air Act 

(CAA) except Guam, Puerto Rico, American Samoa, and the Northern Mariana Islands. 

[45 FR 80089, Dec. 2, 1980, as amended at 64 FR 35763, July 1, 1999] 

Sec. 51.301 Definitions.

 For purposes of this subpart: 

 Adverse impact on visibility means, for purposes of section 307, visibility impairment which 

interferes with the management, protection, preservation, or enjoyment of the visitor's visual 

experience of the Federal Class I area. This determination must be made on a case-by-case basis 

taking into account the geographic extent, intensity, duration, frequency and time of visibility 

impairments, and how these factors correlate with (1) times of visitor use of the Federal Class I 
area, and (2) the frequency and timing of natural conditions that reduce visibility. This term does 

not include effects on integral vistas. 

 Agency means the U.S. Environmental Protection Agency. 

 BART-eligible source means an existing stationary facility as defined in this section. 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 which is emitted by an existing stationary facility. The emission limitation 

must be established, on a case-by-case basis, taking into consideration the technology available, 

the costs of compliance, the energy and nonair quality environmental impacts of compliance, any 

pollution control equipment in use or in existence at the source, the remaining useful life of the 

source, and the degree of improvement in visibility which may reasonably be anticipated to 

result from the use of such technology. 

 Building, structure, or facility means all of the pollutant-emitting activities which belong to the 

same industrial grouping, are located on one or more contiguous or adjacent properties, and are 

under the control of the same person (or persons under common control). Pollutant-emitting 

activities must be considered as part of the same industrial grouping if they belong to the same

Major Group (i.e., which have the same two-digit code) as described in the Standard Industrial 

Classification Manual, 1972 as amended by the 1977 Supplement (U.S. Government Printing 

Office stock numbers 4101-0066 and 003-005-00176-0 respectively). 

 Deciview means a measurement of visibility impairment. 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 entire range of conditions, from pristine to highly 

impaired. The deciview haze index is calculated 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 lne (bext/10Mm-1) Where bext = the atmospheric light extinction 

coefficient, expressed in inverse megameters (Mm-1). 

 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. 

 Fossil-fuel fired steam electric plants of more 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 charging more than 250 tons of refuse per day, 

 Hydrofluoric, sulfuric, and nitric acid plants, 

 Petroleum refineries, 

 Lime plants, 

 Phosphate rock processing plants, 
 Coke oven batteries, 

 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 facilities 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 classified or reclassified Class I.

Federal Land Manager means the Secretary of the department 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-Campobello 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 any applicable State Implementation Plan, and any 

permit requirements established pursuant to Sec. 52.21 of this chapter or under regulations 

approved pursuant to part 51, 52, or 60 of this title. 

 Fixed capital cost means the capital needed to provide all of the depreciable components. 

Fugitive Emissions means those emissions which could not reasonably pass through a stack, 

chimney, vent, or other functionally equivalent opening. 

 Geographic enhancement for the purpose of Sec. 51.308 means a method, procedure, or 

process to allow a broad regional strategy, such as an emissions trading program designed to 

achieve greater reasonable progress than BART for regional haze, to accommodate BART for 

reasonably attributable impairment. 

 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 Native village, which is federally recognized as eligible for the 

special programs and services provided by the United States to Indians because of their status as 

Indians. 

 In existence means that the owner or operator has 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 the facility or (2) entered into binding agreements or contractual 

obligations, which cannot be cancelled or modified without substantial loss to the owner or 

operator, to undertake a program of construction of the facility to be completed in a reasonable 

time. 

 In operation means engaged in activity related to the primary design function of the source. 

 Installation means an identifiable piece of process equipment. 
 Integral vista means a view perceived from within the mandatory Class I Federal area of a 

specific landmark or panorama located outside the boundary of the mandatory Class I Federal 

area. 

 Least impaired days means the average visibility impairment (measured in deciviews) for the 

twenty percent of monitored days in a calendar year with the lowest amount of visibility 

impairment. 

 Major stationary source and major modification mean major stationary 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 impairment (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 that 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 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 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 observation 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. 

 Reconstruction will be presumed to have taken place where the fixed capital cost of the new 

component exceeds 50 percent of the fixed capital cost of a comparable entirely new source. Any 

final decision as to whether reconstruction has occurred must be made in accordance with the 

provisions of Sec. 60.15 (f) (1) through (3) of this title. 

 Regional haze means visibility impairment that is caused 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 sources, mobile sources, and area sources. 

 Secondary emissions means emissions which occur as a result of the construction or operation 

of an existing stationary facility but do not come from the existing stationary facility. Secondary 

emissions may include, but are not limited to, emissions from ships or trains coming to or from

the existing stationary facility. 

 Significant impairment means, for purposes of Sec. 51.303, visibility impairment which, in the 

judgment of the Administrator, interferes with the management, protection, preservation, or 

enjoyment of the visitor's visual experience of the mandatory Class I Federal area. This 

determination must be made on a case-by-case basis taking into account the geographic extent, 

intensity, duration, frequency and time of the visibility impairment, and how these factors 

correlate with (1) times of visitor use of the mandatory Class I Federal area, and (2) the 

frequency and timing of natural conditions that reduce visibility. 

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

 Stationary Source means any building, structure, facility, 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 natural conditions.

 Visibility in any mandatory Class I Federal area includes any integral vista associated with 

that area. 

[45 FR 80089, Dec. 2, 1980, as amended at 64 FR 35763, 35774, July 1, 1999] 

Sec. 51.302 Implementation control strategies for reasonably attributable visibility impairment. 

 (a) Plan Revision Procedures. (1) Each State identified in Sec. 51.300(b)(2) must have 

submitted, not later than September 2, 1981, an implementation plan meeting the requirements of 

this subpart pertaining to reasonably attributable visibility impairment. 

 (2)(i) The State, prior to adoption of any implementation plan to address reasonably 

attributable visibility impairment required by this subpart, must conduct one or more public 

hearings on such plan in accordance with Sec. 51.102. 

 (ii) In addition to the requirements in Sec. 51.102, the State must provide written notification 

of such hearings to each affected Federal Land Manager, and other affected States, and must 

state where the public can inspect a summary prepared by the Federal Land Managers of their 

conclusions and recommendations, if any, on the proposed plan revision. 

 (3) Submission of plans as required by this subpart must be conducted in accordance with the 

procedures in Sec. 51.103. 

 (b) State and Federal Land Manager Coordination. (1) The State must identify to the Federal 

Land Managers, in writing and within 30 days of the date of promulgation of these regulations, 

the title of the official to which the Federal Land Manager of any mandatory Class I Federal area 

can submit a recommendation on the implementation of this subpart including, but not limited to: 

 (i) A list of integral vistas that are to be listed by the State for the purpose of implementing 

section 304, 

 (ii) Identification of impairment of visibility in any mandatory Class I Federal area(s), and 

 (iii) Identification of elements for inclusion in the visibility monitoring strategy required by 

section 305. 

 (2) The State must provide opportunity for consultation, in person and at least 60 days prior to 

holding any public hearing on the plan, with the Federal Land Manager on the proposed SIP 

revision required by this subpart. This consultation must include the opportunity for the affected 

Federal Land Managers to discuss their: 

 (i) Assessment of impairment of visibility in any mandatory Class I Federal area, and 

 (ii) Recommendations on the development of the long-term strategy. 

 (3) The plan must provide procedures for continuing consultation between the State and 

Federal Land Manager on the implementation of the visibility protection program required by 

this subpart. 

 (c) General plan requirements for reasonably attributable visibility impairment. (1) The 

affected Federal Land Manager may certify to the State, at any time, that there exists reasonably 

attributable impairment of visibility in any mandatory Class I Federal area. 

 (2) The plan must contain the following to address reasonably attributable impairment: 

 (i) A long-term (10-15 years) strategy, as specified in Sec. 51.305 and Sec. 51.306, including 

such emission limitations, schedules of compliance, and such other measures including schedules 
for the implementation of the elements of the long-term strategy as may be necessary to make 

reasonable progress toward the national goal specified in Sec. 51.300(a). 

 (ii) An assessment of visibility impairment and a discussion of how each element of the plan 

relates to the preventing of future or remedying of existing impairment of visibility in any 

mandatory Class I Federal area within the State.

 (iii) Emission limitations representing BART and schedules for compliance with BART for 

each existing stationary facility identified according to paragraph (c)(4) of this section.

 (3) The plan must require each source to maintain control equipment required by this subpart 

and establish procedures to ensure such control equipment is properly operated and maintained. 

 (4) For any existing reasonably attributable visibility impairment the Federal Land Manager 

certifies to the State under paragraph (c)(1) of this section, at least 6 months prior to plan 

submission or revision: 

 (i) The State must identify and analyze for BART each existing stationary facility which may 

reasonably be anticipated to cause or contribute to impairment of visibility in any mandatory 

Class I Federal area where the impairment in the mandatory Class I Federal area is reasonably 

attributable to that existing stationary 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 months before plan 

submission. 

 (ii) If the State determines that technologicial or economic limitations on the applicability of 

measurement methodology to a particular existing stationary facility would make the imposition 

of an emission standard infeasible it may instead prescribe a design, equipment, work practice, or 

other operational standard, or combination thereof, to require the application of BART. 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. 

 (iii) BART must be determined for fossil-fuel fired generating plants having a total generating 

capacity in excess of 750 megawatts pursuant to ``Guidelines for Determining Best Available 

Retrofit Technology for Coal-fired Power Plants and Other Existing Stationary Facilities''

(1980), which is incorporated by reference, exclusive 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. Department of Commerce, National Technical Information Service,

5285 Port Royal Road, Springfield, Virginia 22161. It is also available for inspection at the 

Office of the Federal Register Information Center, 800 North Capitol NW., suite 700, 

Washington, DC. 

 (iv) The plan must require that each existing stationary facility required to install and operate 

BART do so as expeditiously as practicable but in no case later than five years after plan 

approval. 

 (v) The plan must provide for a BART analysis of any existing stationary facility that might 

cause or contribute to impairment of visibility in any mandatory Class I Federal area identified 

under this paragraph (c)(4) at such times, as determined by the Administrator, as new technology 

for control of the pollutant becomes reasonably available if: 

 (A) The pollutant is emitted by that existing stationary facility, 

 (B) Controls representing BART for the pollutant have not previously been required under this 

subpart, and 

 (C) The impairment of visibility in any mandatory Class I Federal area is reasonably 

attributable to the emissions of that pollutant. 
[45 FR 80089, Dec. 2, 1980, as amended at 57 FR 40042, Sept. 1, 1992; 64 

FR 35764, 35774, July 1, 1999] 

 

Sec. 51.303 Exemptions from control. 

 (a)(1) Any existing stationary facility subject to the requirement under Sec. 51.302 to install, 

operate, and maintain BART may apply to the Administrator for an exemption from that 

requirement. 

 (2) An application under this section must include all available documentation relevant to the 

impact of the source's emissions on 

visibility in any mandatory Class I Federal area and a demonstration by the existing stationary 

facility that it does not or will not, by itself or in combination with other sources, emit any air 

pollutant which may be reasonably anticipated to cause or contribute to a significant impairment 

of visibility in any mandatory Class I Federal area. 

 (b) Any fossil-fuel fired power plant with a total generating capacity of 750 megawatts or 

more may receive an exemption from BART only if the owner or operator of such power plant 

demonstrates to the satisfaction of the Administrator that such power plant is located at such a 

distance from all mandatory Class I Federal areas that such power plant does not or will not, by 

itself or in combination with other sources, emit any air pollutant which may reasonably be 

anticipated to cause or contribute to significant impairment of visibility in any such mandatory 

Class I Federal area. 

 (c) Application under this Sec. 51.303 must be accompanied by a written concurrence from the 

State with regulatory authority over the source. 

 (d) The existing stationary facility must give prior written notice to all affected Federal Land 

Managers of any application for exemption under this Sec. 51.303. 

 (e) The Federal Land Manager may provide an initial recommendation or comment on the 

disposition of such application. Such recommendation, where provided, must be part of the 

exemption application. This recommendation is not to be construed as the concurrence required 

under paragraph (h) of this section. 

 (f) The Administrator, within 90 days of receipt of an application for exemption from control, 

will provide notice of receipt of an exemption application and notice of opportunity for public 

hearing on the application. 

 (g) After notice and opportunity for public hearing, the Administrator may grant or deny the 

exemption. For purposes of judicial review, final EPA action on an application for an exemption 

under this Sec. 51.303 will not occur until EPA approves or disapproves the State 

Implementation Plan revision. 

 (h) An exemption granted by the Administrator under this Sec. 51.303 will be effective only 

upon concurrence by all affected Federal Land Managers with the Administrator's determination. 

[45 FR 80089, Dec. 2, 1980, as amended 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 may identify any integral 

vista. The integral vista must be identified according to criteria the Federal Land Manager 
develops. These criteria must include, but are not limited to, whether the integral vista is 

important to the visitor's visual experience of the mandatory Class I Federal area. Adoption of 

criteria must be preceded by reasonable notice and opportunity for public comment on the 

proposed criteria. 

 (b) The Federal Land Manager must notify the State of any integral vistas identified under 

paragraph (a) of this section, and the reasons therefor. 

 (c) The State must list in its implementation plan any integral vista the Federal Land Manager 

identifies at least six months prior to plan submission, and must list in its implementation plan at 

its earliest opportunity, and in no case later than at the time of the periodic review of the SIP 

required by Sec. 51.306(c), any integral vista the Federal Land Manager identifies after that time. 

 (d) The State need not in its implementation plan list any integral vista the identification of

which was not made in accordance with the criteria in paragraph (a) of this section. In making 

this finding, the State must carefully consider the expertise of the Federal Land Manager in 

making the judgments called for by the criteria for identification. Where the State and the 

Federal Land Manager disagree on the identification of any integral vista, the State must give the 

Federal Land Manager an opportunity to consult with the Governor of the State. 

[45 FR 80089, Dec. 2, 1980, as amended by 64 FR 35774, July 1, 1999] 

 

Sec. 51.305 Monitoring for reasonably attributable visibility impairment. 

 (a) For the purposes of addressing reasonably attributable visibility impairment, each State 

containing a mandatory Class I Federal area must include in the plan a strategy for evaluating 

reasonably attributable visibility impairment in any mandatory Class I Federal area by visual 

observation or other appropriate monitoring techniques. Such strategy must take into account 

current and anticipated visibility monitoring research, the availability of appropriate monitoring 

techniques, and such guidance as is provided by the Agency. 

 (b) The plan must provide for the consideration of available visibility data and must provide a 

mechanism for its use in decisions required by this subpart. 

[45 FR 80089, Dec. 2, 1980, as amended at 64 FR 35764, July 1, 1999] 

Sec. 51.306 Long-term strategy requirements for reasonably attributable visibility impairment. 

 (a)(1) For the purposes of addressing reasonably attributable visibility impairment, each plan 

must include a long-term (10-15 years) strategy for making reasonable progress toward the 

national goal specified in Sec. 51.300(a). This strategy must cover any existing impairment the 

Federal Land Manager certifies to the State at least 6 months prior to plan submission, and any 

integral vista of which the Federal Land Manager notifies the State at least 6 months prior to plan 

submission. 

 (2) A long-term strategy must be developed for each mandatory Class I Federal area located 

within the State and each mandatory Class I Federal area located outside the State which may be 

affected by sources within the State. This does not preclude the development of a single 

comprehensive plan for all such areas.
 (3) The plan must set forth with reasonable specificity why the long-term strategy is adequate 

for making reasonable progress toward the national visibility goal, including remedying existing 

and preventing future impairment. 

 (b) The State must coordinate its long-term strategy for an area with existing plans and goals, 

including those provided by the affected Federal Land Managers, that may affect impairment of 

visibility in any mandatory Class I Federal area. 

 (c) The plan must provide for periodic review and revision, as appropriate, of the long-term

strategy for addressing reasonably attributable visibility impairment. The plan must provide for 

such periodic review and revision not less frequently than every 3 years until the date of

submission of the State's first plan addressing regional haze visibility impairment in accordance 

with Sec. 51.308(b) and (c). On or before this date, the State must revise its plan to provide for 

review and revision of a coordinated long-term strategy for addressing reasonably attributable 

and regional haze visibility impairment, and the State must submit the first such coordinated 

long-term strategy. Future coordinated long-term strategies must be submitted consistent with the 

schedule for periodic progress reports set forth in Sec. 51.308(g). Until the State revises its plan 

to meet this requirement, the State must continue to comply with existing requirements for plan 

review and revision, and with all emission management requirements in the plan to address 

reasonably attributable impairment. This requirement does not affect any preexisting deadlines 

for State submittal of a long-term strategy review (or element thereof) between August 30, 1999, 

and the date required for submission of the State's first regional haze plan. In addition, the plan 

must provide for review of the long-term strategy as it applies to reasonably attributable 

impairment, and revision as appropriate, within 3 years of State receipt of any certification of 

reasonably attributable impairment from a Federal Land Manager. The review process must 

include consultation with the appropriate Federal Land Managers, and the State must provide a 

report to the public and the Administrator on progress toward the national goal. This report must 

include an assessment of: 

 (1) The progress achieved in remedying existing impairment of visibility in any mandatory 

Class I Federal area; 

 (2) The ability of the long-term strategy to prevent future impairment of visibility in any 

mandatory Class I Federal area; 

 (3) Any change in visibility since the last such report, or, in the case of the first report, since 

plan approval; 

 (4) Additional measures, including the need for SIP revisions, that may be necessary to assure 

reasonable progress toward the national visibility goal; 

 (5) The progress achieved in implementing BART and meeting other schedules set forth in the 

long-term strategy; 

 (6) The impact of any exemption granted under Sec. 51.303; 

 (7) The need for BART to remedy existing visibility impairment of any integral vista listed in 

the plan since the last such report, or, in the case of the first report, since plan approval. 

 (d) The long-term strategy must provide for review of the impacts from any new major 

stationary source or major modifications on visibility in any mandatory Class I Federal area. This 

review of major stationary sources or major modifications 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 mandatory Class I Federal 

areas. 
 (e) The State must consider, at a minimum, the following factors during the development of its 

long-term strategy: 

 (1) Emission reductions due to ongoing air pollution control programs, 

 (2) Additional emission limitations and schedules for compliance, 

 (3) Measures to mitigate the impacts of construction activities, 

 (4) Source retirement and replacement schedules, 

 (5) Smoke management techniques for agricultural and forestry management purposes 

including such plans as currently exist within the State for these purposes, and 

 (6) Enforceability of emission limitations and control measures. 

 (f) The plan must discuss the reasons why the above and other reasonable measures considered 

in the development 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 strategy, must take into account the effect of new 

sources, and the costs of compliance, the time necessary for compliance, the energy and nonair 

quality environmental impacts of compliance, and the remaining useful life of any affected 

existing source and equipment therein. 

[45 FR 80089, Dec. 2, 1980, as amended at 64 FR 35764, 35774, July 1, 1999] 
Appendix A-9 – Mobile Sources Arizona Regional Haze SIP

APPENDIX A-9. MOBILE SOURCES

This appendix contains work products and references relied upon 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 the 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 Colorado Plateau. The other Class I areas 

within the State will not be addressed 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 formed the basis for those regulations, and 

information from the Western Regional Air Partnership (WRAP). 

The MSWG provides this report to the Arizona Department of Environmental Quality 

(ADEQ) for their consideration in preparing the Arizona Regional Haze State 

Implementation Plan (SIP). 

Summary of Findings 

Based on the analysis of available data, the MSWG finds that mobile source emissions 

in Arizona do not significantly contribute to visibility impairment 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 organic compounds (VOC), oxides of nitrogen (NOX), sulfur dioxide 

(SO2), elemental carbon (EC), organic carbon (OC), and fine particulates (PM2.5) for the 

years 2003 to 2018; air quality modeling and other technical information available from 

the WRAP; their approach in making the significance 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 emissions of VOC, NOx, PM2.5, SO2, EC, and OC will decline 

from 2003 to 2018. 

2) Year to year mobile source emissions of VOC, NOx PM2.5, EC, and OC are 

expected to decline from 2003 to 2018. 

3) Annual mobile source emissions of SO2 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. The minor increase is uncertain and 

cannot be accurately quantified and will be further addressed in the Technical 
Support Document (TSD). In the event that the EPA proposed non-road 

standards are not adopted, Arizona will be required to submit a SIP revision as 

proposed by the WRAP, in their letter dated May 6, 2003 to ensure reasonable 

progress prior to December 31, 2008. 

4) Annual mobile source emissions of VOC, NOx PM2.5, EC, and OC are expected 

to have a minimal impact on visibility. 

5) Reasonable progress will be achieved over the planning period with the 

projected emission reductions. 

6) The relative contribution of mobile source SO2 emissions is insignificant 

compared to that of the emissions from stationary sources. 

7) There is considerable uncertainty in regulations and projections of emissions. 

The projected increase in SO2 for the later part of the planning period is not 

certain. By 2008, the emissions for 2013 can be better assessed with some 

certainty. 

REGULATORY REQUIREMENT 

Regional Haze Rule

The federal RHR relies upon the GCVTC report as the basis for states to submit a SIP 

under 40 CFR 51.309(d)(5). 

Section 309 of the RHR requires states to evaluate mobile source emissions, and if they

are determined to significantly contribute to regional haze in the 16 Class I areas, then 

additional provisions apply. 

SIPs developed under Section 309 must include the following elements: 

• A statewide inventory of current mobile source emissions and projected future 

emissions of VOC, NOX, SO2, PM2.5, EC, and OC, for the years 2003 to 2018.

The emissions inventory must also include 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 source emissions from any areas in the 

state “contribute significantly” to visibility impairment at any of the 16 Class I 

areas (40 CFR 51.309(d)(5)(ii)). 

• If any area of the state is found to contribute significantly to visibility

impairment at any of those 16 Class I areas, the SIP must also include: 

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o An emission budget (cap) and measures to ensure that emissions do not

increase beyond their lowest projected levels for the planning period (40 

CFR 51.309(d)(5)(iii)(A)). 

o An emission tracking system to ensure that mobile source emissions do 

not increase thereafter (40 CFR 51.309(d)(5)(iii)(B)). 

• Progress reports to EPA on the implementation of mobile source 

recommendations of the GCVTC (40 CFR 51.309(d)(5)(iv). 

In the event that EPA finalizes the rule change as proposed, 51.309(d)(5)(ii) and (iii) 

above will then be removed (see below). 

WRAP APPROACH TO SIGNIFICANCE DETERMINATION

Recently, the WRAP concluded that the attempt to measure mobile source significance 

is no longer necessary because new federal programs will achieve continual emission 

reductions as required for significant areas in Section 309(d)(5)(iii). On May 6, 2003,

the WRAP submitted a letter to EPA proposing amendments to the RHR to eliminate

the requirement to conduct the mobile source significance determination, and to 

address non-road mobile sources of SO2. The WRAP letter is provided in Attachment A. 

The EPA has published these changes to the rule (Federal Register Vol.68, No. 128, 

July 3, 2003), along with a 30-day comment period. EPA has proposed a direct final for

the rule. Even if the rule is challenged it still could be finalized by the end of the year. 

Proposed WRAP Amendments: Significance Requirements 

The GCVTC and the final RHR assumed that mobile sources were expected to decline 

from 2003-2005 and increase annually through 2018. As noted above, the rule required 

emission budgets in “significant” areas to prevent the increase in emissions. That goal 

is being achieved without emission caps because of new federal programs: Tier 1 

gasoline sulfur controls in January 2001, and Tier 2 motor vehicle controls in February 

2000, and heavy-duty engine and vehicle standards and highway diesel sulfur controls 

in October 2000 and January 2001. New and updated emissions models predict 

dramatic emission reductions from these programs. Therefore, the WRAP 

recommended that EPA remove the requirements for the significance determination in 

Sections 40 CFR 51.309(d)(5)(ii) and (iii) and amend the rule to require states to 

demonstrate and monitor a continuous reduction of mobile source emissions of each of

the pollutants. 

Proposed WRAP Amendments: SO2 Emission Reductions 

The WRAP recommendation also specifically addresses the issue of the projected 

increase in SO2 emissions from non-road mobile sources in the late years of the 

planning period (2013-2018). Earlier this year, EPA proposed new standards for nonroad equipment and non-road diesel fuels that will dramatically reduce SO2 emission 

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and ensure continued emission reductions for this pollutant (Federal Register Vol.68, 

No. 100, May 23, 2003). Those rules will not be finalized before December 31, 2003, 

the deadline for states to submit their Regional Haze SIPs. Therefore, the WRAP

proposed amendment would require states to submit SIP revisions by 2008 to assess 

whether reasonable progress is being made and if necessary take action to reduce nonroad SO2 emissions if the EPA does not adopt the proposed federal standard to ensure 

reasonable progress. 

SIGNIFICANCE DETERMINATION AND FINDINGS 

The MSWG has determined that mobile sources emissions within areas in Arizona do 

not contribute significantly to visibility degradation at the 16 Class I areas. This 

conclusion also supports the WRAP recommendation that determination of mobile

source emissions impact should be removed from the RHR and replaced with a 

requirement for states to demonstrate continual mobile source emission reductions over

the planning period, considering economic and technological reasonableness and 

applicable state authority of the strategy. 

In making the significance determination, the MSWG analyzed the Arizona mobile 

source emissions and the impact of the new federal programs to determine if 

continuous reductions were achieved for each of the pollutants throughout the planning 

period. The MSWG evaluated the technical data and recent modeling results prepared 

by ENVIRON for the WRAP. The findings provided below are based upon that review. 

Current and Projected Emissions from Mobile Sources 

Inventory

The WRAP developed comprehensive emission inventories for mobile sources for the 

State of Arizona and other western states in 5-year increments. It is assumed that

interim years follow the 5-year trends. This 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 from these two counties follow that of the 

State totals, with their emissions continuing to decline over the planning period. The 

current and projected statewide inventories of emissions from mobile sources are 

shown in Table 1. 

Table 1: Arizona Projected Emissions for Mobile Sources 

2003 through 2018 TPD 

AZ. Total 

2003 989.1

2008 733.1

2013 582.2

2018 495.9

% Change -50%

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Finding 1. Mobile source emissions of all pollutants (VOC, NOx, PM2.5, EC, OC, 

and SO2) decline from 2003 to 2018. 

The analysis of the Arizona data parallels that of the regional analysis conducted by the 

WRAP. The success of new mobile source control programs is demonstrated most 

clearly in the dramatic reductions of emissions from 2003 to 2018. During this period of

continued growth in population and vehicle miles traveled (VMT), all mobile source 

emissions are reduced. The total of all mobile source emissions decline 50% for the 

planning period. An analysis of the data for each pollutant during that same period 

shows that emissions of VOC and NOx steadily decline (by 51% and 52% respectively), 

while PM2.5 shows a decrease of 22%. Additionally, because both EC and OC are 

represented as a percentage of the PM2.5 we can assume that both EC and OC will 

follow the reduction observed in PM2.5; SO2 also declines by 11% (Attachment B). 

Finding 2. Year to year mobile source emissions of VOC, NOx, PM2.5, EC, and 

OC are expected to decline from 2003 to 2018. 

The GCVTC recommended that emissions show reasonable progress. The GCVTC 

defined reasonable progress as steady and continuing emission reductions that, in the 

long-term, lead to improvements in visibility. This is used as the measure of reasonable 

progress under Section 309. The WRAP and EPA interpretation of the rule requires

that each pollutant must be measured separately in the demonstration of continual 

reductions. 

Attachment B provides a demonstration that VOC, NOx, and PM2.5, and hence EC and 

OC, each show annual reductions in the planning period and thus meet the reasonable 

progress goal in the RHR. 

Finding 3. Annual mobile source emissions of SO2 are expected to continually

decline from 2003 to 2013 with a minor increase from 2013 to 2018 with proposed 

federal sulfur standards for non-road diesel. 

Annual mobile source emissions of SO2 show an overall decline of 11% over the 

planning period with existing federal programs (Attachment B). The proposed non-road

federal standards are expected to ensure annual emission reductions (Attachment C). 

As noted in the WRAP letter of May 6, 2003, the proposed federal non-road standards

are critical to this progress. As long as EPA adopts the proposed federal non-road

standards, reasonable progress is achieved. Without these standards, the annual 

emission reductions for mobile sources are achieved only until 2013 when SO2

emissions increase from 9.5 tons/day to 18.6 tons/day (Attachment B). If the non-road 

standards are adopted, the overall SO2 emissions will decline by 27% from 2003 to

2018. The slight increase from 2013 to 2018 is uncertain and cannot be accurately

quantified and will be further addressed in the TSD. If EPA fails to adopt the proposed

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standards by 2008, Arizona will have adequate time to reassess the progress and adopt 

state standards if necessary to account for any emissions increases in mobile source

emissions. Even though some uncertainty exists in these projections, the new 

standards would ensure that annual emissions would decline for SO2 emissions and 

therefore all mobile sources emissions in the state. 

The RHR clearly does not require a separate analysis of on-road and non-road 

emissions in making the significance determination. However, the evaluation of the SO2

emissions data demonstrates the importance of the federal non-road rule (see

Attachments B and C). A comparison of emissions in the years 2003 and 2018 from 

Attachment B shows that on-road SO2 emissions decrease by 78%, while non-road SO2

emissions decrease until 2013 and then increase late in the planning period, resulting in 

a 46% increase overall. That increase is without the proposed federal non-road 

standards. Assuming the proposed federal standards are adopted (see Attachment C), 

the non-road SO2 emissions decline by 27%. 

The point is made even more dramatically in a comparison of 2018 non-road SO2

emissions in Attachments B and C, showing that 2018 SO2 emissions will be 16.5

tons/day without controls and 8.2 tons/day if the proposed federal standards are 

adopted. This will result in a 50% reduction in non-road SO2 emissions. 

Finding 4. Annual mobile source emissions of VOC, NOx, PM2.5, EC, and OC are 

expected to have a minimal impact on visibility. 

The WRAP performed a modeling analysis to estimate the impact of mobile source 

emissions from Phoenix Metropolitan area at the GCVTC Class I in 2018. The forecast

year 2018 was chosen since it represents the year with the lowest emissions, and is at

the end of the planning period. Table 2 summarizes the relative impact of emissions

from the Phoenix Metropolitan area at the 16 GCVTC Class I areas, expressed as a 

percentage of the projected 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 between 0% and 4% of the projected light extinction. 

Table 2. Contribution to Light Extinction from Phoenix Mobile Source Emissions 

(Expressed as a % of WRAP 2018 Base Case Light Extinction) 

Class I Area

on the Colorado Plateau Phoenix 

Arches NP 0% 

Black Canyon NP 0% 

Bryce Canyon NP 0% 

Canyonlands NP 0% 

Capitol Reef NP 0% 

Flat Tops Wilderness 0% 

Grand Canyon NP 1% 

Maroon Bells Wilderness 0% 

Mesa Verde NP 1% 

Mount Baldy Wilderness 2% 

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Petrified Forest NP 4% 

San Pedro Parks WA 1% 

Sycamore Canyon WA 2% 

West Elk Wilderness 0% 

Weminuche Wilderness 0% 

Zion NP 0% 

Source: Table 3. Percent change in light extinction over 2018 WRAP Base Case

Conditions at the 16 Class I areas on the Colorado Plateau due to Mobile Source

Emissions from the 9 GCVTC States, California, Phoenix, and Las Vegas, “WRAP 

Technical memorandum from the Air Quality Modeling Forum to the Mobile Source 

Forum”, November 4, 2002. 

Finding 5. Reasonable progress will be achieved over the planning period with 

the projected emission reductions for all mobile source pollutants. 

The GCVTC definition of reasonable progress is thus met in findings 2 and 3 above,

assuming the adoption of the proposed federal non-road rules. 

Finding 6. The relative contribution of mobile source SO2 is insignificant

compared to that of stationary sources. 

Based upon data from the WRAP Annex, the category of stationary sources is the 

primary source of SO2 contributing to regional haze in the GCVTC 16 class I areas. In 

Arizona, the mobile source contribution to the total concentration of SO2 is relatively

small. In 2003, it represents about 5.3% of the total; while in 2018, with EPA’s

proposed rule, it is about 3.9% of total emissions. These data also show that the 

potential relative contribution of mobile sources emissions to the total SO2 would be 

decreasing at a greater rate than that of stationary sources with EPA’s new proposed 

non-road rule. This continued improvement in mobile source emissions is the result of 

stringent federal programs created after the 1995 GCVTC report. Therefore, the WRAP 

concluded that the Commission’s concern about the potential impact from mobile 

sources has been addressed. Additional federal control programs for mobile sources

will provide an even greater improvement in emissions in upcoming years. 

Finding 7. The uncertainty in regulations and projections in emissions adds to 

the determination. 

It is important to note that uncertainty exists in several areas: 1) the adoption of the 

proposed federal non-road standards as proposed on May 23, 2003; 2) the projected 

benefits that might be achieved, and 3) the projections of emissions from the model for

the later years. When looking at the data, the projections for the early years are likely to 

be more valid than those estimated for 2018. This uncertainty can be addressed 

through periodic reporting on the progress of the reduction in mobile source emissions 

and then making adjustments in the SIP. 

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MSWG RECOMMENDATION TO ADEQ FOR SIGNIFICANCE DETERMINATION: 

Based on this analysis, the MSWG concludes that mobile source emissions do not

significantly 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 that 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 information from the WRAP analysis 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 GCVTC goal of 

continued reduction throughout the planning period based upon new and proposed 

federal programs with the EPA adoption of the proposed non-road rules. In the event 

that EPA’s proposed non-road standards are not realized, the WRAP recommends that 

states be required to file a SIP revision to ensure reasonable progress prior to 

December 31, 2008. 

Based upon the findings above, the MSWG recommends that ADEQ consider this 

report in preparing the significance determination for the Arizona Regional Haze SIP. 

Should the proposed revisions to the RHR become effective prior to the submission of 

the Arizona SIP under Section 309, references 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 Arizona Mobile Source Emissions by Pollutant Projected for 2003 through 

2018 Assuming No New Regulations” 

Attachment C “Total Arizona Mobile Source Emissions by Pollutant Projected for 2003 through 

2018, Assuming a 15 ppm Sulfur Non-road Diesel Standard” 

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Attachment A 

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VOC NOx PM2.5 SO2 Total

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

% Change -51% -52% -22% -11% -50%

VOC NOx PM2.5 SO2* Total

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

% Change -38% -28% -6% 46% -28%

*2003 and 2018 are actual model outputs;

 2008 and 2013 are extrapolated and assumed to be linear.

VOC NOx PM2.5 SO2 Total

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

% Change -55% -63% -48% -78% -59%

Non-road

On-road

State Total

Attachment B

Total Arizona Emission by Pollutant

Projections for 2003 through 2018

Assume No New Regulations

(TPD)

 

Note: Both EC and OC are represented as a percentage of the PM2.5 and we can 

assume that both EC and OC will follow the changes observed in PM2.5

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VOC NOx PM2.5 SO2 Total

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

% Change -51% -52% -22% -51% -51%

Note: Assumes all the reductions associated with 15 ppm Standard 

come between 2013 and 2018

VOC NOx PM2.5 SO2 Total

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

% Change -38% -28% -6% -27% -31%

VOC NOx PM2.5 SO2 Total

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

% Change -55% -63% -48% -78% -59%

Non-road

On-road

State Total

Attachment C

Total Arizona Emission by Pollutant

Projections for 2003 through 2018

Assume a 15 ppm Sulfur Non-road Diesel Standard

(TPD)

 

Note: Both EC and OC are represented as a percentage of the PM2.5 and we can 

assume that both EC and OC will follow the changes observed in PM2.5

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