p.1 

OAR Box 1781 

Prepped by Ollie Stewart 

Document Number: 

12)11-1-4 

Docket Number: 

A-90-37 

Printed 10/29/2008 10:46:18 AM Sheet 12 of 142 
P.2 

A-^o-37 

TT-I-'H 

TERRY c. BRANSTA0, GOVERNOR DEPARTMENT OF NATURAL RESOURCES 

March 4,1993

 LARRY J'WIUS0N

-

0iKCrc* 

William B.Marx 

President 

Council of Industrial Boiler Owners 

6035 Burke Centre Parkway, Suite 360 

Burke, Virginia 22015 

Dear Mr. Marx: 

This is in response to your faxed copy of correspondence addressed to Peter Hamlin of my 

staff, received this date. You requested an extension of the comment period on a proposed 

Prevention of Significant Deterioration Permit for ADM's planned boiler #4 at Cedar Rapids, 

Iowa. 

This department has followed all federal and state procedural steps in reviewing this permit 

application, including providing ample notice and opportunity for public comment. This public 

comment period remains open through Monday, March 8, 1993. I see no valid reason for 

further extending this comment period. Your request for extension is therefore denied. 

Sincerely, 

Allan E. Stokes 

Administrator 

Environmental Protection Division 

cc: Peter Hamlin 
P.3 

r 

March 4, 1993 

Peter R. Hamlin, Chief 

Air Quality Bureau 

Wallace State Office Building 

Des Moines, IA 50319 

Dear Mr. Hamlin, 

. This is confirmation of my phone request today that the 

comment period on the ADM PSD request on Boiler #4 at Cedar 

Rapids be extended for one week. This would allow the Council of 

Industrial Boiler Owners (CIBO) time to prepare a comprehensive 

statement on the state's draft permit. You explained that since 

the applicable PSD procedures had been followed the request was 

denied. While your position meets the statutory requirements, 

CIBO's request for extension is well justified on the basis of 

the national interest, since your proposed permit conditions 

would set a new level of stringency for all coal-fired units, 

which might become a baseline for industrial (and utility) 

projects in other states. 

Therefore, we urgently.request a reconsideration of your 

denial of our request for a 7-day extension. 

Sincerely, 

yilliam B. Marx' 

President 

WBM/bj o 

cc: A. Presziosi 

COUNCIL OF INDUSTRIAL BOILER OWNERS 

6035 Burke Centre Parkway. Suite 360. Burke. Virginia 22015 • Phone: (703) 250-9042 • FAX: (703) 239-9042 
P.4 

cito# 

MEMORANDU M 

February 17, 1993 

TO: 

FROM: 

SUBJECT: 

NOx Subcommittee 

Environmental Committee 

William B. Marx ioSH^. 

Iowa Department of Natural Resources, ADM PSD Permit 

Request, Cedar Rapids Boiler No. 4 

Enclosed please find the following documents: 

a. PUBLIC NOTICE, The Iowa Department of Natural 

Resources, Archer Daniels Midland Company; 

b. Prevention of Significant Deterioration Permit 

Review Fact Sheet; 

c. IDNR Project No. 90-222, Plant Number 57-01-080; 

d. NOx BACT Analysis, ADM Cedar Rapids Boiler #4, 

Control Technology Feasibility. 

CIBO plans to support ADM in its objection to the state's 

conditions - 0.06 lbs/MMB SD2, 0.06 lbs/MMB NOx (50ppm) and 0.20 

lbs/MMB CO, as well as limits on fluoride, lead and beryllium -

by far the most onerous we've seen to date for coal. These 

conditions, if allowed to stand, might well become a precedent 

and be the death knell for future industrial coal use. 

Please give this matter your full and immediate attention -

it is both urgent and important. 

Note the comment period closes March 8; therefore be sure 

your comments are in Lauren Laabs' hands no later than 5 p.m., 

Thursday, March 4, copy to CIBO. 

Thanks for your cooperation. 

WBM/bjo 

cc: Mark Calmes 

Kyd Brenner 

Dennis C. Williams 

Joint Fuels/Environmental Committee 2/11/93 AttendeesCOUNCIL OF INDUSTRIAL BOILER OWNERS 

6035 Burke Centre Parkway. Suite 360. Burke. Virginia 22015 • Phone: (703) 250-9042 • FAX: (703) 239-9042 
P.5 

*" ' PUBLIC NOTICE 

The Iowa Department of Natural Resources ' 

Archer Daniels Midland Company • (ADM) has applied to the Iowa 

Department of Natural Resources (DNR) for a Prevention of 

Significant Deterioration of Air Quality (PSD) permit to install a 

new fluidized bed combustion steam boiler and related cogeneration 

equipment at its corn processing plant located near Cedar Rapids, 

Iowa. The proposed project Is considered a "major modification" of 

an existing stationary source because emissions of nitrogen oxides, 

sulfur dioxide, particulates, carbon monoxide, and fluoride will 

increase by an amount in excess of significant levels specified in 

the PSD regulations. 

Based upon the information provided by ADM on or about November 5, 

1990; on October 19, 1992; and in other applicable submissions, DNR 

has determined that the proposed project meets the requirements of 

4 0 CFR 52.21 (1) through (r) as adopted by DNR by reference at 567 

Iowa Administrative Code section 22.4. DNR has further determined 

that emissions from the proposed project will not cause or 

contribute to a violation of the National Ambient Air Quality 

Standards (NAAQS). Therefore, DNR is issuing a draft permit 

approving the proposed project. 

It is DNR'B determination that this proposed project will consume 

< 0.1 ug/m3 of the nitrogen oxide-increment, leaving 24.8 ug/zn3 of 

available nitrogen oxide increment at this location. It is DNR's 

determination that this proposed project will consume < 22.2, < 

6.7, and < 0.4 ug/m3 of the 3-hour, 24-hour, and annual sulfur 

dioxide increment, respectively. This leaves > 4 04.6, > 56.5, and 

> 18.07 ug/m3 of the 3-hour, 24-hour, and annual sulfur dioxide 

increment, respectively, -available at this location. It is DNR's 

determination that this proposed project will consume < 0.4 and < 

0.1 ug/m3 of the 24-hour and annual particulate increment, 

respectively. This leaves 5.8 and 15.7 ug/m3 of the 24-hour and 

annual particulate increment, respectively, available at this 

location. 

A copy of all the. materials submitted by the applicant, the draft 

PSD permit, and a fact sheet describing the project and review in 

greater detail are available for public inspection at the Linn 

County Health Department, 501 Thirteenth street N.W., Cedar Rapids, 

Iowa, 52405. In addition, a copy or summary of other materials 

considered in making the preliminary determination, including 

comments received following a previously held public hearing, will 

be available at this location. A complete record of the permit 

review is available for inspection at the Iowa Department of 

Natural Resources, Filth Floor, Wallace State Office Building, Des 

.Moines, Iowa 50319. At the close of the public comment period, 

comments received by DNR also will be made available at the Linn 

County Health Department and at DNR. Additionally, when a final 

determination is made by DNR, that final determination will be made 

available at these locations. 
P.6 

t7 PaREVENTION O F SIGNIFICANT DETERIORATION 

PERMIT REVIEW 

FAC T SHEET ' 

ARCHE R DANIELS MIDLAN D COMPAN Y 

Introduction 

Archer Daniels Midland Company (ADM) has applied to the Iowa Department of 

Natural Resources (DNR ) for a Prevention of Significant Deterioration o f Air Quality 

(PSD)- permit and a State o f Iowa Air Quality Construction Permit to install a new 

fluidized bed combustion steam generator and related cogeneration equipment at its co m 

processing plant located near Cedar Rapids, Linn County, Iowa. 

D N R finds that the proposed project is subject to the requirements of 567 Iowa 

Administrative Code chapter 22 aod that a State of Iowa Air Quality permit should issue. 

Thes e proposed new sources also have been reviewed to determine whether they are 

subject to the PS D regulations promulgated pursuant to 4 2 U.S. C sections 7470 et al. 

(Clean Air Act (CAA) sections 160 ct al.) and found in 40 C.F.R. Part 5 1 This review 

has been conducted as a result of the Environmental Protection Agency's delegation to 

D N R of the responsibility to review sources in Iowa for compliance with PSD. DN R 

finds that the proposed project is subject to these regulations. 

T he purpose of PS D is to prevent significant deterioration of the air quality in identified 

regions. Within these regions, there is a classification system which declares whether and 

the extent to which the air quality may be deteriorated. PS D regulations affect tbe 

construction or modification of major industrial facilities occurring in these areas. 

Construction is conditioned upon obtaining a permit, on e of the key requirements for 

which is an obligation upon the regulated source to use the Best Available Control 

Technology (BACT). 

T o be reviewable for PSD, the source to be constructed first must be located in an area 

where the National Ambient Air Quality Standards (NAAQS) have not been exceeded 

for any of the criteria pollutants listed in section 107 of the CA A and which b designated 

as "attainment* or "unclassifiable." Second, the proposed construction project must be 

considered a "major stationary source" or "major emitting facility," defined in section 169 

of the CA A as any one of 28 types of sources with the potential to emit 100 tons per 

year (TPY) or more of any pollutant regulated by the CA A or any other type of source 

with the potential to emit regulated pollutants in amounts equal to or greater than 25 0 

TPY, or a "major modification," which includes any physical change in the racthod o f 

operation of a major stationary source which would result in a significant net emissions 

increase of any pollutant regulated by the CAA. 'Potential to emit" is the capability at 

maximum design capacity to emit a pollutant after the application o f air pollution control 

equipment and after taking into account all federally enforceable limitations restricting 

the hours o f operations or the type of amount of material combusted or processed. 

Ther e are three possible classifications for areas covered by PSD; Class I, Class U, and 

Class IU. Class I areas include national parks and wilderness areas, and are considered 

to be the areas where air quality is the highest Cass II includes all areas not designated -

as Class I o r as Class III. Class II areas may be redesignated as Class III areas by a State 

after an opportunity for public comment. Redesignation ta a Class III area allows for 
FEB - ,3-935 . WE D T:3 T DN R 

W 3 

more degradation of the air quality in that area. However, the allowance for dcgradauon 

of the air quality in Class I areas must remain constant, and PSD requires that each 

permit application analyze the passible effects of the proposed facility on Class I areas 

in the vidnity. 

Description of Source and Emissions 

ADM operates a corn starch processing plant located in Cedar Rapids, Linn County, 

Iowa. The plant is located in an attainment area for all criteria pollutants, including 

sulfur dioxide (SO,), lead, particulate matter (TSP), PM-10, nitrogen dioxide (NOx), 

carbon monoxide (CO), and ozone. The nearest PSD Class I area is over 250 miles from 

the plant. 

There exists a potential 72 J TPY increase in emissions of total suspended particulates 

(TSP). The majority of TSP emissions, which amounts to at least 60 TPY, is likely to be 

comprised of matter having a mean particle diameter of ten (10) microns or less (PM10). Additionally, there is a potential 483 TPY inaease in sulfur dioxide emissions; a 

potential 242 TPY increase in nitrogen oxides emissions; a potential 484 TPY inaease 

in carbon monoxide emissions; and a potential 3J TPY inaease in fluorides. The 

applicant has estimated that emissions of other pollutants regulated under PSD from this 

source will include VOC emissions of 8.8 TPY; lead emissions of 0.00007 TPY; beryllium 

emissions of 0.00014 TPY: and mercury emissions of 0.015 TPY given the coals currently 

expected to be used in the boiler. 

It ia believed that two of these contaminants, lead(Pb) and beryllium, may inaease 

dramatically as the coal supply changes. Therefore, it is necessary to establish emission 

limits to ensure the continuing minor modification status of this boiler with respect to 

PSD. These limits are set at 1/2 of the PSD significance level to provide maximum 

flexibility to ADM. 

Best Available Control Technology (BACT) 

Best Available Control Technology (BACT) is an emissions limit based on the maximum 

degree of pollution reduction which DNR determines is achievable on a case-by-case 

basis taking into account energy, environmental, economic and other costs. Any major 

stationary source or major modification that ii affected by the PSD regulations must 

conduct an analysis to ensure that BACT is specified for each significant pollutant. No 

technology may be approved which would violated the New Source Performance 

Standards (NSPS) found at 40 C.F.R. Part 60 or any applicable National Emission 

Standard for Hazardous Air Pollutants (NESHAPS) found at 40 CF.R. Part 61. 

Analysis of Application 

Once it is determined that a proposed project is subject to PSD review, the applicant 

nL««t: 

(1) demonstrate the Best Available Control Technology (BACT) for each PSD 

pcDutant emitted by a new or modified source; 

(2) perform an ambient air quality analysis to demonstrate that the inaease in 
P.8 

emissions due to the modification and associated growth will not exceed National 

Ambient Air Quality Standards (NAAQS) or applicable PSD inaemeats; 

(3) perform additional analysis to study the effects of inacascd emissions on 

soils, vegetation, and visibility; and 

(4) demonstrate that the source will not adversely impact a designated PSD Class 

I area. 

L Best Available Control Technology (BACT) 

Best Available Control Technology (BACT) is an emissions limit based oa the maximum 

degree of pollution reduction which DNR determines is achievable on a case-by-case 

basis taking into account energy, environmental, economic, and other costs. Any major 

stationaiy source or major modification that is affected by the PSD regulations must 

conduct an analysis to ensure that BACT is specified for each significant pollutant No 

technology may be approved which would violated the New Source Performance 

Sttndards (NSPS) found at 40 C.F.R. Part 60 or any applicable National Emission 

Standard for Hazardous Air Pollutants (NESHAPS) found at 40 CF.R. Part 61. 

a. Sulfur Dioxide BACT 

Sulfur dioxide emissions from fluidized bed boilers can be controlled by selection 

of the coal used, by selection of (he bed material to adjust the calcium to sulfur 

(Ca/5) ration in the combustion bed, and by use of flue gas desulfurlzation 

devices (scrubbers) which can also operate at various Ca/S ratios. DNR bas 

determined that BACT for SO, for this boiler is 0.08 pounds of SOj/mmBtu 

input, based oa management of Ca/S ratios of both the fluidized bed and lime 

spray drying (LSD) (dry scrubbing) while burning high sulfur coals. Selection of 

coal supplies would modify the type of control which would actually have to be 

used. (Further details of this determination may be found in the BACT review 

documentation attached.) 

b. Particulate BACT 

The only new particulate emission source will be stack emissions from the new 

steam generator itself. Emissions from coal handling, ash handling, and similar 

activities will increase, but no additions or modifications to these other systems 

were proposed. 

Current particulate control technologies which will reduce particulate emissions 

include fabric filter dust collectors (baghouses), electrostatic precipitators (ESPs), 

particulate scrubbers, and mechanical collectors. ADM has proposed a 

particulate limit based on the application ofa baghouse of 0.03 lbs/mmBtu input. 

This method of controlling particulate emissions is among the most successful 

control technologies and is acceptable to DNR as BACT. A baghouse, which is 

constructed of 2 fabric bag which acts as the filter media; a tubesheet to support 

the bags; a gas-tight enclosure; and a mechanism to dislodge the accumulated 

dust from the bags, can remove 99.9 percent or more of incoming particulate 

matter. The applicability of ESPs is generally restricted to removing particulate 

matter from gas streams in which the resistivity of particulate falls into a narrow 
P.9 

c .=> — •=»

 — '=', • 

margin. Further, efficiency of collection is affected by numerous factors, 

including residence time, gas temperature, moisture content, particle resistivity, 

flue gas chemistry, inlet loading, and particle-size distribution. The use of ESPs 

present a potential for re-entrainment and an affinity for an explosive 

environment. Finally, most ESPs operate in the 95-99 percent collection 

efficiency range. Particulate scrubbing requires a two-step process. Flnt, the 

particulate must be Vetted," increasing the effective mass of the material 

preparation for the next step. The second step is collection via inertia! 

impaction, interception or centripetal separation. The efficiency of collection ii 

a function of water flow, water quality, and the pressure drop throughout the 

scrubber. As water quality deteriorates, re-entrainment becomes a serious 

problem and particulate emissions can increase dramatically. Scrubbers require 

a large capital investment, have relatively high operating and maintenance costs, 

and relatively high energy consumption. Scrubbers are most often used to 

control reactive pollutants such as acid gases. There are three types of 

mechanical collectors. The most efficient is the multiclone, which consists of a 

framework and steel plates to which are welded many email cyclone collectors, 

each with a diameter between six and ten inches, depending oo the application. 

Although pressure drops vary, they are typically three to six inches water gage. 

The second is the cyclone, which is a large diameter centripetal collection device. 

Cyclones have relatively low pressure drops and lower efficiencies than a 

multiclone. The third type of mechanical collector is a settling chamber. In a 

settling chamber, a region of low velocity is created and provides for gravitational 

settling of the particulate. Settling chambers have low collection efficiencies 

unless the materials is relatively 'heavy." The collection efficiencies of 

mechanical scrubbers range from 50 to 90 percent depending on particle size and 

how well the material agglomerates. Cyclones have low collection efficiencies 

particularly of PM-10. They also experience erosion of the tubes, which are 

often plugged with dust during periods of high grain loading. 

DNR has determined tbat BACT for particulate for this boiler is 0.03 

Ibs/mmBTU based on the use of a baghouse. 

c Nitrogen Oxide BACT 

Fluidized bed boilen tend to emit less NOx than other boilers because of the 

lower and more even temperatures at which they operate. The existing NOx 

emissions can be controlled by management of over-fire air and by Selective 

Non-Catalytic Reduction (SNCR). Selective Catalytic Reduction (SCR) is not 

considered feasible in this case because of the potential for deactivation of the 

catalyst through contact with coal contaminants and bed material. DNR has 

determined that BACT for NOx for this boiler is 0.07 pounds of NOx/mmBtu 

input, based on management of over-fire air and SNCR. (Further details of this 

determination may be found in the BACT review documentation attached.) 

d. Carbon Monoxide BACT 

Two method* are available for controlling CO emissions. They are (1) 

combustion optimization, and (2) catalytic oxidation. As with SCR for NOx, 
P.10_ 

r ^ aw - *-> - =» 

—». -w .ynn . 

catalyst beds present potential operational problems. Therefore, DNR has 

determined that ADM'i proposal of 0.20 lbs/mm Btu input Is BACT for CO. 

ev Fluoride BACT 

Fluorides may be emitted through coal combustion at levels exceeding 3 TPY 

and, therefore, may be subject to BACT determination. It is believed that 

fluoride* released in the combustion chamber will react with calcium to form 

Cap, t solid material. A baghouse is BACT for control of solid particles, and 

control beyond this does not appear necessary. Therefore, a baghouse is 

accepted as BACT for control of fluoride emissions. 

Note retarding Toxic Pollutants: Based on the 1990 amendments to 1he CAA. the 

consi'derijfoq of toxic pollutants is no longer considered as part of PSD analysis. 

Z PSD Ambient Air Quality Analysis 

Applicants for a PSD permit must supply at least one year's worth of ambient air 

monitoring data for those contaminants for which there would be a significant increase 

in emissions. However, DNR may accept the results of monitoring conducted at existing 

sites, provided it meets the criteria stated in the EPA publication titled Ambicqt 

Monitoring Guidelines for Prevention of Significant Deierioratjon. An extensive 

monitoring program administered by DNR and Linn County is in place in Cedar Rapids. 

Based on Information submitted by ADM, DNR has determined that the existing Linn 

County monitoring is acceptable. 

For a PSD permit application lo be approved, the applicant must demonstrate that the 

proposed project will not result in a violation of either: 

a PSD Inaement or 

a National Ambient Air Quality Standard (NAAQS). 

a PSD Increment 

The PSD increment is the maximum increase in ambient concentrations of 

specific pollutants which ii allowed from all significant sources in a particular 

area In this case, the PSD inaement includes all sources emitting SO, and TSP 

which have been permitted since August 7,1977, and all sources emitting NOx 

which have been permitted since February 8,1988. There Is no PSD increment 

for CO, NMHC or PM-10. The PSD increments allowed for the affected 

pollutants are as follows.-

Anmu.!. 

?4-houn 

?-noui. 

TSP 

19ug/m3 

37 pg/m3 

20ug/m3 

91 ug/ra3 

512ug/in3 

25ugta3 

Cedar Rapids was designated as a TSP non-attainment area until 1988. Only "a 
P.11 

few sources other than those herein permitted fall within the former nonattainment area and will consume increment. They belong to the applicant, to 

Penford Corporation (recently permitted expansion), and to the University of 

Iowa (Boiler #11). Outside the former non-attainment area, increment 

consumption will be lower than within because total ADM concentration for the -

four boilen is lea that two micrograms per cubic meter and Penfbrd's 

contribution is less that 10 micrograms per cubic meter. The increment 

consumption for particulate within the former non-attainment area was modeled 

at 33 ug/m3 annually and 312 ug/m3 for a 24-hour period. The inaement 

consumption for particulate outside the former non-attainment area is 

significantly less than this amount and is near 10 ug/m3 for the 24-hour average. 

The increment consumption for sulfur dioxide was modeled by the applicant at 

1.93 ug/m3 annually, 32L5 ug/m3 for a 24-hour period, and 107.4 ug/ra3 for a 3-

hour period. The inaement consumption for nitrogen oxide was modeled at less 

that 0.1 ug/m3 annually. 

b. National Ambient Air Quality Standards (NAAQS) 

A proposed source is determined to contribute to a violation of NAAQS if it is 

expected to inaease the ambient concentrations a significant amount at the 

location of a violation of an ambient standard. Any contribution to a violation 

is considered significant if k exceeds any of the following; 

Pollutant 

Houi 

SO: 

TSP 

PM-10 

NOx 

CO 

2000ug/ra3 

Annual 

1.0ug/m3 

1.0 ug/m3 

1.0ug/m3 

1.0 ug/m3 

-

24 Hours 

• 

5 ug/m3 

5 ug/m3 

5ug/m3 

' -

-

8 Houn 

*» 

-

-

-

500ug/m3 

? Houn 

25 ug/ml 

-

-

•* 

«• 

In this case, PSD permit limits apply to all tbe listed contaminants because each 

of them would be emitted in significantly greater amounts by ADM's proposed 

project. Regarding PM-10. computer modeling of air dispersion patterns 

indicated that the national ambient air quality standards for PM-10 would be 

exceeded at several receptor locations. However, a detailed review of predicted 

impacts at these recepton by emissions increases directly from and associated 

with the boiler was conducted and in no case was the annual or 24-hour average 

in excess of the significance levels presented above. In fact, maximum impacts 

at all locations were determined to be insignificant Since the proposed project 

would not significantly contribute to predicted nonattainment for PM-10, the 

requirements of the PSD regulations have been met with regard to PM-10. 

Concentrations of total suspended particulates, nitrogen dioxide, and carbon 

monoxide are below the significance levels designated for each of those 

pollutants. It a unlikely that a violations of the NAAQS will occur for any of 
P.12 

- _ .J ui fc_ u r':'+^>J- , M K 

those pollutants as a result of the proposed project. 

Tbe apph'cant identified three areas of non-attainment for sulfur dioxide, based 

on computer modeling performed by the applicant. One of these areas is located 

at Iowa Electric's Sixth Street station, and the other two are located at Iowa 

Electric's Prairie Creek Station. DetaDed modeling of the impact values from 

the proposed project was conduaed using a fine grid. Based on this modeling, 

contributions were shown to be below the significance levels at the points where 

nonattainment was found in one of the areas and throughout the second and 

third areas. (It appean, therefore, that compliance with the PSD regulations will 

be had with regard to sulfur dioxide.) However, there are significant concerns 

regarding this modeling. DNR has set in this permit a 3-hour limit and a 30-day 

limit which, when combined, are adequate to prevent significant contribution by 

this bofla to the non-attainment areas existing in Cedar Rapids. 

DNR has not found the potential for unsafe levels of any other potential 

contaminant. Therefore, no further special ambient impact assessment has been 

conducted. 

3. Effects on Vegetation, Soils, and Visibility 

• 

a. Vegetation and Soils 

t 

Land surrounding the proposed facility is used mostly for crop production. The 

proposed modification will have an insignificant impact on area vegetation and 

soils. Although some types of vegetation may be damaged by high concentrations 

of particulates which are equivalent to the application of 50 - 380 miaograms per 

square centimeter per day, concentrations of particulates were modeled at 5 

ug/m3 per 24-hour period. These concentrations arc not significant. 

Regarding sulfur dioxide, both chronic and acute damage has been observed, 

depending on the concentration and length of exposure. EPA studies show 

chronic damage to corn, beans, and barley with levels of 400-800 ug/m3 

continuously for seven days. Most chronic damage to native Iowa foliage will 

occur in the range of 800-1500 ug/m3 for a period of a few days. Damage may 

occur over a long period if values are consistently in the 300-500 ug/m3 range. 

Modeled peak concentrations for the proposed project are below the levels at 

which damage would oaur - 9 ug/m3 for a 24-hour average and 0.4 ug/m3 for 

an annual average. 

Chronic injury may occur from nitrogen dioxide concentrations greater than 470 

ug/m3 on a long-term basis. Vegetation or soil damage fire unlikely at the 

modeled peak concentration of less than 0.1 ug/m3. 

Carbon monoxide levels below approximately 0.1 ug/m3 are bel'eved not to cause 

damage to vegetation and soils. Modeled levels for this project are less than 1 

ug/m3. 

b. Visibility Requirements 
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In order to preserve the attractiveness of wilderness areas and parldandj, the 

PSD program places special limits on facilities which may contribute to 

atmospheric haze. There are three contaminants primarily responsible for 

contributing to haze. These are particulates. SO„ and NOx, 

The proposed modifications are a significant source of all three of these 

pollutants. Calculations show visibility impairment it twenty (20) kilomcten to 

be acceptable according to EPA guidelines. It is unlikely that the proposed 

construction will impact visibility in the nearest Class I area, which is over 250 

miles from the plant 

4. Wilderness and Parkland Protection 

The PSD program provides Class I protection for national parte and wilderness areas. 

The nearest area receiving this special protection is the Hercules Glades Wilderness in 

southern Missouri, which is over 250 miles from the plant. The radius of potential 

significant impact for sulfur dioxide emissions from the proposed project in 4.1 

kllometen or less than 3 miles. The proposed modification will not significantly impact 

this wilderness area. 

Preliminary DeterminationBased on information in the administrative record, DNR proposes to approve the permit 

applications subject to the conditions outlined in the attached draft permit 

Any owner or operator of a source or modification that is subject to PSD regulations 

shall not commence construction without first receiving approval from the agency 

designated to implement the PSD program. Any owner or operator who constructs, 

modifies, relocates or operates an affected source not in accordance with the PSD permit 

conditions shall be subject to federal enforcement action under sections 113 and 167 of 

the CAA. The PSD regulations also provide that issuance ofa permit shall not relieve 

the source of the obligation to comply with all applicable State Implementation Plan 

(SIP) federal air pollution standards. 

Reopening tbe Public Comment Period 

If information or arguments submitted to DNR during the public comment period appear 

to raise substantial new questions concerning the draft permit, then DNR may prepare 

a revised draft permit, a revised fact sheet or may reopen or extend the public comment 

period. Comments filed during the public comment period may address only the 

substantial new questions which caused the public comment period to be reopened. 

Public notice of any reopening or extension of the public comment period shall be issued 

by the central of DNR. 
P.14 

, — o — •=» • *•;_ . JUIN K 

K - a fcb 

January 28, 1993 ADM Cedar Rapids JBotier #4 PSD Review 

S02 BACT Analysis 

ADM Cedar Rapids Boiler #4 

Control Technology 

Feasibility 

The Radian report dismisses western coal as a fuel sourci for BACT. This limits their analysis to 

midwestern coal only as a BACT fuel source. The report then identifies two types of coatroJ 

technologies applied in the United States for controlling S02 emissions from coal-fired boilers:. 

atmospheric fluidized bed combustion (AFBC) and flue gas desulfurlzation (FGD). 

Radian notes: 

"Recently, LSD systems have also become popular for utility boilers, industrial cogeneration 

boilers, and Incinerator systems due to their higb removal efficiencies (> 90 percent), lower costs 

and ease of operation compared to wet FGD systems." 

"However, LSD FGD has never been applied to an AFBC unit. Addition of FGD generally 

makes AFBC boilers economically noncompetitive with conventional boilers using FGD. 

Therefore, performance achievable for this application bas not been demonstrated "(page 3-7). 

Existing facilities 

The Radian report summarizes fluiUiztxl bed boiler permits issued since 1989. This summary does nut 

document LAER permits. The summary identifies twelve BACT determinations for coal-fired AFBC 

boilers requiring $02 emission limits ranging from 0.15-6 Ib/MMBtu to 1.0 Ib/MMBtu. This confirms 

Out Iimeitone-inje^ion based limits as low u 0.16 Ib/MMBtu have been established. The summary does 

nut identify CaO levels, coal restrictions or other restrictions except to point out two midwestern plants 

which they imply are permitted to use 6.0 and 5.4 Ib S02/MMBcu coals (page 3.2). They have found 

no combined application of FOD on an AFBC boiler. 

The summary of twelve BACT decisions since 1989 did not include LAER decisions. It is evident from 

this data that S02 emission limits as low as 0.15 <C/mmBtu have been established. 

Fuel Selection 

The Radian report notes that the ADM boiler would have to obtain 90% reduction to be able to meet 

their proposed limit using their worse case coal (page 3-2). This means that they are planning to use 

up to 7.81b 502/MMBtu coal. Radian also refers to low-sulfur coals as not 'economically available' 

for midwestern boilers. They then reject western coal as a potential fuel source for the ADM boiler. 

However, western coal currently i? 'economically available" to ADM's three existing boilers at this 

facility. The Radian report states that ADM is currently achieving about 91 % S02 removal to less than 

0.4 Ib/MMBtu with a blend of Midwestern coal and low-s\ilfur Western coal, without add-on controls. 
P.15 

January 28. 1993 ADM Cedar Rapids Boiler #4 PSD Review 

Economics 

i 

Radian presents their BACT S02 Control Hierarchy with four non-aggressive options. They evaluate 

the Energy, Environmental and Economic impacu, with the Economic impacts the significant reason to 

reject udd-on controls or other coal options. Their economic analysis is supponed by sketchy cost 

figures tu show the "unreasonable" expense to attain stricter S02 emissions control. 

Ammonia-induced Cost Increases 

In discussing NOx controls in their initial submittal, Radian notes unreached ammonia in the cyclone 

could react with residual sulfur trioxides (S03) in the exhaust stream to produce ammonium salts which 

cuuld foul the air heater and baghouse. If this were to occur, Radian and ADM believe this could 

force boiler maintenance which could reduce boiler availability between 1 and 10 percent as well as 

increase visible emissions. 

In their initial submittal, Radian notes this reaction would be of concern mainly when both the ammonia 

and S03 levels are 5 percent or greater. This is relevant because Radian projects the S03 levels at 

between I and 6 ppm based on S02 levels of the current operation at .£..0.35-040 Ib/MMBtu (pages 1-

15 through 1-18). 

In discussing NOx controls in their supplemental submittal, Radian expands on their concerns about 

ammonium salt production. This effect was noted in the discussion of the feasibility of Selective NonCatalytic Reduction (SNCR) NOx controls added to a boiler configured like the existing boilers. 

Another view is that this could be an added cost of higher sulfur oxide emissions from the fluidized 

bed given the presence of ammonia reaction NOx controls. From this viewpoint. S02 control strategies 

which result in S03 levels greater than 83% of the current maximum S03 level would carry an 

additional economic burden from the resulting air beater and baghouse fouling. 

Baseline emissions 

The Radian report and response to IDNR comments uses NSPS of 909S S02 removal as baseline (0.78 

Ib.'MMBni). Radian states (page 3-12) "because this emission rate is also NSPS for the boiler, it is the 

baseline emission level for estimating impacts." 

In their supplemental submittal, Radian notes: 

"NSPS was selected as baseline because AFBC S02 control using limestone injection is 

an integral part of the combustion process and boiler design and operation. Other types 

of coal-fired boilers (pulverized coal, cyclone, stoker) use add-on controls for the control 

of S02. AFBC boilers are designed to have some type of bed material (sand, ash, or 

limestone) for operation. The oed material stabilizes and catalyzes the combustion 

process allowing the boiler to combust coal at lower temperatures. Limestone is used 

as the bed material If S02 control is desired over the amount of S02 that will be 

retained by the coal ash." 

"Because the bed material is an integral pan of the combustion process, boiler 4 

operation using limestone as the bed material was selected as the baseline. NSPS level 

of control using limestone as the bed material was selected as the baseline S02 emission 

level because all large coal-fired boilers must meet this level of control" [supplemental 

response #31]. 

3 
P.16 

FEB - 3-S> 3 v : D M R p . 1 •<* 

January 28. 1993 ADM Cedar Rapids Boiler #4 PSD Review 

impacting metal and refractory U a maintenance problem. If the solids inventory is increased, this will 

shorten the time that the boiler can operate continuously. , • * Ul 

There may be maintenance problems with higher Ca/S ratios in the bed, such as 4.0 or greater 

however, this is theoretical only. INDR commenr #41 asks Radian to document the maintenance 

problems expected with a high solids inventory (high Ca/S ratio) and to provide the economic cose of 

such maintenance problems. Tbe response to this comment is the impact to cost effectiveness is 

"insignificant". 

Attachment 9 of Radian's supplemental report shows, for 95% S02 removal and 1% downtime to the 

boiler (91% boiler usage), the cost per ton of S02 removal is S4.5. At 10% downtime to the boiler, 

or 82% boiler usage, the cost per ton is S44.7. The annualized maintenance costs for 1% and 10% 

duwntime are shown as 573,000 and 5655,000 respectively. How these maintenance costs were derived 

>s not shuwn, 

According to information from a boiler manufacturer as presented in the Stanley report, the following 

gives expected performance data for the proposed FBC boiler ADM project: 

Cfl/S RiU'Q 

2.0 

2.5 

3.0 

4.0 

S02 Removal Efficiency 

85% 

' 87% 

,90% 

'92% 

Lime Spray Drying (LSD) Scrubber Efficiencies 

When asked in IDNR comment #42 to document performance problems associated with dry scrubbing 

Radian cites the 'unreasonably high cost effectiveness over baseline." Their response then goes on to 

say that performance problems referenced are related to the expected abrasive effects of reusing the 

sorbents in the AFBC waste to make up the LSD slurry. In their own words, "This is a theoretical 

cuncept only...." Vendor information presented by Radian in Attachment 8 says that by reusing 

limestone in the spray dryer, the limestone requirements of the combined system would be reduced by 

10-20%, thus the scrubber could result in a savings in costs due to decreased limestone usage. No 

performance problems are mentioned. 

Spray dryer manufacturers have also developed data for their equipment, again from the Stanley report: 

Ca/S Ratio 

1.0 

1.5 

2.0 

2.5 

SQ? Rcrpo-yal Efficiency 

60% 

70% 

89% 

92% 

The vendor quote included in Radian's supplemental Attachment 8 notes with recycled limestone (from 

the bed material) used In tht spray dryer, efficiencies of 50-60% could be expected. With lime used 

in the Ca/S jatio, the efficiencies can be as high as 90%, as the Stanley report indicated. There is also 

a large discrepancy between the Radian report and the Stanley report in terms of limestone injection 

custs. 

Radian concludes that lime spray drying (LSD) as well as coal blending are both too expensive based 
P.17 

January 28, 1993 ADM Cedar Rapids Boiler #4 PSD Review 

-There wouJd be no need for an additional coal handling facility since all boilers would 

be using the same coal at the same time. According to the Radian report the total 

capital investment for a new coal-handling facility is S 10,693,000. 

-No additional control would be needed at this time which would eliminate an estimated 

$2,500,000 capital expenditure for a scrubber and also eliminate the continuous operating 

and maintenance costs associated with the scrubber. 

-It Is anticipated the current coal price differential favoring Western coal over Iowa 

coal will remain the same through 1996. In 1996, Phase I of the Acid Rain Provisions 

will become effective which may eliminate the current price differential. A reasonable 

scenario then would be a gradually increasing coal price differential favoring Iowa coal 

until die year 2000, when Phase II of the Acid Rain Provisions would become effective. 

2. Convening the three existing boilers to the same 42:58 blending program as boiler #4 ' 

would allow ADM to defer the capital investment until the annual cost of western coal 

costs as much as the annualized costs of the duplicate coal handling facility. This annual 

savings of J 1,193,147 could be applied to the purchase of 349,353 tons of western coal 

needed for the three existing boilers. Under these circumstances the duplicative coal 

handling facility would not be justified until the western coals became at least 

(51,193,147/349,353 tonj « $3.42/ton more expensive than midwestern coals. 

(It must be noted that there would be operational savings each year until the price differential 

reaches this level from the current ~$3/ton savings in the use of western coals). 

In the future between 1996 und 2000 when iris anticipated that Midwestern coal would be 

substantially cheaper than Western coal then a blend (42% Midwestern, 58% Western) of Iowa 

cuai and Western coal for all four boilers with a scrubber for boiler #4 could be utilized tu 

achieve an emission rate of 0.08 Ib/MMBTU for boiler #4. The other three existing boilers 

would achieve an emission rate of 0.35 Ib/MMBTU on the same blended coal; which is well 

within the existing permit limits. 

-This would require a capital expenditure for coal mixing equipment for the existing coal 

handling facility. A capital expenditure would not be required for a separate coal 

handling facility since all four boilers would still be using the same coat blend. 

-This would require a scrubber to be added to boiler #4 which would cost $2,500,000 

initially plus operating and maintenance costs. 

-Savings from burning Western coal from 1992 to somewhere between 1996 und 2000 

would be used to offset or possibly pay for the total cost of the capital expenditures. 

3. Sometime after the year 2000 when it is anticipated that Midwestern coal would be 

much cheaper than Western coal, then a switch to burning all Midwestern coal could be 

made. A bed Ca/S ratio of 3.0 and a scrubber Ca/S ratio of 2.5 would achieve an 

emission rate of 0.08 lb/MMBTU for boiler #4. The three existing boilers could be 

operated at a Ca/S bed ratio of 4.0 and achieve an emission rate of 0.62 lb/MMBTU 

which would meet the existing three boilers' permit conditions. 

-This type of strategy allows the company the maximum amount of flexibility in using 

boiler bed Ca.'S ratios, coal sources, coal handling and blending systems, add-on controls 

and capital expenditures to achieve a BACT S02 of 0.08 Ib/MMBtu for boiler #4. At 
P.18 

FfcaaW- ,3-9 3 I E E T : 5 5 DN R 1 8 

January 28, 1993 ADM Cedar Rapids Boiler H PSD Review 

Even so, these costs Bre so low as to suggest mofe aggressive control technologies should have been 

explored and that the current BACT proposal is flawed. Other more aggressive options inlcude: 

combining dry scrubbing with coal blending or Western coal, additional add-on S02 controls, more 

aggressive CaO ratios than used in this analysis, etc. This table demonstrates concerns about cusi 

increases in western COal as well as capital costs of coal handling and dry scrubbing are simply not 

relevant. 

Western coal price differential 

The cost to obtain Western coal has been inflated by a "price differential" of S5.00 to $22.50/tun, due 

the assumed difficulty of obtaining Western coal in the iiirure due to provisions of Title IV of the 

CAAA, acid rain. Tnis assumption is purely speculation, and it is currently around $3.00/ton cheaper 

for ADM to obtain Western coal over Midwestern coal. Radian acknowledges this in their November 

comments. 

Revised cost estimates 

in response to IDNR comments, Radian examines an option of AFBC with LSD (dry scrubber) and 

100% Western coal. However, the analysis of these options by Radian and subsequent cost calculations 

is built upon the incorrect baseline of 0.78 Ib/MMBtu. Therefore, the cost per ton of removal will be 

grossly Inflated, since the denominator is 0.78 instead of 7.8. 

i 

The stricter control options Radian examines are: AFBC. at 92% control (4.0 Ca/S ratio in the bed), 

AFBC + LSD <® 95% control, AFBC + LSD @ 99% control, and 100% Western coal. 

The costs presented for these control options are over-inflated due to the incorrect baseline used. If 

these numbers were adjusted to reflect a 7.8 Ib/MMBtu baseline, as was done in the Stanley report, they 

would show much lower numbers of total cost/ton and incremental S/ton. The Radian numbers also 

include higher costs for other factors than were included in the Stanley report. 

The Radian report shows an increased cost of limestone and limestone waste disposal by approximately 

$ 1.000.000 over the Stanley report. The Stanley report reflects an accurate baseline of 7.8 Ib/MMBtu. 

It also examines much tighter control options, as low as 0.07 Ib/MMBtu S02 removal. 

A comparison of costs for the Radian and Stanley reports shows: 

Table 2 

CVnw' Qp.'V" Stanley Report 

AFBC® 90% SI.621.996 

AFBC® 92% $1,994,342 

(4.0 bed ratio) 

AFBC + LSD ® 95% $2,359,826 

AFBC + LSD $ 99% $2,590,696 (98.5% control) 

100% Western coal $ 267,066 

Radian Renon 

$1,659,069 

$3,074,258 

53,575.127 

S4,076,427 

$4,149,536 (coal $5/ton) 

$8,559,694 (coal $22.50/ton) 

Cost Difference 

$ 37.073 

$1,079,916 

Sl.215.301 

$1,455,731 

$3,882,470 

$8,292,671 
P.19 

January 8, 1993 ADM Cedar Rapids Boiler #4 PSD Review 

The grarjh reveals that Western coal with a Ca/S ratio of 3.0 and 90% overall S02 removal gives one 

of the highest emissions reductions for the least cost. This is truo for Western coal With $0 price 

differential over Midwestern coal, and for Western coal with a $5 price differential over Midwestern 

coal. Higher price differentials were not evaluated for short-term analysis. 

Figure 2 

3300 

*wo3200-

J200-

3100-

1000 

2200-

aaceJ70O2MO3500-

Approximate Annual Cost Limit 

ADM Cedar Rapids Boiler #4 

Annualized Cost of Control per ton S02 removed 

versus 

Resulting Emissions of Sulfur Dioxide (S02) 

*.*/!** 

I I I I I I I I IT ' I I I I l I J I I ' I I ' ' • ' rnrrni l I I • • • • I < • • i • • • ••' . 

1000 2000 3000 4000 5000 «000 

Resulting Emissions (tons/year) 

n 

J 
P.20 

January 28, 1993 ADM Cedar Rapids Boiler #4 PSD Review 

Environment 

Radian identifies only one environmental issue, the generation of solid wastes from 502 emission 

control alternatives. They state that operating the AFBC boiler to achieve 92% reduction (4.0 Ca/S 

ratio) would increase solid waste generation by 64,500 tons/year. There is no calculation shown for this 

number. 

Radian claims the AFBC plus LSD FGD option would reduce solid waste generation by 20,900 

tuns/year. The reduction in solid waste by using an LSD FGD system should be considered an 

environmental advantage. 

Radian states: 

"The primary environmental impact of the S02 emission control alternatives will be from the 

generation of solid wastes. Operating the CFB boiler to achieve 92 percent reduction will 

increase solid waste generation by approximately 64,500 tons/yr. The AFBC plus LSD FGD 

option would reduce solid waste generation by about 20.900 tons/yr/ (page 3-16) 

Regarding coal blending, Radian states: 

"Because western coal contains less sulfur, limestone usage and, therefore solid waste 

generation rates will be lower that for midwestern coal-firing. These savings are 

included in the analysis" (page 3-18). 

Unfortunately, the cost analysis presentation is too sketchy to confirm this. The lack of listing waste 

disposal costs is inconsistent with other sections of the Radian repon. For example, In the NOx BACT 

analysis Radian manages to itemize waste disposal costs, in that case to show a.cost disadvantage tor 

the control optioo of ammonia injection. An itemization of waste disposal costs to show an economic 

c.i.\t advantage for the western coal or blended coal BACT options is never shown. 

13 
P.21 

January 28, 1993 ADM Cedar Rapids Boiler #4 PSD Review 

Radian's proposal of 0.78 Ib/MMBtu as BACT is not a top-down BACT selection and is rejected. 

The emission level chosen as BACT is 0.08 lb/MMBtu for S02. This was done by evaluating 

control options in the Stanley and Radian reports and looking at stricter options than either report 

showed, in order to accomplish a "top-downn BACT analysis. This is shown on Figure 2. 

The selected BACT of 0.08 Ib/MMBru represents nearly the NSPS limit for Western coal (NSPS is 0.81 

Ib/MMBtu). This selection can be arrived at by various options, although die most cost-effeaive options 

include a scrubber on Midwestern coal or Western coal at a 3.0 Ca/S bed ratio.. 

A BACT emission rate of 0.08 lb/MMBtu was chosen based on considerations of top-down analysis and 

-ust-effectiveness. Tbls can be achieved with limestone injection ratios in the bed of less than 4.0, if 

this is a concern. This limit can also be achieved with Midwestern coal or a blend of Midwestern and 

western coals, although with Midwestern coal higher Ca/S ratios in the bed and a scrubber is required. 

Western coal is not a permit requirement, since there are other means of achieving 0.08 lb/MMBtu 

cmhsiion rate for S02. However, the Western coal options reflea ths greatest emission reductions at 

the least cost. 

15 
P.22 

TERRY E. BRANSTAO. (JOVIANO* 

January 28, 1993' DRAFT 

DEPARTMENT OF [NATURAL RESOURCES 

LARRY J . WILSON. omecTC. 

CERTIFIED 

1

 Mr. Mark E. Calmes, Director ' 

Corporate Loss Pravention 

Archer Daniels Midland Company 

Box 1470 

Decatur! Illinois 62525 

Dear Mr. Calmes: 

• Subject: IDNR Project No. 90-222, Plant Number 57-01-080 

This lercar transmits the following permit for the air contaminant source end related oontrol 

equipment described in your permit application of November 2, 1990, and subsequent 

submittal of October 14, 1992. 

Source No. Description 

Unit #4 CFBC Boiler 

DNR Permit U 

93-A-XXX Issued 

Permit Type 

PSD 

Your attention is directed to-the Standard and Special Conditions attached to these permits. 

Pursuant to Departmental directive of September 10, 1991 no review was performed 

regarding the toxic emissions from these sources, if any. This permit does not constitute 

acceptance (or lack thereof) of the modeling demonstration provided with the permit 

application nor approval (or lack thereof) of the toxic emissions documented in the submittal. 

Sincerely, 

cc: IPNR FO #5 

Mr. Petei Hamlin, Chief, Air Quality Bureau 

EPA, Region VII 

WAUJ.CS STATE OFFICE BUILDING / OES MClNES. IOWA 5C3.9 / 515-231-5145/ 7D0 315-242-SS67 / FAX; 15-261 -8355 
Archer Daniels Midland Company Boiler Number Four . * 

January 28, 1993 PSD Permit Number 93-A-xxx 

PERMIT CONDITIONS 

The owner or operator cf the facility shall assure that the installation and operation of this 

facility is in compliance with all conditions listed herein. 

1. Departmental Review 

This permit is issued based on information submitted by the applicant in the application 

form, its attachments, and any additional submittal. Any misinformation, false statements 

or misrepresentations by the applicant shall cause this permit to be void. 

The proposed equipment has been evaluated for conformance with Iowa Code Chapter 

455B; 567 Iowa Administrative Code Chapters 20-29; and 40 C.F.R. Part 52, and has the 

potential to comply. 

No review has been undertaken on the engineering aspects of the equipment or control 

equipment other than the potential of that equipment for reducing air contaminant emissions. 

This Department assumes no liability, directly or indirectly, for any loss due to damage to 

persons or property caused by, resulting from, or arising out of the design, installation, 

maintenance or operation of the proposed equipment. 

2. Initiation of Construction 

This permit shall become void if a continuous program of construction has not been initiated 

within 120 Ions hundred and twenty) days aiter the date of issuance of this permit: or if 

construction is discontinued for a period of 12 Itwelve) months or longer; or if construction 

is not completed within a reasonable period of time. 

The owner or operator bears responsibility to ensure, that construction conforms to that 

shewn on the plans anci specifications and that adequate operation and maintenance is 

provided to ensure that no condition of air pollution is created. Any changes made in the 

final plans and specifications for the proposed equipment or control equipment shall require 

a supplemental permit. 

3. Permit Not Transferable 

This permit is not transferable from one piece of equipment to another. Further, this permit 

is not transferable from one location to another. 

It any of the existing boilers are replaced by the owner/operator for any reason, the 

owner/operator must obtain approval from the IDNR central office before beginning 

construction the replacement unit. Approval may be conditioned on additional requirements 

to this permit. 

4. Permittee Responsibility 

Issuance of this permit shall not relieve the owner or operator of the responsibility to comply 

fully witli applicable provisions of the state implementation plan (SIP) and with the provisions 

of applicable local, state, and federal laws, regulations, ordinances, and other reauiremants 

applying to this installation. 
P.24 

- Archer Daniels Midland Company Boiier Number Four 4 

January 28, 1993 PSD Permit Number 93-A-xxx 

8. Source Characteristics 

Tnis permit is for the construction and operation of a Tampella Keelar 477,000 pph steam 

circulating fluidized bed combustion (CFBC) boiler to be operated at no more than 551.5 

million BTUs per hour (MMBtu/hr) and ducted to the stack detailed below. 

Heiaht Diameter Temoerature Flue Gas Flow 

350 feet 3.45 meters " 320 F 200,891 ACFM 

UTM Location 

4,642,020.0 meters Northerly and 608.775.0 meters Easterly 

9. Limitations on Other Sources. 

A. Emissions Limits 

Effective on and after the date the 30-day S02 compliance demonstration is completed, 

emissions from the existing dryers (units #2, #4 and #5) shall not exceed the following: 

Source Pollutant Emission Limit Averaqinq Period 

Existing Units 

#3.#4 and *5 

combined S02 150 lb/hour -• 3-hour 

B. Fuel Usage 

On and after the startup.date of the proposed boiler, the owner/operator of the plant shal 

not combust a fuel other than natural gas in the existing dryers (Units nZ.ffA. and #5). 

10. Initial Compliance Demonstrations 

The owner/operate shall verify initial compliance with the emission limitations contained in 

Section #6 and submit a written report of the results within 60 days of achieving maximum 

production and no later than 180 days after the startup date of the proposed bojler. 

The owner/operator shall submit a written report to the DNR central office of each initial 

compliance demonstration attempt, whether successful or not, postmarked not later than 

30 days after the completion of the test period or the termination of the attempt, 

whichever occurs first. 

A. Long Term Emission Limits 

1. 30-Day Rolling NOx and S02 Emission Rate Compliance 

The initial performance tests using Continuous Emission Monitors (CEMS) shall be 

conducted over the first 30 consecutive boiler operating days. The first day of these 

tests shall be completed within 30 days after achieving maximum production rate but 

no later than 180 day after initial startup of the facility. 

For the initial 30-day rolling average compliance test, NOx and S02 from the boiler shal 

be monitored for 30 consecutive boiler operating days. The 30-day average emission limn 
P.25 

Archer Daniels Midland Company Boiler Number Four ' 6 

January 28, 1993 PSD Permit Number 93-A-xxx 

D. Pretest Meeting 

A pretest meeting shall be held at a mutually agreeable site no later than thirty (30) days 

prior to the date of each compliance test or the date of each CEMS performance evaluation, 

whichever occurs first if performed at different times. Each meeting shall be attended by 

representatives of the DNR central office, the owner and the compliance testing firm, if 

used. Representatives of the Linn County Health Department shall be invited to attend each 

pretest masting and each compliance demonstration. 

It shall be the responsibility of the ow.ner to coordinate and schedule each meeting, and to 

formally notify all participants of each pretest meeting date, compliance test date, and CEM 

performance evaluation date. --

Upon being notified, the DNR will send to the owner a "proposed test plan" questionnaire. 

The questionnaire shall be completed by the owner and submitted to the DNR as directed. 

The completed questionnaire must be received by the DNR no later than fifteen (15) working 

days prior to the pretest meeting date. 

E. Additional Notices 

The Department reserves the right to impose additional, different, or more detailed testing 

requirements as the need arises. It is the responsibility of the owner/operator to locate 

the test ports to be used during compliance testing. 

11. Operating Condition Monitoring: 

» 

The owner shall maintain a record of periods "of startup, shutdown or malfunction; the 

type, quality, and quantity of fuel combusted in existing boilers #2, #3, #4 and the 

proposed unit #4; and any other information necessary to verify compliance with the 

conditions of this permit. 

12. Continuous Emission Monitoring 

A. S02 and NOx 

The owner shall continuously demonstrate compliance with the S02 and NOx emission 

limitations, opacity, and S02 percent reduction requirements of this permit through the 

use of continuous emission monitoring systems (CEMS) and a fuel sampling and analysis 

(FSA) system. These systems shall be installed, operating and calibrated prior to 

beginning the initial compliance demonstration set forth in Condition #10 according to 40 

CFR 60.13. 

ir. the case where the CEM is to be used as the test method for demonstrating 

compliance, the performance certification report shall be submitted to the agency prior to 

initiating the facility compliance testing. 

Verification of compliance with the emission limit shall be made by the owner/operator at 

the end of each boiler operating hour, using the data collected by the Continuous 

Emis.sion Monitoring System (CEMS). 

The three-hour average is calculated as the arithmetic average of all valid hourly data 

collected during the previous three boiler operating hours. 

Compliance with the S02 and NOx emission rate limitations and the S02 percent 

reduction requirements shall be calculated as the average of all valid hourly emission rate 

data and valid hourly S02 percent reduction data for the 30 previous boiler operating 

aays during which each standard applies. The owner/operator shall calculate a new 

30-day average at the end of each boiler operating day. 
Archer'Daniels Midland Company Boiler Number Four 

'January 28. 1993 PSD Permit Number 93-A-xxx 

Equivalent S02 inlet 

rate of individual 

bunker 

%S 

----- K, 

GHV 

where K = 20.000(lb#BTU)/(% 'IVIMBTU) 

If the equivalent inlet S02 rates for coal contained in each day bunker which feeds to a 

single boiler differ by 0.2 lbs S02/MMBTU heat input or less, the arithmetic average of 

the two equivalent S02 inlet rates shall be used as the "equivalent hourly average S02 

inlet rate" for each hourly percent reduction calculation during the boiler operation day. 

Otherwise, the owner/operator shall; .(1) use the smaller of the two equivalent S02 iniet 

rates as the "equivalent hourly average S02 inlet rate" for each hourly percent reduction 

calculation during the boiler operating day or (2) calculate an "equivalent hourly average 

S02 inlet rate" for each hour of operation using the following heat input weighted 

equation. 

W1#%S1 + W2*%S2 

Equivalent hourly average S02 inlet rate = K 

WI#GHV1 + W2*GHV2 

Wl = Tons of coal fed to first of paired day bunkers during hour 

W2 = Tons of coal fed tc second of paired day bunkers during hour 

%S1 = Weight percent sulfur of coal contained in first bunker 

%S2 = Weight percent sulfur of coal contained in second bunker 

GHVl = Gross heating value of coal contained in first bunker 

GHV2 = Gross heating value of coal contained in second bunker 

K = 20.000 (ro"BTU)/(%*MMBTU) 

i 

B. Particulate, Lead and Beryllium 

A continuous monitoring system for measuring the opacity of emissions discharged into 

tne atmosphere shall be installed, calibrated, operated, and maintained during all periods 

of ooeration of tha boiler except for continuous monitoring system breakdowns and 

repairs. Operation shall ba in conformance with 40 CFR 60.48b which includes recording 

the output of the system,. Reporting and recordkeeping requirements shall be in 

conformance with 40 CFR 60.49b which shall include filing a quarterly report of excess 

emissions as outlined therein. Any existing monitor shall be recertified acccording to the 

procedures specified by the Department. 

13. Notification. Reporting and Recordkeeping. 

A. The owner/operator shall furnish the DNR written notification of the follows 

conditions; 

1. Any usage of this source contrary to those limitations specified in Condition 6 as 

required by Chapter 24 of the IAC. 

2. The date that construction of the boiler has begun postmarked within seven (7) 

cays of that date. 

3. The anticipated date of initial startup of the proposed boiler, postmarked not more 

than sixty (60) days nor less than thirty (30) days prior to such date. 

4. The actual date of start of operation postmarked within 15 (fifteen) days following 

the start of operation. 

5. The anticipated dace of each performance test postmarked not more than 

forty-five (45) days nor less than thirty (30) days prior to the date of the test. 

6. The actual date of installation and startup of each CEMS required herein, 

postmarked within fifteen (15) days of completion. 

7. The anticipated dates of the operational test period, test protocol, and daily 

schedule of the monitor tests postmarked thirty (30) days prior to such activities. 
P.27 

IOWA DEPARTMENT OF NATURAL RESOURCES 

Air Quality Section 

4

 ' NOx BACT Analysis 

ADM Cedar Rapids Boiler #4 

Control Technology 

Feasibility < 

Background 

The infdal Radian repon conuins a summary of fluidized bed boiler permits issued since 1985 including 

those muring Issuance. This summary documents LAER pennies issued in 1985-87 setting NOx limits 

from 0.04 through 0.10 lb/MMBtu based on Selective Non-Catalytic Reduction (SNCR); BACT permits 

In 1988-89 setting NOx limits of 0.29-0.50 lb/MMBm based on combustion controls (CC); and BACT 

permits in 1990-92 setting NOx limits from 0.11-0.29 lb/MMBtu based on SNCR with one exception 

at 0.40 lb/MMBtu based on Combustion Control (CC). See Figure 1. Figure I shows the trend in 

BACT determinations towards the 1985-1987 LAER limits. This is what would be expected wi& a 

properly conducted BACT review. 

The Radian report confirms that both CC and SNCR requirements have been established and the systems 

have been operating based on permits from 1988 and 1985 respectively. Emission limits have ranged 

from 0.04 to 0.50 lb NOx /MMBtu with the most recent BACT limit 0.16 lb/MMBtu (Figure 1 and 

Radian Report Table 2-2). Tbe most recent permit determinations mors accurately reflea the current 

technology and economics. These are significant since BACT is a case-by-case review considering tht 

economics of the technology at the time of review. 

Figure 1 

o 

co36': 

a 

l o , 

— CNcd: 

"in 

V) 

UJ 

ADM Cedar Ropids Boiler §4 

BACT and LAER Determinations 

for similar boilers 

over Time 

BACT Detirinat'oni 

LAER determinations •^* . 

o84 

I I 1 v I I I I i | . . I 1 ) i . • I 

86 

iii i i t c | i ii. i i » i i j i i i i T r i I i • 

88 90 92 94 

Year 
P.28 

January 11, 1993 

Figure 2 

ADM Cedar Rapids Boiler #4 PSD Review 

O 

O. 

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O : 

CN; 

O : 

O . 

tri 

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Q: 

c 

Q. 

(fl 

0) 

v . 

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qto3 

ADM Cedar Rapids Boiler #4 

BACT Determination 

Interest Rates 

over Time 

Prime Interest Rate ADM's • 

Proposed 

Rate 

X 

EPA 

Report 

Rate 

o 11 I i i | i i I I | i i i I 11 i i i | . . 

ci81 82 83 84 85 

i | 111 1 11 i'fi 11 r i i j I 11 i | i 111 1 11 11 | i i I i | 

86 87 88 89 90 91 92 93 

Yea 

Ammonia induced cost increases 

ADM alleges that residual ammonia levels in the ash will increase waste disposal costs 2.5 times the 

current costs. In addition, ADM claims thai ammonia reactions with sulfur dioxide and chlorine 

emissions from the coal will increase maintenance requirements making the boiler unavailable between 

une and ten percent (1 -10%) of the time. 

The Department is unaware of any requirement which would increase disposal costs because of the trace 

ammonia levels projected. Similarly, the potential loss of recycling opportunities was determined to be 

insignificant in light of the substantial oversupply of usable ash in the region. 

The possibility exists that ammonium salt deposits could require greater maintenance reducing boiler 

availability. This was taken into account in the economic analysis prepared by Radian and is reflected 

in this report. 
P.29 

January 28, 1993 ADM Cedar Rapids Boiler #4 PSD Review 

moderation of the substantial mass of aggregate in the turbulent fluidized combustion bed (supplemental 

responses #2.4 and 22]. 

Accepting ADM's claim that a fluidized bed with ovetftre air emitting NOx at 0.40 lb/MMBtu is 

baseline ("a realistic scenario of upper bound uncontrolled emissions") would change the Department's 

economic analysis. Upon review of ADM's argument as well as operating records for existing Boilers 

#1 through #3 (summarized below), the Department agrees that the baseline for this particular boiler 

is 0.40 lb NOx/MMBtu of boiler input. 

Emission averaging Time 

A 30-day rolling average emission limit was proposed by the Department to satisfy both PSD and NSPS 

requirements. In their supplemental submittal Radian supports this averaging period [supplemental 

response #31 and provides data to indicate why startup temperature limitations preclude short-term NOx 

limits [supplemental response #18]. This averaging time will be used. 

Combustion Control (CC) Efficiencies 

Although 0.40 Ib/MMBcu may be the 'reasonable scenario of upper bound uncontrolled emissions for 

the source", this boiler design can reasonably be expected to perform more efficiently when managed 

fur NOx control. Of significance from one Emission Data Report (3rd quarter 1991) for existing boilers 

*l through #3 is the stability of both hourly and 30-day emissions. The 30-day averages persisted for 

a week or longer without changing by 0.01 lb/MMBtu. Noting a 30-day rolling average consists of 

over 700 hourly readings, even a dramatic change in-emissions (such as a drop to 0.19 lb/MMBtu 

(8/22/91)) did not reduce the 30-day rolling average. 

Boiler #1 had 30-dav rolling averages of: 

0.32 Ib/MMBtufrora 7/1- through 7/8 , 0.31 lb/MMBtufrom 7/9 through 7/25, 

0.30 Ib/MMBtufrora 7/26 through J/ 2 , 0.31 Ib/MMBtufrom 8/3 through 8/14, 

0.30 Ib/MMBtufrora 8/15 through 8/29, 0.29 Ib/MMBtufrom 8/30 through 9/12, 

0.30 Ib/MMBtufrom 9/13 through 9/24, 0.31 lb/MMBtuon 9/25, 

0.30 Ib/MMBtufrom 9/26 through 9/28, 0.31 Ib/MMBtufrom 9/29 through 9/30+. 

with hourly emissions from 0.19 Ib/MMBtu (I hour on 8/22) to 0.36 lb/MMBtu (1 hour on 9/21). 

Boiler 11 had 30-dav rolling averages of: 

0.30 lb/MMBtufrom 7/1- through 8/18, 0.29 Ib/MMBtufrom 8/19 through 8/29, 

0.28 Ib/MMBtufrom 8/30 through 9/6 , 0.29 lb/MMBtufrom 9/7 through 9/12, 

0.30 Ib/MMBtufrom 9/13 through 9/21, 0.31 lb/MMBtufrom 9/22 through 9/30+. 

with hourly emissions from 0.24 lb/MMBtu (14 hour on 8/24) to 0.36 lb/MMBtu (1 hour on 9/22). 

Boiler #3 had 30-dav rolling sveraEes of; 

0.33 Ib/MMBtuthrough 7/1-. 0.34 lb/MMBtuon 7/2, 

0.33 lb/MMBtufrom 7/3 through 7/6, 0.32 lb/MMBtufrom 7/7 through 7/24, 

0.31 Ib/MMBtufrom 7/25 through 8/2, 0.32 lb/MMBtufrom 8/3 through 8/8. 

0.31 Ib/MMBtufrora 8/9 through 8/18, 0.30 lb/MMBtufrom 8/19 through 9/4, 

0.31 Ib/MMBrufrom 9/5 through 9/8. 0.32 lb/MMBtufrom 9/9 through 9/17, 

0.33 Ib/MMBtufrom 9/18 through 9/20, 0.34 lb/MMBtufrom 9/21 through 9/27. and 

0.3i lb/MMBtufrom 9/28 through 9/30+ 

(this boiler was taken down two hours into 9/28 four hours after NOx levels reached 0.50 lb/MMBtu.) 
P.30 

January 28, 1993 ADM Cedar Rapids Boiler #4 PSD Review 

reduction was corrected to use a single baseline. 

Ib| ADM's costs. 

jc] with revised availability costs as calculated by Radian and discussed above, 

j 11 from Table A-3 NOxOUT costs (because it's cheaper), 

Other SNCR Control Efficiencies 

Control to 0.11 Ib/MMBtu 

In their initial report Radian indicates a NOx emission limit of 0.11 lb/MMBtu has been 'provisionally 

guaranteed' as they were developing the 0.12 Ib/MMBtu option (page 2-21). Despite this, Radian 

addresses the two SNCR technologies as one option. In their supplemental submittal Radian explains 

this decision was based on the similarities in the reaction chemistry of the two techniques rather than • 

their performance or economic nuances (supplemental response #17]. 

In both cases Radian states this was subject to a maximum NH3 slip of 20 ppm. From this statement 

the costs for the 0.12 lb/MMBtu Thermal DeNOx option appear to be the sam: as the costs for the 0.11 

lb/MMBtu provisional guarantee. Therefore, these costs are calculated with the correct baseline. 

Control to 0.07 Ib'MMBtu 

The initial Radian report states: . 

"A lower emission limit of 0.07 lb/MMBtu for SNCR plus CC was considered 

technically infeasible due to high ammonia slip levels." 

"The cyclone temperatures ot* the ADM Cedar Rapids boiler 1-3 typically operate at 

1485 -1600 F. This temperature is much lower than the optimal SNCR"temperature of 

1900 F., and lower than many other CFB boiler applications. The lower temperature 

window requires a high reagent to N02 ratio to reduce NOx emissions down to 0.07 

lb/MMBtu. This would result in ammonia slip levels at probably 2 to 3 times greater 

than 20 ppm. This would result in ammonia emission concentration equal to or greater 

than the .NOx emissions. Additionally, the high ammonia slip levels would cause 

ammonia salt formation/deposition/emission problems that would significantly affect plane 

availability and waste disposal handling. Both Exxon and NALCO declined to give 

guarantees for a NOx emission rate of 0.07 Ib/M.MBtu with an ammonia slip less than 

20 ppm. Because SNCR plus CC with an emission limit of 0.07 lb/MMBtu with less 

than 20 ppm slip was not considered technically feasible for the proposed CFB boiler, 

the environmental, energy, and economic impacts were not assessed." (page 2-22) 

In their supplemental submittal Radian still has concerns about the feasibility of the lower emission limit 

because of the ammonia emissions which would be expected. Radian expects they would need a fourfold increase in reagent injection rates with injection ratios similar to those required in California for 

emission limits of 0.04 to 0.065 lb/MMBtu (supplemental response #20]. Alternately, ADM could use 

reaction enhancers [supplemental response #4] but the economics of this option are not yet defined. 

Radian overstates the significance of higher ammonia slip. The State of Iowa does not have an air toxics 

program so ammonia levels are not a direct concern. These are, however, discussed in the 

environmental review which follows. 
P.31 

January 28, 1993 ADM Cedar Rapids Boiler #4 PSD Review 

The analysis to this point accepted Radian's cost components (other than solid waste disposal) at face 

value, including operational costs (supplemental response #25]. 

The Department has used the economic analysis developed for the Benzene NESHAP regulations as a 

guide for "reasonable costs" in BACT determinations, ln the benzene rulemaking an economic cost of 

- $3.000/ton of contaminant removed was considered acceptable. Although benzene is considered a 

"hazardous" contaminant, the criteria pollutants in PSD are specifically selected because of their clear 

threat to public health. Hence, the public health comparison is valid. 

It is evident all the options have reasonable costs. However, 0.07 lb/MMBtu NOx emissions is at the 

limit used by the Department previously for average costs analysis. SNCR perfbrmance efficiencies are 

dependent on reagent injection rates. As a result, SNCR control efficiency can be managed by adjusting 

injection rates within the limits of reagent storage and handling equipment and the feasibility limits of 

the technology. 

ln their supplemental submittal, Radian describes the factors which change as control limits for SNCR 

are tightened. Radian estimated the capital costs for 0.07 lb/MMBtu option from 0.12 lb/MMBtu costs 

using the "slx-tenrhs factor rule" as follows: 

A* C,-C,-(Q,/QJ 

In the same response Radian indicates: 

[supplemental response #20] 

"Circulating AFBC boilers in California have NH3 to NOx injection ratio's of 2:1 to 

4:1, the lower ratio for units with emission limits of 0.09-0.10 lb/MMBtu and the higher 

ratio for emission limits of 0.04-O.65 lb/MMBtu. Based on this information , it was 

assumed that an injection ratio of 4:1 would be necessary to achieve an emission limit 

of0.07 1b:MMBtu..." 

From the economic documentation, it is evident the 0.12 lb/MMBtu calculations are based on a ratio 

or' 1:1. The Radian cost relationships are used to develop additional efficiency options of 70% (the 

nominal 0.12 option), 72.5% (the nominal 0.11 option), 75%, 77.5%, 80%, and 82.5 (the nominal 0.07 

option) assuming a linear relationship between the two reagent ratios of the 0.12 and 0.07 Ib/MMBtu 

options. 

The resulting costs are summarized in Table 3 and Figure 3. 

Table 3 (continuation of Table 2) 

Control Technique emissions emission Annualized 

reduction Costs 

lb/MMBtu TPY (from baseline) 

Cost/Ton 

ofNOxreducion 

CC 12.5% SNCR _ 70% 

CC 12.5% SNCR @72.5% 

CC 12.5% SNCR© 75% 

CC 12.5% SNCR QV.5% 

CC 12.5% SNCR & 80% 

CC 12.5% SNCR® 82.5% 

w/ 1 % reduction in capacity 

w/ 10% " 

0.105 

0.09625 

0.0875 

0.07875 

0.07 

0.06125 

267 

244 

222 

200 

178 

156 

154 

139 

622 

645 

667 

689 

711 

733 

735 

750 

760,000 

760,000 

1,146,000 

1,545,000 

1,940,000 

2,335,000 

2,389,000 

2,905.000 

$1,176 WxOJT) 

$1,686 (Thermal 

deNOx) 

$2,108 " 

$2,494 ' 

$2,849 " 

$3,179 " 

$3,250 " 

S3.736 " 
P.32 

1,111 

778 

267 

264 

238 

— 

333 

844 

847 

873 

d 

d 

d 

dj 

— 

? 

732,000fb] 

799.000(b) 

1,331,0001b! 

0 

$867.30 

$943.33 

$1,524.63 

January 28, 1993 ADM Cedar Rapids Boiler #4 PSD Review 

In their supplemental report Radian states: "over rwo-thirds of the annual cost of the SNCR technologies 

is reagent consumption..." (page 6). As a result, the actual costs should be significandy less than 

indicated in Radian's analysis. 

If ADM's contention of 0.40 lb/MMBtu baseline were to be rejected, the economics would be as shown 

in Table 4. It should be noted the ability to operate combustion controls (CC) presents no capital costs 

and wuuld have unknown annual costs not documented by ADM. It is assumed CC presents no 

annualized costs. 

Table 4 (Table 2 continued) ' 

Status Control Technique emissions emission Annualized Cost/Ton 

reduction Costs of NOx reduction 

lb/MMBtu TPY (from baseline) 

baseline uncontrolled J>.0.50 

CC 0.40 

CC and SNCR 0.12 

w/ 1 % reduction in capacity 

w/ 10% reduction in capacity 

!d| emission reduction corrected to apparent uncontrolled baseline 

Incremental Cost Analysis 

Increases «n incremental cost/ton or emissions removed in switching from one control option to another 

may be used along with average cost/ton of emissions reduced when the average costs are nearing the 

cost cutoff, ln analyzine going from 80% to 82.5% SNCR efficiency, the incremental cost for Thermal 

deNOx is [$(3,179-2,849)/ton] = $330/ton increase in costs for an additional ((178-156)ton] = 22 tons 

of NOx removal. This results in an incremental cost of SI5.00/ton for each additional ton of 

contaminant removed and is an acceptable incremental cost. 

Summary 

The selection of a baseline does not sufficiently impact the economics to change the BACT selection. 

The most stringent emission limit must be established as BACT unless other criteria override the 

economics. This economic-based BACT limit is 0.06125 lb NOx/MMBtu utilizing combustion controls 

with ai least 12.5 % removal efficiency and ammonia-based selective non-catalytic reduction (SNCR) 

with at least 82.5 % efficiency. The resulting cost is $3,185/ton of NOx removed based on the 0.40 

.h/MMBtu baseline (depending on downtime which could result from ammonium salt formation). 

However, even with a 1% increase in boiler downtime due to ammonia salt formation, the cost increase 

is only - S70/ton, increasing the total cost to $3,255/.on. Increases beyond 1% are considered 

extremely unlikely due to the ability to operate combustion controls at better than 12.5% (ie .£.0.35 

lb/MMBtu). and the abilitv to manage other factors affecting salt deposition. Improving combustion 

control efficiency to 2^.4^ (<.0.31 Ib/MMBtu) would allow SNCR control efficiency to be decreased 

to 80.25% and still meet the specified emission limit. 

11 
P.33 

January 11, 1993 

Figure 4 

ADM Cedar Rapids Boiler #4 PSD Review 

ADM Cedar Rapids Boiler #4 , 

Nitrogen Oxide and Ammonia Emissions 

versus 

Nitrogen Oxide Emission Limit 

x 

O 

• I I I I I I I 1 f I i I I I ! t , , ) I . . I I I . I I ! < I 1 ! • . I i I | . . I I , | I . I 1 I I I I I i . 1 , | 

O.OO 0.10 0.20 0.30 0.40 ;0.50 0.60 

NOx Emission Limit (lb/MMBtu) 

Ammonia bandling/Hazardous material spills 

Ammonia injection will probably involve the shipmem, storage and handling of anhydrous ammonia. 

As noted in the Radian report: 

'Exposure to NH3 in the event of a tank truck loading/unloading accident or failure of 

the storage tank, could result in stvtrt adverse health effects. At low concentrations (10 

to 20 ppm) ammonia causes irritation of tbe nose, throat, eves, and the respiratory 

system. At higher concentrations, (greater than 500 ppm) NH3 is toxic to humans and 

animals. High concentrations produce severe symptoms involving laryngeal spasm, 

bronchial pneumonia, and fatality. In the event of a large anhydrous ammonia spill, 

concentrauons greater than 500 ppm would occur in the vicinity of the spill. Ammonia 

is classified as a Class 1, Division 2, Group H hazard by the National Fire Protection 

Association." (page 2-19) 

13 
P.34 

/ • ' •' •- • 

January 28, 1993 ADM Cedar Rapids Boiler #4 PSD Review 

presence in the boiler ash may alter the disposal leachate characteristics and/or effect the 

reusability of the boiler ash." 

"The ash from ADM's current circulating AFBC boilers 1-3 at the Cedar Rapids 

cogeneration facility is currently being disposed of in the mine of the Iowa coal source 

and reuse opdons are being investigated.... if SNCR is applied, the absorbed NH3 could 

reduce the waste reuse potential. Additionally, the NH3 and ammonium salts may 

change the ash characteristics sufficiently to require a more costly landfill option." (page 

2-18) 

Radian applies a $15/ton surcharge to account for the potential higher disposal costs. Radian did not 

document the cost of leachate tests or the sensitivity of the ash to failing the leacbate test that might 

apply. In their supplemental submittal, Radian continues to use these higher waste disposal cost 

projections [supplemental response #24] even though the response to the Department's request for 

substantiation is ".. we do not know the impact of the resulting ash..." [supplemental response #14j. 

Even if additional costs were incurred, the end result would provide equivalent environmental protection. 

This concern is reduced to an economic concern which is addressed in Radian's cost calculations. These 

justs must be confirmed as well as the sensitivity of the emission opacity to operational parameters. The 

Department is unaware of any requirement which would increase disposal costs because of the trace 

ammonia levels projected. 

The potential reuse option for the solid waste generated from ammonia injection is cement manufacture. 

Given the many sources of usable ash currently being landfilled, the Department's opinion is that any 

damage to the ash produced at one (or even all) of the four ADM boilers from ammonia injection would 

not effect potential ash use in Iowa. 

Energy 

Impacts of alternative energy production 

Radian discusses higher emissions which would be produced by ADM using alternate sources of energy 

in the metro area during boiler downtime. They suggest the environment would be better served by 

assuring maximum utilization of this boiler. It is possible die proposed boiler would emit less per 

kilowatt-hour than existing utility boilers as currently managed. However, the acid rain provisions of 

the 1990 Clean Air Aa Amendments are the appropriate means of addressing this issue and will 

substantially reduce environmental impacts from these sources. This is not a valid criteria for selection 

of a control technology for this application. 

. NOx BAC T Determination 

Citing EPA's public comments: "The Proposed NOx BACT of 0.10 lb/million Btu of heat input appears 

to be too high .." and, "A NOx limit of 0.08 lb/million BTU would be more appropriate." 

Ttu initial Radian teport statts: 

"Recent BACT permit limits set for circulating AFBC boilers firing high sulfur coals 

have higher limits for NOx (0.11-0.16 lb/MMBtu) than the LAER determination limits 

(0.04-0.1 lb/ MMBtn) of the California circulating AFBC boilers." (page 2-21) 

15