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OAR Box 1781 

Prepped by Ollie Stewart 

Document Number: 

83) IV-B-7 

Docket Number: 

A-90-37 

Printed 10/29/2008 10:46:21 AM Sheet 83 of 142 
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• ; • 

i 

»«* 0Sr « A 

ONITEO STATES ENVIRONMENTAL PROTECTION AGENCY 

RESEARCH TRIANGLE PARK. NC 27711 

APR 1 4 

A-^o-viOFFICE OF 

MR QUALITY PLANNING 

AND STANDARDS 

MEMORANDUM 

SUBJECT: New Source Review Program 

PROM: 

TO: 

John S. Seitz, Director C^-J^-fa-. 

Office of Air Quality Planting and Stan 

See Addressees 

idards^uO-10) 

EPA AIR DOCKF.T 

The purpose of this memorandum is to alert you to some concerns we have regarding part 

of die New Source Review (NSR) program, i.e., the Prevention of Significant Deterioration 

(PSD) program, and to ask your assistance in determining die true extent of any problem. The 

concern focuses on whether or not the PSD program is being implemented appropriately in all 

areas of die country. The PSD program is an important part of our air quality management 

program, and is one on which we plan to rely heavily as we move toward implementing the new 

ozone standard in transitional areas. We will need your support in gathering additional data diat 

will allow us to better assess diis situation. If this further study confirms diat die PSD program is 

not being implemented appropriately, corrective action will be required. 

Our concerns grow out of conversations with personnel from the Office of Enforcement 

and Compliance Assurance (OECA), the letter to Administrator Carol Browner from Peter 

Hamlin, Chief of the Iowa Air Quality Bureau, and a review of information submitted to my staff 

by die National Park Service (NPS). Based on these, I am concerned that a number of problems 

related to program implementation may exist, as we discussed at our meeting in Las Vegas. 

Given die importance of the PSD program tp managing our national air quality program, it is 

critical for us to take steps to gamer additional information on this issue. In addition, I believe 

diat mere are several steps we should take to better monitor the PSD program as we implement it 

over die next year, and to address the kinds of issues diat have been raised. 

•f. 

First, I am asking each Regional Office to review and comment on die specific permits 

described in die NPS memorandum which was sent to your staff in early January (see attached). 

By May 7,1999,1 ask that you respond witii a memorandum describing whether you agree or 

d::2g-cc v.ith the conclusions reached in the NPS memorandum as it relates to the permits issued 

by States in your Region. If problems are identified, your memorandum should also recommend 

any specific actions that you believe should be taken. 
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Second, I ask that you obtain for review the preliminary and final determinations for all 

PSD permits issued by the States in your Region or those currently undergoing review within the 

Region since January 1,1997. We are aware that this request may require obtaining a copy of 

the documents from a State or local agency in those cases where copies have not already been 

provided to the Region. Given the concerns expressed about the resources such a review would 

entail, we are willing to provide on-site assistance to each Region to assist in the compilation of 

these data. In order to schedule such assistance, you should have these determinations available 

for review by June 1,1999. Once the determinations are collected, we intend to extract the 

following information: 

1. facility name, permit ID, source type, location and Standard Industrial Classification (SIC) 

code(s); 

2. project description (boiler, dryer, etc.), emission unit number, operating limit/units, size or,•; 

capacity/units, fuel type; 

3. die control technology selected as Best Available Control Technology (BACT); 

4. whether the cost analysis followed EPA guidance and whether the documentation was 

adequate; 

5. me pollutants emitted; 

6. the permitted emission rates; 

7. me distance to the Class I area and whether the Federal Land Manager (FLM) was notified 

appropriately; 

8. whetiier the Regional Office commented on the permit and, if so, whether the permitting 

authority incorporated the Regional Office comments; 

9. whether the BACT determination is more stringent than the applicable New Source 

Performance Standards (NSPS) and, if so, the number of tons per year of emissions that 

were prevented; 

10. where there was no applicable NSPS, whether BACT was more stringent than the applicable 

State Implementation Plan (SIP) limit; the number of tons per year of emissions which was 

prevented by applying BACT; [This step will require that a copy of each State/local SIP 

rule be available.] 

11. the monitoring, record keeping and reporting requirements that were applied, such as 

continuous emission monitoring, averaging times, etc. 

If you do not require assistance in developing this information, we will provide you with a 

common format spreadsheet on which the data should be entered. In those cases where we assist 

in the compilation, we will provide you with a copy of your Region's data for your review. 
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Though the PSD program is the primary focus of this effort, we are also interested in 

gathering some data on the nonattainment NSR program. Due to the resource constraints we all 

have, I recommend we do this prospectively by conducting a closer review of NSR permit 

applications, preliminary determinations, final determinations and tracking the permits that 

finally are issued for applications received since January 1,1999. For nonattainment NSR 

permits, the information needs are somewhat different. Since the Class I area and FLM status are 

not applicable, and the Lowest Achievable Emission Rate (LAER) is needed in lieu of BACT for 

the nonattainment NSR permits please substitute the following information for items 3,4, 7, 9, 

and 10 above: 

3a. the emission limit and control technology selected as LAER; 

4a. whedier cost (or other factors) was an issue in determining what technology was selected as 

LAER; 

7a. whether the offsets were appropriately obtained and documented; 

9a. whedier the LAER determination was more stringent than the applicable NSPS level of 

control and, if so, the estimate of the additional tons of emissions reductions that were 

obtained; 

10a. where there is no applicable NSPS, whether LAER was more stringent than the applicable 

SIP limit; if so, the number of additional tons per year prevented from entering the 

environment. 

In addition to the information gathering steps described above, some additional work will 

be necessary including activities tiiat could require reprogramming of resources. First, for the 

FY 2000-01 program guidance, we are requiring more reporting from the Regional Offices for 

PSD and nonattainment NSR permits which will be reviewed during the upcoming years. 

Second, we are coordinating closely with OECA in their enforcement initiative relating to the 

PSD and nonattainment NSR programs. Finally, we are also considering re-instituting the annual 

conference among Headquarters, Regional Office, and State and local agency staff for training 

purposes, and to help promote national consistency in matters pertaining to tiiese programs. 

I expect to be communicating with our colleagues from the State and local agencies about 

this matter in the near future. In developing this plan, we have worked closely with Region VU, 

the sub-lead region for permits. I look forward to hearing from you, and urge your cooperation 

in making this a high priority. If you have any questions, please contact Karen Blanchard at 

(919) 541-5503. 

Attachment 
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I* / 

Addressees:" 

Director, Office of Ecosystem Protection, Region I 

Director, Division of Environmental Planning and Protection, Region II 

Acting Director, Air Protection Division, Region UI 

Director, Air, Pesticides and Toxics Management Division, Region IV 

Director, Air and Radiation Division, Region V 

Director, Multimedia Planning and Permitting Division, Region VI 

Director, Air, RCRA and Toxics Division, Region VJJ 

Assistant Regional Administrator, Office of Pollution Prevention, State and Tribal Programs, 

Region VTJI 

Director, Air Division, Region DC 

Director, Office of Air Quality, Region X 

V 
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4-13-99 

***FOR EPA INTERNAL USE ONLY*** 

COMMUNICATION PLAN 

Office of Air and Radiation 

KEY WORD TITLE: PSD/NSR Permit Program Review 

ISSUE IMPORTANCE: Medium 

PROJECTED ANNOUNCEMENT DATE: March 1,1999 

AGENCY CONTACTS: Ms. Karen Blanchard, Office of Air Quality Planning and 

Standards 

(919)541-5503 

1. ACTION: 

EPA Headquarters is issuing a memorandum to the Regional Air Directors requesting 

information about the PSD/NSR permit review process in their regions. By May 7,1999, 

EPA OAQPS is asking the Regions to review and comment on specific concerns raised 

by staff at the National Park Service (NPS) about a subset of 47 permits that have been 

reviewed by die NPS and subsequently issued by state permitting authorities. By June 1, 

EPA OAQPS is asking the Regional Air Directors to make available for OAQPS review, 

copies of PSD permits, and permit files, for PSD permits that have been issued in the last 

two years. Specifically, OAQPS needs to ensure that construction projects at major 

sources are undergoing pre-construction PSD/NSR reviews and that the appropriate level 

of air pollution control is being applied. 

2. MESSAGE: 

The PSD/NSR program is an important part of our national air quality management 

program, and is one upon which we plan to rely heavily as we move forward 

implementing the new ozone air quality standards in transitional areas. Over the next 

year, we intend to monitor the health of the program to ensure that it is being 

implemented appropriately and consistently across the country. 

3. AUDIENCE: 

(a) EPA Regional Offices 

(b) EPA Office of Air and Radiation, Office of Enforcement and Compliance Assessment 

Assistant Administrator, and Office Directors 

(c) State/Local Air Pollution Control Agencies 

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•*•»• / A 

4. OVERALL STRATEGY: 

EPA will conduct an initial assessment to respond to specific concerns raised by staff 

from the NPS, and general concerns raised by an air director from a State agency, i.e., 

Iowa, as well as from informal discussions with personnel from the Office of 

Enforcement and Compliance Assurance, to determine whedier the initial concerns 

identified regarding implementation of the PSD program warrant corrective action. 

Following this initial evaluation, EPA OAR and the Regional Offices will determine what 

corrective action, if any, is needed. The type of information that will be reviewed 

includes a compilation of the following for each permit: 

— What control technology was selected as BACT? 

— What pollutants were emitted, and from what industry? 

— What were the allowable emission rates? 

— What is the proximity to the nearest Class I area? Were FLM's notified? 

— Did the Regional Office comment on the draft permit? Were tiiese comments 

incorporated into the permit? 

In addition to the information gathering steps above, EPA/OAR has decided to require 

additional reporting from Regional Offices on PSD and nonattainment New Source 

Review permits for the upcoming years (FY2000 • 2001). OAR is also coordinating 

closely with OECA in their enforcement initiative relating to these permitting programs. 

Additionally, OAR is considering taking additional steps to ensure the program is being 

implemented effectively. One such step includes possibly re-instituting annual training 

conferences among EPA, State and local permitting staff to help promote national 

consistency by providing an opportunity for dialogue and collaboration. 

5. BACKGROUND SUMMARY: 

On August 3,1998, Peter Hamlin, Chief of the Iowa Air Quality Bureau, sent a letter to 

Administrator Browner raising a number of concerns about the integrity of the PSD 

program nationally. Specific concerns included the lack of PSD permits that are being 

issued, inappropriate BACT determinations, and inconsistent BACT determinations for 

similar sources in different parts of the U.S. Similar problems were identified in a 

memorandum to EPA staff from National Park Service staff. 

6. DESCRIPTION OF ACTION: 

EPA is undertaking this data gathering effort to either further investigate the preliminary 

infonnation suggesting that there may be problems in how the PSD program is being 

implemented. 

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7. EFFECT.OF ACTION: 

If results of the data gathering effort confirm preliminary concerns regarding PSD 

program implementation, a number of actions could result. These could include: 

reprograrnming of resources to allow increased program oversight, issuing guidance 

memoranda and/or making regulatory changes to reduce the likelihood of incorrect 

interpretations of the requirements, as well as providing greater emphasis on training. 

8. ANTICIPATED REACTION: 

State and local permitting authorities may be unsupportive of this effort if it appears that 

some agencies may be the subject of criticism. 

EPA Regional Offices will have concerns about the resource implications of undertaking 

the effort given the competing need to issue Title V operating permits. 

Some people from the public or industrial sectors may complain that EPA has 

mismanaged the program. 

Industrial representatives and State and local agencies may argue that the program is so 

complicated diat no one can implement it appropriately. 

9. DETAILED STRATEGY: 

The Office of Air Quality Planning and Standards (OAQPS) will send the final 

memorandum to die Regional Air Directors by Friday April 16. 

Regional Office memoranda concerning the National Park Service staff comments on 47 

permits are due to OAQPS by May 7,1999. 

OAQPS will engage in discussion with State and local air agencies during the April/May 

time frame, with some discussion between staff and the STAPPA/ALAPCO permitting 

committee co-chairs in late April, followed by at least informal discussions between the 

ITPID Division Director and/or the OAQPS Office Director at the STAPPA/ALAPCO 

membership meeting in Arizona on May 15. 

c:\archive\psdcs.wpd 

# "=* • 
_H9_ 

MEMORANDUM 

To: John Bunyak, Dennis Crumpler, Lew Nagler 

From: Don Shepherd 

Subject: NSR Issues 

Date: December 4,1998 

Background 

For the past two decades the federal program for the Prevention of Significant Deterioration 

(PSD) has sought to protect those areas where air quality is better than the level required for the 

protection of human health, especially in those pristine Class I areas set aside for preservation in 

their natural state. One of the major tenets of a federal program was that it should help establish a 

"level playing field" so that similar industries locating in similar situations should experience 

similar air pollution control costs. It was also expected that the Best Available Control 

Technology (BACT) requirement of the PSD regulations would be technology forcing, driving 

the state-of-the-art toward more effective control strategies. At a minimum, BACT was to be at 

least as stringent as any applicable New Source Performance Standard (NSPS), which were to be 

updated every eight years. EPA was to play the role of overseer and "referee" for die PSD 

program, acting as a source of new control technology standards, as well as guidance on 

interpretations and final arbiter of disputes. One of EPA's key functions was to act as a control 

technology information repository (the RACT/BACT/LAER Clearinghouse), the premise being 

that new sources would be required by the states to meet levels of control equivalent to diat 

established elsewhere, thus promoting consistency and the "level playing field," and uniformly 

forcing die technology toward more effective pollution control. 

Findings 

Of the 47 PSD permit applications diat I reviewed over the past 15 months, about half had a 

"fatal flaw" that would invalidate their conclusions that more effective air pollution controls are 

not feasible. 

Applicability: Five applications involved questions of applicability of PSD to pollutants other 

than originally reviewed. Our observation that emissions from other operations at a major source 

could be effected by the modified emissions unit and should thus be included in the applicability 

determination were rejected by most states, although FL DEP did require applicants to 

investigate this possibility in subsequent applications with the result that additional processes 

and pollutants became subject to PSD review. One state rejected our concern by saying they had 

made a "policy decision" not to consider collateral effects; another state never seemed to grasp 

the issue. In discussing a netting issue with one state, it was pointed out to us that the state could 

essentially do whatever it wished because its EPA regional office did not review permits when 

sources had netted out of PSD. 

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NSPS as a minimum level of control: One state had an inconsistent approach to use of the NSPS 

as a "floor" for control effectiveness. In one case, the state refused to recognize data submitted by 

NPS showing that a category of sources (phosphate fertilizer plants) was capable of meeting 

sulfuric acid emissions limits less than half those set by the NSPS and vowed allegiance to the 

NSPS. Our contention was that, not only was this 20-year old standard out-of-date, it was 

incorrectly established in the first place. In another case, the same state made a "policy decision" 

to ignore a proposed (but effective) revision to NOx limits for utility boilers because they felt 

that a higher limit was more appropriate. Despite the proposed NSPS, the EPA region concurred 

witii the state's approach, on the condition that the applicant would have to meet the final NSPS 

upon promulgation. Our concern with this EPA determination was that it circumvented BACT by 

setting BACT equal to the final NSPS with no consideration that BACT might be more stringent 

in this case. 

A second state initially appeared to be so wedded to using the phosphate fertilizer NSPS as 

BACT that, even though it admitted that typical control technology (mist eliminators) could 

perform much better, it continued to write the ancient NSPS limits into its permits. However, the 

state was open to our demonstration that lower limits were achievable and subsequently set its 

BACT limits lower than NSPS in permits that followed. 

A third state used the 24-year old Ferro-alloy NSPS to set particulate emission limits at twice the 

rate measured for a similar, existing unit at the same plant. 

EPA "approval" of BACT: Several states and applicants have used EPA's actions (or inactions) to 

claim approval of a control technology that does not necessarily represent BACT. The most 

egregious example occurred when a flat glass manufacturer proposed location of a new plant 

within 30 kilometers of Shenandoah National Park. Even though the company employs S02 and 

PM controls at its two plants in Wisconsin, and even though the Park is already suffering adverse 

. impacts due to sulfate pollution and visibility impairment, the company chose not to control S02 

and PM near Shenandoah. The state agency went along with the applicant, citing PSD permits 

issued to similar flat glass plants in Iowa, Kentucky, and New York. Both the applicant and the 

state argued that, because EPA had "approved" those plants without the S02 and PM controls 

that had previously been the industry norm, it would be unfair to require the company to spend 

any money to control those same pollutants near a National Park. (Even the applicant noted that 

electrostatic precipitators were in use to control PM at 90% of similar glass plants around the 

world.) Research by NPS into those three uncontrolled plants found that, in each case, EPA staff 

wrote strong objections to the states concerning the lack of S02 and PM controls, but no action 

was taken when the states ignored the EPA objections. EPA's response was, once again, that it 

was die "state's call." 

Failure by EPA to conduct or stand by a rigorous BACT analysis played a part in at least two 

other permits in our sample. In one case, EPA's approval of a new lime plant without NOx 

controls undercut our argument that such controls should at least be evaluated for their economic 

feasibility. In another case, EPA's comments during our review period that SCR was not 

required on a combined cycle turbine (CCT) in the Pacific Northwest, when SCR is the 
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presumptive norm on all other CCTs we have reviewed, undercut our influence in reducing NOx 

emissions in that area. 

Faulty technical feasibility analyses: The first step in the BACT analysis is to identify control 

technologies that are technically feasible. Not only must an applicant consider control 

technologies that have been proven for its particular type of process, it must also consider the 

potential for transfer of control technology from another application with similar pollutant stream 

characteristics. Some states expressed a reluctance to consider such "technology transfer," while 

one openly refused, stating that if a control had not been used on an identical source, they would 

not even consider it. Even when we provided examples of two low-solvent coating technologies 

in use at a high quality furniture plant in the same region, another state dismissed that technology 

because the applicant had unsubstantiated "quality concerns." This appears to be an area where 

states are extremely reluctant to tread—only Virginia required an applicant to analyze the factors 

associated with transferring control technology from a proven application to an unproven one. 

Faulty economic feasibility analyses: If a control technology is determined to be technically 

feasible, it is not necessarily a candidate for use unless it is also economically feasible. That does 

not mean that the plant can afford it, just that the cost of using the control is within the same 

general range as costs for similar controls at similar facilities. One applicant used the argument 

that if it had to retrofit dry low-NOx combustion technology (or any other NOx control 

technology) to the 1969 vintage gas turbines it proposed tp bring into the state, it could not afford 

the project. 

EPA cautions against establishing one "bright line" or generic test for determining how many 

dollars should be spent to control a ton of "pollutant" regardless of the industry; instead, EPA 

recommends that control costs typical to the industry and specific to the pollutant be used as the 

criteria. OAQPS has prepared a Control Cost Manual (available on the CATC website) to serve 

as a guide in estimating the costs of various control options. 

About 60% of the applications reviewed contained significant errors in this portion of the BACT 

analysis. Many states performed the cost analyses without ever stating what an acceptable 

cost/ton would be. (One state concluded that any cost would be unacceptable!) Others applied a 

generic $/ton to all processes and pollutants. These cost thresholds ranged from around 

$2000/ton - $5000 /ton, irrespective of the pollutant. Even when a cost fell below the state's 

economic feasibility threshold, the applicant would conclude that it was still too expensive. 

The most common mistakes in the cost analyses were the lack of documentation to support cost 

estimates, inflated costs, and the use of a 10% interest rate when calculating the long term costs 

of investing money into pollution control equipment. Often, the applicant would use those 

portions of the Cost Manual that drove costs upward, and ignore or substitute higher costs for 

those portions of the Manual that tended toward lower costs, without justifying its deviation from 

the Manuals procedures. Despite advising every applicant and host-state that, as of March 1997, 

OMB and OAQPS had changed the annual interest rate to 7%, most continued to use the old 

10% rate that inflates costs dramatically (about 25%) over the 20-year life of most air pollution 

control equipment. (One state did perform alternate calculations using the 7% interest rate after 

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we pointed this out.) Applicants also tended to underestimate the life of control equipment they 

did not want to purchase, in some cases shortening the life-expectancy by as much as a factor of 

five. In one case, the applicant calculated the incremental costs of moving from one (favored) 

level of emissions control to a higher (unfavored) level. Although this is an acceptable step in the 

economic analysis, EPA procedures advise that it must be preceded by a calculation of average 

cost effectiveness, so that the "big picture" of overall emission reductions and costs can be 

shown. 

It is typically extremely difficult to prove that an applicant has overestimated its costs when there 

is no documentation to support (or refute) those costs. States are often under so much pressure to 

issue permits quickly that there is great reluctance to require the applicant to return with 

documentation to support its cost assumptions. (Virginia did require such a re-analysis and the 

result was a very well documented and thoroughly researched economic analysis that is included 

as an attachment to this report.) It may also be the case that state permit review engineers are not 

familiar with the economic analysis procedures and are therefore uncomfortable with the whole 

process. In many cases, we have resorted to conducting generic cost analyses based on our 

estimation of typical industry costs for a given project. 

Faulty environmental impacts analyses: Even though a potential control technology may be 

technically and economically feasible, it may still be rejected because it creates an unacceptable 

environmental impact or depletes some scarce resource. One state attempted to advance this 

logic to the its illogical conclusion by advising an applicant that improved control of S02 

emissions at a phosphate fertilizer plant need not be considered because it would generate a 

waste product. Because all add-on air pollution control technologies convert air pollutants into 

some other form of waste, this superficial argument would eliminate all current technologies 

from consideration. 

Another invalid environmental feasibility argument is based on the premise that, if no air quality 

. standard is being exceeded or AQRV adversely impacted, BACT can be less stringent. Some 

sources try to argue that, if air quality impacts are very low, BACT can be relaxed. As EPA has 

noted, BACT must stand on its own. 

Other states are currently struggling with the legitimate question of the side effects created by 

pushing NOx control technology to ever-lower emission rates. For example, SCR requires the 

injection of ammonia into the stack gas to react with NOx. As the catalyst in the system 

deteriorates, more and more of this ammonia fails to react with the NOx and is, instead, released 

to the atmosphere (as "slip"). Furthermore, both the ammonia used to react with the NOx and the 

spent catalyst are hazardous materials and require special handling. Unfortunately, applicants 

who are trying to make a case for rejecting SCR often overstate its risks. (On the other hand, 

applicants proposing SCR usually report that these risk's can be managed successfully through 

p

r

oper plant procedures.) So, the issue becomes one of balancing the desire to reduce NOx 

emissions with the need to prevent excessive ammonia "slip" from the stack, ammonia spills, and 

the problem of dealing with disposal of the catalyst with its heavy metals. Although two states 

are talcing an objective look at this problem, they may need some technical assistance. For 

example, one state appears to have assumed that a one part-per-million (ppm) increase in 

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ammonia emissions had the same weight as a one-ppm reduction in NOx. Due to the differences 

in molecular weights, the actual trade-off is much more favorable to NOx reduction. 

Procedural Issues: Although federal regulations, EPA's New Source Review Workshop Manual, 

and our own PSD guidance publications all lay out the time periods in which information on 

PSD applications that may affect visibility in any federal Class I area must be provided or taken, 

many states are either unaware of these requirements or do not care. In one case, we found out 

about a PSD applicant near GRSM through local private contacts-the state had never advised us 

of that or several other PSD permits. Another state told us that we had missed their 20-day period 

to file a notice of intent to comment, although we were never informed of the permit application 

or given our required 60 days to review and comment upon it. (The state did "grant" us a ten-day 

extension, although, when the visibility analysis was received on the ninth day, no further 

extensions were allowed.) When we advised the state of our rights to more time, their reaction 

was one of total disbelief. 

The most blatant example is ongoing in which the state continues to refuse to require the 

applicant to model the impact of its emissions on AQRVs at a nearby Class I area. The state 

contends that, as long as the Class I increments are not exceeded, the applicant does not bear the 

burden to conduct any further analyses with respect to the Class I area. 

In one case, a state advised us that they do not have authority to require an applicant requesting 

revision or extension of a PSD permit to revisit BACT. If that is the case, the adequacy of the 

state SIP should be questioned. Another state made a policy decision to set BACT higher than a 

proposed NSPS—with EPA concurrence. 

In the case of the glass plant mentioned above, the state refused to re-set the clock on our 60-day 

comment period, even though we advised them that the applicant had conducted its visibility 

modeling with the Appalachian Mountains running from southeast to northwest. The problem of 

states' unwillingness to provide us the required information and time, or ignorance of those 

requirements, is widespread; roughly two-thirds of the states involved in this sample failed to 

follow the proper PSD permitting procedures in this respect This results in our having to prepare 

comments on major issues with minimal time and information. 

And, even when we do submit comments, their impact is hard to gauge. In one case, even though 

we had submitted two sets of comments on BACT, the state failed to include our second and 

most extensive set of comments in the public record. 

Additional Concerns 

As EPA continues to defer and delegate to the states, its lack of oversight appears to be 

encouraging development interests to prevail over environmental protection. For example, when 

questioned if it would review an applicant's visibility analysis for GRSM, a state, under intense 

pressure from the applicant across the table, proclaimed that it would accept the modeling results 

immediately and at face value. (As a minimum, the state should defer to the FLMs rather than 

simply accepting the applicant's analysis.) Another state also bordering GRSM submitted its 

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review of the applicant's BACT analysis in the form of a verbatim re-statement of the applicant's 

submittal. When we challenged a series of invalid assumptions about the technical infeasibility 

of controlling emission from a paper machine and associated boilers, the state agency became 

very defensive, even though the applicant was forced to radically alter its story. Finally, when we 

presented evidence to a state that there were emissions of S02 for which it had not accounted 

(and would trigger PSD for that pollutant), and that the applicant had mislead the state regarding 

the control technology that would actually be used, the state's response was to ignore the 

information and issue the permit. 

It is usually difficult to assess the effectiveness of our comments because we rarely receive a 

response from the state regarding the final disposition of the permit, or a specific response to our 

comments. (Florida has been very good at providing such follow-up.) It is also practically 

impossible to verify that "synthetic minors" are truly minor unless such actions were to be 

reported to EPA and the FLM. The evolution of synthetic minors into major sources through 

increases in throughput and emissions often leads to situations where the resulting control 

technology is less effective than that which would have been BACT had all of the emissions 

been reviewed initially, due to retrofit costs. 

Conclusions 

An overarching problem appears to be a lack of consistency among EPA regions in dealing with 

PSD. For example, the head of NSR for one EPA region noted recently that he would not dare 

require the level of control in his region that some other EPA regions do, for political and 

cultural reasons. As a result of these inconsistencies, we see a wide range of BACT within a 

given industry and time, as illustrated by the attached table of BACT determinations and pending 

applications for utility turbines. 

Despite die lack of strong nationwide EPA oversight, some states (CA, NJ) have maintained 

healthy NSR programs and can be counted upon to set the mark for other states to strive toward. 

And, states such as Florida have shown an encouraging willingness to consider our comments 

and concerns and try to address them fairly in its review process. Virginia's emphasis on regional 

office review and responsibility has resulted in some excellent efforts to evaluate the feasibility 

of alternate control strategies. On the other hand, other states appear to be so overwhelmed by the 

technical and political issues involved in NSR diat they can only "rubber stamp" applications as 

quickly as they can push permits out the door. 

It appears that many states need additional NSR staffing (who doesn't?) and training in the finer 

points of NSR, especially the economic analysis portion of the BACT review. This may account 

for the reluctance of many states to require thoroughly documented BACT demonstrations. There 

also appears to be a great reluctance to advance or transfer technology as a part of the BACT 

process, unless there is some outside driver such as an increment problem. Most deleterious to 

the FLMs is the seeming lack of understanding by many states of the procedural requirements 

that apply when a PSD source may impact a mandatory federal class I area. This often results in 

the FLMs receiving late notification (or no notification) regarding projects that may impact areas 

under their responsibility and forces the FLMs to rush their analyses to conform to the 

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applicant's construction schedule. Hopefully, NSR Reform will help address this deficiency, 

assuming states comply. 

Recommendations 

EPA/DOI/USFS must provide to the states support and incentive to train their NSR staffs. Only a 

staff that is knowledgeable of the PSD regulations, NSR procedures, and the roles of the FLMs 

can recognize the tactics used by applicants and their consultants, and understand the legitimate 

needs of the FLMs for information and time to review major applications. EPA should expand 

upon its standard educational programs by providing specialized courses in PSD-NSR and invite 

participation by the FLMs. (For example, current NSR training courses offered through AWMA 

and EPA are conducted by consultants with little actual experience in dealing with Class I 

issues.) 

No matter how well trained the staff of a state agency may be, without the support of the 

policy-makers, permitting decisions will default toward political expediency. EPA must take a 

more active role in oversight of PSD permitting activities and follow-through with remands of 

permits that it recognizes are defective. Only the threat of remand of a permit or revocation of 

authority will get the attention of some state and local programs. 

There is a tremendous need for better communication and coordination among the governmental 

permit review participants (permitting authority, EPA, and FLMs). The permitting authorities 

must become more aware of their obligations to notify and supply information to the FLMs in a 

timely fashion, and EPA and the FLMs should coordinate their responses to the permitting 

authorities so that mixed signals are not being sent. Permitting authorities should provide written 

responses to FLM written comments, as well as copies of final actions. (An alternate approach 

might have the permitting authorities post all permitting actions on their website.) 

The FLMs must become more aware and assertive of their rights in the NSR process. As long as 

we allow those rights to be ignored, we are short-changing our primary stakeholders, the citizens 

of the US who value their national parks, refuges, and wilderness areas. 

rt 
P.16 

Case Examples 

ACE fDEVA/CA)--permit modification for CFB boiler. We may be at fault for missing the 

public notice and failing to comment to EPA. EPA may have unwisely accepted the argument 

that actual emissions will not increase and should have required incorporation of verification into 

the permit. We need more information on this one. 

Alabama Power—Theodore Pit (BRET/AL)—Alabama Power proposed a 170 MW gas-fired 

combustion turbine, duct burner, and a 40 MW heat recovery steam generator to be controlled to 

3.5 ppm NOx. We agreed that this represents BACT. 

Androscoggin Energy (ACAD/MaineV-three 50 MW gas/oil combined cycle turbines (CCT) 

with dry low-NOx (DLN) combustors and SCR. Proposed NOx limits are 6-9 ppm (gas, 

witiiout and with duct burners, and 42 ppm on oil. We noted errors in the BACT analysis (e.g., 

use of incremental rather than average cost, 10% interest rate), raised questions about 

undocumented costs, and recommended use of SCR and lower NO limits. Although we do not 

have a response from Maine to our comments, the final permit did result in a NOx limit that fell 

between our recommended value and that originally proposed. 

Maine refused to require a regional haze analysis until FLAG reaches a conclusion and 

nationwide rules are promulgated. The applicant, fearing an appeal, conducted the regional haze 

analysis anyway. Since the haze analysis was dated 3/26/98 and the permit was issued 3/31/98, 

Maine obviously did not allow us the 60-day review we are entitled to. 

Bayer Corp. (CARO/SO—Baver is proposing to add a new gas/oil boiler to take on the load 

previously carried by two old 160 mmBtu/hr (each) gas and #6 oil-fired boilers. The new boiler 

would use Low-NOx burners and Flue Gas Recirculation, and bum 0.05% sulfur oil as backup; 

this represents BACT for this type of boiler. Even though the new boiler could operate at a 

. higher firing rate than typically experienced by the combined old boilers (about 120 mmBtu/hr 

total), DHEC believes that they can prevent unpermitted "extra" use by requiring that any new 

steam using equipment be evaluated for its effect on boiler emissions. The benefit to Bayer is a 

boiler that is more reliable, efficient, and economical; die benefit to the environment is a cleaner 

boiler. • 

The problem is that DHEC based its netting calculations on a comparison of past potential 

emissions (instead of the average of the last two years' actual emissions) to future potential 

emissions. Although I have not been able to find emissions data for this plant, I suspect that an 

acrual-to-potential emissions comparison would trigger PSD. We advised DHEC that, although 

we have some concerns about the way the netting calculations were performed, we agree with the 

overall goals of the project to replace two relatively dirty old boilers with a clean, new unit. We 

also stressed that DHEC insure that any additional equipment with a steam demand is evaluated 

for its impact upon emissions and air quality. EPA R-IV does not now review minor source 

netting applications, so they would not be involved in this anyway. 

/5 
P.17 

BP Oil (BRET/LAI-increase boiler capacity from 250 to 430 mmBtu/hr. The applicant has 

employed a unique strategy by confining its review of other BACT deterrninations to only EPA 

Region VI, or if necessary, to only Louisiana. The applicant has even further limited the scope of 

its BACT review by dismissing SCR on the basis that it is only used in ozone non-attainment 

areas. 

In its submittal dated 5/26/98, the applicant dismissed Selective Non-Catalytic Reduction 

(SNCR) on the grounds that it cannot operate at the boiler exhaust temperature of 650 F. In its 

8/31/98 submittal, BP has corrected its SCR cost estimate to exactly conform to ours with one 

exception. BP rejects SCR because it claims that SCR would have to be placed after the boiler 

economizer and that the normal economizer outlet temperature would be too low. In order to 

obtain the necessary SCR operating temperature (500-750 F), BP contends that the efficiency of 

the economizer would have to be reduced, thus incurring a $565,000 annual "fuel penalty." The 

result of this fuel penalty is a $5600 cost per ton of NOx removed. The fuel penalty included in 

BP's cost estimates in not justified and BP's cost estimates used to dismiss SCR as economically 

infeasible are therefore overestimated. Without the fuel penalty, SCR is technically and 

economically feasible and should be required as BACT. 

Calpine— South Point (GRCA/AZV- Calpine proposed gas-only firing and Dry Low-NOx 

combustors with Selective Catalytic Reduction for the 500 MW combined cycle turbines at its 

South Point Plant. We agreed that the target NOx emission limit of 4.5 ppm represents BACT for 

this application. 

Cardinal Glass (SHEN/VAV-600-ton/dav flat glass plant. Although Cardinal operates two 

plants in Wisconsin where it uses dry scrubbers and electrostatic precipitators to control S02 and 

PM, it proposed to locate within 30 km of SHEN without either of these control technologies. 

Cardinal and VaDEQ justified this approach on the basis that the last three PSD permits issued 

(by Iowa, Kentucky, and New York) for similar facilities did not require such controls and each 

permit was "approved" by the EPA regional offices. (Cardinal did propose a new NOx control 

technology, the Pilkington 3R Process that had been required by Kentucky and New York; Iowa 

required SNCR.) Once such a precedent of $0/ton for controlling S02 and PM had been allowed 

by EPA, even though VA performed the best cost/benefit analyses of any I have reviewed in the 

past eight months, VA inevitably concluded that any expense was excessive when measured ' 

against the "no-control" actions in other states. The plant eventually withdrew its application 

when confronted by public opposition to locating the plant in an environmentally sensitive area 

with substandard pollution control technology. 

From a procedural standpoint, VA handled the Cardinal application better than most states, 

although it should have re-set our 60-day review "clock" when it was discovered that Cardinal 

had committed major errors in its visibility modeling. The problem with the Cardinal application 

resulted from the creation of a "backsliding bandwagon" effect that was allowed to gain 

momentum when the EPA regional offices responsible for reviewing PSD permits in their 

respective states allowed the permits to stand despite expressing serious concerns about the lack 

of S02 and PM controls. EPA regional staff contacted while reviewing this application 
P.18 

expressed frustration over these outcomes, but justified them with the refrain that these were the 

"states calls." 

Cardinal subsequently moved its application to North Carolina, where it again proposed no S02 

or PM controls, and somewhat higher NOx emissions. It is our understanding that NC intends to 

permit these emissions. DOI did not comment due to the distance of the proposed plant from its 

Class I areas. 

Cargill Fertilizer-Bartow Pit (CHAS/FLV-Cargill proposed to increase the MAP/DAP 

capacity of its Bartow fertilizer plant #3 from 2640 TPD to 3000 TPD. A PSD-significant 

emissions increase would occur for PM and F. Cargill would replace or upgrade many of the 

emission control systems, and has proposed that its PM limit be reduced. 

Cargill has provided an adequate explanation of which parts of the plant and which pollutants are 

effected by the modification and subject to PSD. Cargill's proposed emission limits are based 

upon the expected performance of the upgraded control equipment and are consistent with the 

0.19 lb PM/T phosphate and 0.0417 lb F/T limits required by otiier permits issued by FDEP. 

Those limits represent BACT for this project.. 

Cargill Fertilizer—Riverview Pit (CHAS/FLV-The two main issues to be addressed in die 

BACT review were the controls for S02 and sulfuric acid mist (SAM) at the modified Ul 

sulfuric acid plant. S02: Cargill did not perform any demonstration of the economic infeasibility 

of potentially more efficient control technologies and could not, therefore, eliminate them from 

consideration. However, Cargill proposed a lower S02/ton limit than any found to date in the 

RACT/BACT/LAER Clearinghouse, a step in the right direction. Nevertheless, the limit 

proposed by Cargill is not as low as that proposed by one of its competitors. 

SAM: Cargill did not perform any demonstration of the economic infeasibility of potentially 

more efficient control technologies and cannot, therefore, eliminate them from consideration. 

Cargill's reliance upon an out-of-date and technically flawed NSPS was not sufficient to refute 

the evidence of its own test results that a much lower limit can be achieved by its current mist 

eliminators. It was recommended that, if SAM emissions from the Cargill #7 acid plant were 

limited to not more than 0.10 lb SAM/ton of acid produced (the highest rate recorded at this 

facility and likely to be met more than 99.9999% of the time), FWS would not challenge the lack 

of a proper BACT analysis for this permit application. When FDEP acted upon the FWS 

comments and issued the permit for 0.12 lb SAM/ton of acid produced, a 33% reduction from 

previous permits, we decided to accept that small victory. 

A few months later, Cargill proposed to expand its monoammonium phosphate (MAP) plant by 

requesting that its permit limits be revised to reflect greater production and actual emissions. 

At the request of FWS, FDEP investigated whether both of the recent applications from Cargill 

should be combined and reviewed as one project, and the effects of these projects on other 

emission sources at the facility should be evaluated with respect to PSD applicability and 

impacts. Their conclusion was that the projects were separate, based on corporate records and 

ft 
P.19 

Cargill's continued need to buy sulfuric acid. 

FDEP also responded to FWS comments on control technology by requiring that Cargill meet 

lower emission limits than originally proposed. 

Casco Bay Energy (ACAD/ME Casco Bay Energy Company (CBEC) proposed to construct 

and operate a 520 MW combined cycle gas turbine (CCT) at Bangor-Hydro's E. M. Graham 

Station power plant in Veazie, Maine. CBEC proposed to use Dry Low-NOx Combustors 

(DLNC) and Selective Catalytic Reduction to reduce NOx emissions to 5 ppm to allow some 

margin for safety in day-to-day operation and for efficiency losses due to aging of the catalyst. 

CBEC has noted in their application that some vendors have been willing to guarantee 

achievement of a 3.5-ppm limit during a one-time performance test, but suggest 5 ppm for 

long-term operation. Although NP§ concurred with CBEC, Maine DEP required the 3.5-ppm 

limit. 

CP&L—Lee (SWAN/NO-CP&L is requesting extension of a permit to construct and operate 

several large oil-fired combustion turbines in eastern NC. Not only has CP&L proposed the same 

high NOx emission limits allowed by the old permit, it has refused to provide FWS with the 

information it needs to determine what impacts the facility would have on AQRVs in the 

Swanquarter Class I area. NC supports CP&L on the basis that, as long as there is no increment 

violation, the applicant need conduct no further analysis. 

Chaparral Steel (SHEN/VAV-new electric arc steel mill. We noted errors in the BACT 

analysis (e.g., 10% interest rate), requested documentation of costs, and recommended that 

further S02 control options be explored for die EAF and NOx controls for the billet reheat 

furnace. (There was a reluctance to even consider control technology that had not been proven 

on an identical source.) VaDEQ responded to comments from NPS and EPA by requiring the 

additional analyses requested. 

Cogen Technologies-Linden Venture (BRIG/NJV-proposal to add a sixth CCT with DLN and 

SCR. Although we received a copy of an earlier application to modify the existing facility, we 

may not have received much information on the proposed new CCT. Although the applicant has 

proposed addition of SCR to meet LAER requirements and expedite permitting, NJDNR is 

considering eliminating the SCR requirement due to concerns about ammonia slip. We need to 

get more information of this one. 

Colorado Energy Management—Brush (ROMO/CO)- Colorado Energy Management (CEM) 

is requesting a permit to construct and operate two 1969 vintage gas-fired Westinghouse 251AA 

turbines rated at 25 MW each at its Brush, CO plant. Although we agreed that SCR is probably 

not BACT for such a small simple cycle peaking turbine, we disagreed when CEM dismissed 

Dry Low-NOx (DLN) combustors on the grounds that they could not be retrofitted to these 

ancient turbines without great expense. We suggested that CEM should not use turbines that 

cannot be controlled to today's environmental standards. In view of the predominance of DLN 

control technology for simple cycle turbines, and their capability to meet NOx emission limits in 

the 9-15 ppm range, CEM should be required to meet a limit in that range. 
P.20 

Colorado Springs Utilities—Nixon (GRSA7COV-Colorado Springs Utilities (CSU) is 

requesting that its permit to construct and operate a 110 MW turbine at its Ray D. Nixon Plant be 

modified to substitute two GE Frame 6B turbines rated at 33 MW each. Although we agreed with 

CSU that DLN technology probably represents BACT here, we disagreed with the emission 

limits proposed by CSU. CSU concluded that, because it could find no simple cycle turbines at 

some (undefined) higher altitude than sea level meeting a NOx limit lower than the 25 ppm 

proposed, BACT would default to its proposal. However, CSU provided no information as to the 

effect of altitude on the ability of modern gas turbines with DLN to meet lower NOx limits. 

In view of the predominance of DLN control technology for simple cycle turbines, and their 

capability to meet NOx emission limits in the 9-15 ppm range, CSU should be required to either 

meet a limit in that range or provide better documentation as to why it cannot 

Continental Lime (CARE/UT)—Continental has determined that no NOx controls are feasible 

for this new coal-fired lime kiln. NPS will likely comment that Continental should investigate 

the possibility of transferring SCR technology to this process by re-heating the baghouse exhaust 

using waste heat and treating the effluent with SCR. 

Duke Energy—New Smyrna (CHAS/FL)-Duke Energy (Duke) proposes to construct and 

operate a gas-fired 500-megawatt (MW) combined cycle turbine (CCT) in New Smyrna, Florida. 

Duke has proposed to meet NOx limits of 12 ppm by use of "advanced dry low-NOx 

combustors" to minimize the formation of NOx by premixing fuel and air prior to combustion, 

and by providing staged combustion to reduce flame temperatures. Duke has rejected the use of 

SCR on the grounds of economic infeasibility. The high cost of SCR ($6534/ton NOx removed) 

may be due to cost overestimates, performance underestimates, and calculation errors on the part 

of the applicant. However, without documentation to support many of the costs presented, it is 

impossible to determine why Duke's estimates are so much higher than for other similar 

• installations. 

Duke's proposal represents a step backward from the level of NOx control proposed by the 

majority of similar current competitors. Duke has not documented or justified the extraordinarily 

high control costs contained in its application. We believe that NOx can be controlled to a level 

of 2-3.5 ppm by addition of SCR and that the cost of such control would not exceed the $4000 

per ton typical of the industry. If Duke's costs really are exceptional, it must present more 

diorough evidence to support its claim. 

Farmland Hydro (CHAS/FLV-NPS believes that the PSD applicability determinations for two 

successive expansions at Farmland Hydro may not have been broad enough in that they did not 

evaluate the effects of the expansions on each other and on other related processes at the plant. 

In late 1997, Farmland Hydro (FH) submitted a PSD permit application to expand its sulfuric 

acid plant (SAP) production capacity. In early 1998, FH proposed to expand the utilization of its 

monoammonium phosphate (MAP) and diammonium phosphate (DAP) plant, which utilizes 

sulfuric acid from the expanded acid plant. In both applications, FH quantified only the direct 

emissions from the equipment to be modified and ignored any effects that increased throughputs 

1

 \°i 
P.21 

,. J 

would have on supporting and dependent operations. In our comments to FDEP, NPS advised 

that the applicant should quantify and add any increases in emissions of these pollutants from the 

existing facility to the quantities described by the applicant. NPS also pointed out deficiencies in 

the BACT analysis, including: lack of documentation of costs; dismissal of potential controls 

because they created a waste product; failure to consider more stringent controls proposed at 

other, similar facilities; and over-reliance on an out-dated and poorly developed NSPS. 

Fronterra Pwr fPAIS/TXV-Fronterra consists of two gas-fired 165-megawatt (MW) GE Frame 

7FA combustion turbines with two heat recovery steam generators and one steam turbine. 

Frontera proposed to meet a nitrogen oxides (NOx) limit of 15 parts per million (ppm) using 

Dry-Low-NOx (DLN) combustors, despite our experience over the past year that most new gas 

turbine facilities are including Selective Catalytic Reduction (SCR) for control of NOx. TNRCC 

rejected SCR on the premise that it would create adverse ammonia emissions and excessive 

costs. Our analyses indicated that SCR for NOx control was technically, economically, and 

environmentally feasible, and was therefore BACT. We encouraged TNRCC to reconsider the 

use of SCR for this application and for other facilities of this type. 

Globe Metallurgical (CRLA/OR)-new electric arc furnace for production of silicon metal. PM 

control limits were based on an ancient NSPS and not reflective of current capabilities. 

Griffith Energy (GRCA/AZ)-We commended Griffith for its choice of gas-only firing and Dry 

Low-NOx combustors with Selective Catalytic Reduction for the proposed 650 MW combined 

cycle turbines at its Kingman plant. We agreed that the target NOx emission limit of 4.5 ppm 

represents BACT for this application. 

Hoeganaes (MACA/TNV- Hoeganaes proposed to construct and operate a new 

42.6-ton-per-hour ladle furnace and rotary dryer. Emission controls on the electric arc ladle 

furnace and rotary dryer would consist of fabric filters. The use of enclosure and a baghouse for 

control of particulate emissions from the electric arc furnace (EAF) represents BACT for 

particulate matter. However, we were concerned that the use of side-draft hoods for fume capture 

is not as effective as direct shell evacuation which captures all emissions during melting. 

Furthermore, we suggested diat the baghouse could be more efficient and meet the much lower 

limits that are found in the RACT/BACT/LAER Clearinghouse for recent EAF permits. For 

example, Chaparral Steel in Virginia recently received a permit limiting its EAF to 0.0018 

gr/dscf. 

IMC-Agrico (CHAS/FLV-addition of a phosphate-based animal feed kiln. NPS recommended 

addition of a permit limit to verify the applicant's contention that the expansion would not result 

in increased emissions from the rest of this major source. We also recommended fluoride 

controls similar to that achieved at fertilizer plants. 

Kissimmee— Cane Island (CHAS/FL1-- We commended Kissimmee Utility Authority (KUA) 

for proposing installation of a new, efficient 250 MW Combined Cycle Turbine (CCT), but were 

disappointed that the degree of NOx control proposed lags well behind that which we see 

elsewhere around the U.S. Our own compilation of recent permit applications shows a clear trend 
P.22 

toward installation of SCR on these facilities. Unless KUA can show some compelling reason 

why it cannot achieve a similar level of control, we recommended that it revise its application to 

include SCR and meet a NOx limit of 3.5-5.0 ppm. 

KUA received a permit from FDEP for installation of a new 40 MW simple cycle turbine with 

NOx to be controlled to 15 ppm by Dry Lox-NOx (DLN) combustors. However, KUA has 

experienced difficulties in meeting that limit and has requested until 1/1/2000 to do so. Because 

of the peaking nature of this unit, it is likely that DLN represents BACT, so the only question is 

the emission limit achievable by this technology. In view the difficulties experienced by KUA in 

meeting the 15-ppm limit for this aero-derivative turbine, it seems reasonable to allow extra time 

to bring this unit into compliance with that limit. 

Lakeland Mcintosh fCHAS/FLV-addition of a 250-megawatt (MW) simple cycle gas and oil 

fired turbine facility to its existing Mcintosh Power Plant. Despite at least 18 examples of gas 

turbines permitted to startup now with NO limits in the 9-15 ppmvd range and using dry low NO 

combustors, Lakeland is still proposing to meet a 9-ppm NOx limit within five years of startup. 

Both FDEP and NSPS have suggested that Lakeland opt for a more efficient combined cycle 

turbine (CCT) that would be more efficient and less polluting; Lakeland may convert to CCT in 

the future. Lakeland's economic analysis also contained numerous examples of unsupported or 

inflated costs, short equipment lives, and high (10%) interest rates. FDEP eventually issued a 

permit requiring that the plant either meet 9 ppm in the simple cycle mode or 7.5 ppm as a CCT. 

La Paloma Generating (JOTR/CA)—La Paloma proposed to construct four 262 MW gas-fired 

combined cycle turbine units with NOx controlled to 3.5 ppm by SCR. Due to the good controls 

and long distance from a DOI unit, we did not comment. 

Mississippi Phosphate (BRET/MS)-proposed to increase the combined production of its 

sulfuric acid plants. Although the applicant agreed that PSD was triggered for sulfuric acid mist, 

NPS raised concerns that the extra 39.9 TPY of S02 could also trigger PSD for that pollutant if 

. other S02 sources at the plant increased emissions as a result of the expansion. MDEQ's 

response was that a policy decision had been made not to consider this possibility. Later, NPS 

advised MDEQ that test results in FL had found that S02 could also be emitted from the catalyst 

used in die sulfuric acid plant and that these extra emissions could trigger PSD—no response 

from MDEQ. NPS advised MDEQ that the sulfuric acid mist eliminators proposed by the 

applicant were not really the "high efficiency" units claimed, and that better mist eliminators 

were already in use elsewhere at tiiis plant and others—MDEQ's draft permit continued to rely on 

die NSPS and permits in otiier states. 

Miss Pwr—Daniels (BRET/MD-- We commended Mississippi Power for its choice of gas-only 

firing and Dry Low-NOx combustors with Selective Catalytic Reduction for the proposed 

combined cycle turbines at its Daniels Plant. We agreed that the target NOx emission limit of 3.5 

ppm represented BACT for this application. 

Northwest Regional Power Facility (MORAAVAV-838 MW combined cycle turbine (CCT) 

facility. Northwest Regional Power Facility (NRPF) proposed to meet a nitrogen oxides (NO) 

limit of 9 parts per million (ppm) using Dry-Low-NOx (DLN) combustors, and claimed that the 
P.23 

addition of Selective Catalytic Reduction (SCR) to further reduce NOx emissions would create 

adverse ammonia emissions and excessive costs. Washington Department of Ecology agreed 

with that position. However, the state may have incorrectly assumed that a part per million of 

NOx and ammonia were equivalent, because it never actually calculated the effect on emissions 

of adding SCR. NPS estimated that NOx reductions would outweigh ammonia emissions by a 

factor of 2-4 times. NRFP's economic analysis of adding SCR also contained numerous 

examples of unsupported or inflated costs, short equipment lives, and high (10%) interest rates. 

Nucor Steel (SWAN/NCV- Nucor is proposing to construct and operate a new 250-ton-per-hour 

steel mill in eastern NC. Emission controls on the electric arc and ladle furnaces would consist of 

fabric filters. NOx emissions from the billet reheat furnace (BRF) would be reduced through use 

of Low-NOx burners. Nucor has proposed to control NOx emissions to 0.21 Ib/mmBtu by use of 

Low-NOx burners. However, as Nucor noted in its BACT analysis, a permit issued by Indiana 

DEM to Beta Steel requires use of Selective Catalytic Reduction (SCR). Nucor has attempted to 

dismiss SCR on the basis that the $2700 cost of removing a ton of NOx is economically 

prohibitive. Not only would $2700 per ton be considered acceptable in every state in which we 

are aware of a cost threshold, it is also inflated and poorly documented. 

Nucor Steel (CARO/SO-proposed addition of new milling operations. When we suggested to 

SC that, unless the proposed addition is considered part of the recently permitted main mill, 

some pollutants would escape PSD review, SC construed our comments to mean that they 

thought we were concerned that this application was completely circumventing PSD. Although 

we tried to explain to SC that, by dividing a project into small parts, some pollutants that may be 

emitted in significant amounts could drop out of PSD review while others stayed, they never 

quite grasped the concept. The economic analysis was flawed in that it relied upon 

unsubstantiated and inflated costs and interest rates. We have not received any response from SC 

regarding our BACT comments. 

Orange Cogeneration—Bartow (CHAS/FL1- Orange Cogen (Orange) received a permit from 

FDEP for installation of a two new 41 MW Combined Cycle Turbines (CCT) with NOx to be 

controlled to 15 ppm by Dry Lox-NOx (DLN) combustors. However, Orange has experienced 

difficulties in meeting that limit and has requested until 1/1/2000 to do so. 

Altiiough FDEP does not have the authority to revisit BACT in this case, it is my understanding 

that EPA policy demands that any revision and/or extension of a PSD permit must consider 

possible changes in BACT subsequent to the issuance of the original permit. In this case, Orange 

should be required to perform a new BACT analysis, with particular attention to the feasibility of 

installing Selective Catalytic Reduction (SCR) on this CCT. FDEP implied that EPA 

intervention would be given serious consideration. 

Pglnctfo Lime (CARO/SQ--proposal to construct a new lime calcining kiln. SC repeatedly 

asserted that, if a control technology had not been previously required on this type of source, it 

need not be considered. The applicant continued to argue that potential controls were either 

technically or economically infeasible, but did not provide an economic analysis to support the 

latter contention. SC cited EPA BACT determinations at other lime plants, and a letter from 
EPA approving the proposed BACT as justification. Our extensive arguments for technical 

feasibility were never included in the hearing record, nor were there any responses. 

Pinev Point Phosphates fCHAS/FLV-proposal to reconstruct a sulfuric acid plant at a 

phosphate fertilizer manufacturing facility. Although a lawsuit by a local government finally 

forced the plant to accept a lower S02 limit, information provided by FWS appeared to have 

played a major role in supporting that lower limit. FDEP cited our evidence that modem mist 

eliminators are capable of reducing sulfuric acid emissions well below the 1978 NSPS limit and 

required their use, but did not reflect those capabilities in its final permit. The economic analysis 

was flawed in that it relied upon unsubstantiated and inflated costs and interest rates. 

Proctor & Gamble fMING/MOI-new papermaking machine and boilers. MDNR essentially 

approved the applicant's arguments with little independent review until an initial round of 

comments were submitted by NPS. At the point, MDNR appeared to go into a mode of trying to 

justify its initial determination, despite wild variations in the arguments submitted by the 

applicant. 

Ravonier (OKEF/FD-- Rayonier requested a permit to install and operate a temporary boiler to 

be fired on #6 fuel oil while each of the two main boilers is taken down for repairs. Emission 

increases over normal rates during the repair period would be about 277 tons S02 and 81 tons 

NOx. Because of the temporary nature of this boiler, add-on control equipment is not likely to be 

economically feasible. Furthermore, Rayonier has committed to tying the exhaust from the 

temporary boiler into their existing venturi S02 scrubber so that S02 emissions will be reduced 

by over 90%. This tends to make uneconomical any attempts to reduce S02 emissions further. 

Although the temporary boiler proposed by Rayonier is equipped with Low-NOx Burners and 

Flue Gas Recirculation, the 0.425 lb NOx/mmBtu emission rate is more than double that typical 

for this size boiler and probably reflects the quarter-century age of the unit. 

Red Hills Power Project fNATR/MSV-proposed large lignite-fired CFB boiler. MDEQ says it 

has made a policy decision to permit tiie boiler at 0.20 lb NOx/mmBtu and without addition of 

SNCR. Since the proposed revisions to NSPS Subpart Da are already effective and require a 

NOx limit no greater than 0.15 Ib/mmBtu, MDEQ has made a policy decision to allow the higher 

limit and planned to discuss the matter with EPA R-IV. MDEQ claims that SNCR, which is 

typically required for new CFB boilers, is not feasible for this boiler because of its size and 

low-quality fuel. 

Choctaw Generation Inc. is proposing the construction of the Red Hills Power Generation 

Facility (RHPGF) in Choctaw County, Mississippi. The project consists of two 220 megawatt 

(MW) circulating fluidized-bed (CFB) coal/wood-fired boilers and two 335 million Btu per hour 

(mmBtu/hr) auxiliary natural gas-fired boilers in central Mississippi. Emissions of Particulate 

Matter (PM), Sulfur Dioxide (S02), Carbon Monoxide (CO), Volatile Organic Compounds 

(VOC), Fluorides (F), Sulfuric Acid Mist (SAM), and Nitrogen Oxides (NOx) would be in 

sufficient quantities to trigger application of federal regulations for the Prevention of Significant 

Deterioration (PSD) of air quality and thus the requirement that those emissions be controlled 

using Best Available Control Technology (BACT). S02 and NOx emissions will be controlled 

by the inherently low-polluting nature of the fluidized bed combustion process. Particulate will 

£3 
P.25 

be controlled by a baghouse. NOx emissions are expected to result in a 2-6 ppb increase in ozone 

concentrations within 200 km of the plant. 

NPS has obtained information from Jacksonville (FL) Electric Authority (JEA) regarding a 

proposed 300 MW coal/petroleum coke-fired CFB boiler. Emissions from that boiler would be 

controlled by Selective Non-Catalytic Reduction (SNCR) of NOx, Lime Spray Drying (LSD) for 

S02, and a fabric filter for PM. Initial emission limits are expected to be no higher than 0.01 lb 

NOx/mmBtu, 0.17 lb S02/mmBtu, and 0.017 lb PM/mmBtu. 

S02 Controls are proposed to be the inherent scrubbing ability of the limestone component of 

the fluidized bed. Although additional S02 removal could be achieved by increasing the amount 

of limestone injected into the fluidized bed, RHPGF has determined that the optimum level of 

limestone injection would achieve 90% S02 removal and meet an emission limit of 0.25 

Ib/mmBtu. S02 emissions would be 5424 TPY. 

RHPGF evaluated the effects of adding a Lime Spray Dryer (LSD) as an alternative to CFB to 

control S02 emissions. However, RHPGF did not explore the possibility of adding a LSD to the 

CFB, as is being proposed by JEA (see discussion above). When requests by NPS to RHPGF to 

add this analyses were rejected by the applicant on the grounds that the expense would outweigh 

the benefits, NPS conducted its own analysis using techniques developed by EPA in its Control 

Technology Cost Manual. Although hampered by the lack of cost data specific to this project, 

our analysis determined that an additional 92% S02 removal would reduce emissions by over 

5000 TPY at an annual cost of about $11 million; the resulting cost per ton of S02 removed 

would be about $2200, well within the ranges of reasonable costs seen in other projects. 

NPS has significant disagreements with RHPGF with respect to its LSD operating and 

annualized cost calculations. RHPGF should obtain vendor quotes on the capital and operating 

costs of a polishing scrubber for this application. 

Finally, the addition of LSD would also provide control of the fluorides and chlorides cited by 

RHPGF as detrimental factors for the use of additional NOx controls (see NOx discussion 

below), as well as reducing their emissions and environmental impact 

NOx Controls proposed by RHPGF are limited to the low-temperature combustion characteristic 

of CFB boilers and the resulting low NOx generation rates. Although additional NOx removal 

could be achieved by adding specific NOx controls, RHPGF has decided that they are not 

feasible for this application. The RHPGF proposal would achieve an emission limit of 0.20 

Ib/mmBtu. NOx emissions would be 6470 TPY. 

Although the proposed NSPS has not yet been promulgated, it will apply in its final form to 

"those electric utility and industrial steam generating units for which construction, modification, 

or reconstruction is commenced after July 9,1997." Therefore, RHPGF must comply with the 

final, promulgated version of this standard. Based on conversations with Mr. James Eddinger, 

(Combustion Group, Emission Standards Division, U.S. Environmental Protection Agency, 

Research Triangle Park, North Carolina), he does not expect the final version to change 
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significantly. If that is the case, RHPGF will be required to meet a NOx emission limit 

equivalent to 0.15 Ib/mmBtu heat input, instead of the 0.20 Ib/mmBtu limit proposed by RHPGF. 

Furthermore, because BACT may represent an emission limit even lower than the NSPS, the 

appropriate NOx limit for RHPGF may lower still. 

By proceeding with its application at this time, RHPGF is placing itself in an area of unknown 

emission requirements. Rather than accept an emission limit that would represent the most 

stringent likely outcome of the proposed NSPS, it has chosen a limit that would be valid only if 

the proposed NSPS is promulgated in a relaxed form and BACT is determined to be equivalent 

to that relaxed NSPS. RHPGF has reached an agreement with Mississippi DEQ and EPA Region 

IV that would allow it to receive a permit at 0.20 lb NOx/mmBtu, with tiie condition that it meet 

a lower limit if promulgated through the NSPS. (NPS questions how these agencies determined 

that BACT would be equal to the NSPS in this case, in that BACT is to represent a case-by-case 

determination and is often more stringent than the NSPS.) 

RHPGF also made arguments that more advanced control technologies might make the project 

unaffordable, and cited a letter from EPA Region IV to North Carolina as an example of an 

objection based on affordability. However, according to EPA's New Source review Workshop 

Manual, affordability is not a valid consideration. 

RHPGF also rejected SCR on the grounds that it was too expensive at about $8300 per ton of 

NOx removed and technically difficult. However, the technical difficulties of operating SCR 

downstream of a CFB with its exceptionally high particulate loading can be overcome by 

installing dust removal equipment between the boiler and the SCR system. Two possible 

approaches are to either install a high temperature fabric filter or mechanical collectors, screens, 

and a dummy catalyst ahead of the SCR; RHPGF chose the latter approach for its cost analysis. 

(NPS believes that RHPGF should have also evaluated the fabric filter alternative. Because the 

RHPGF cost analysis was very sketchy, NPS attempted to use the EPA Control Cost Manual 

. approach using both Total Capital Investment (TCI) estimates from RHPGF and from the EPA 

IAPCS5a cost model. Using RHPGF's $50 million TCI estimate, its catalyst replacement cost of 

70% of TCI (much higher than the 40%-60% of Capital Cost that we usually see), and two-year 

catalyst life (compared to three-five years in other applications), assuming 82% NOx removal 

(from the IAPCS5a model prediction), including other operating costs, and using a 7% interest 

rate to calculate the Capital Recovery Factor, NPS estimates that an additional 5400 TPY of NOx 

could be removed at a cost of about $18 million annually; the cost per ton of NOx removed 

would be about $3300, within the range accepted by many states. When NPS used the IAPCS5a 

model to estimate TCI, we obtained a TCI of $13 million, and an annual cost of $11 million to 

remove the same 5400 tons of NOx. The NPS cost benefit ratio was about $1000 per ton. 

NPS believes that RHPGF should have evaluated at least one more NOx control option. Because 

it has apreed to meet a NOx limit as low as the 0.15 proposed by EPA in its NSPS if that limit is 

ultimately promulgated, RHPGF has effectively admitted that such a lower limit is feasible. (In 

Preag, Germany, a lignite-fired boiler is demonstrating NOx emissions 0.1-0.137 Ib/mmBtu. 

According to the boiler vendor, a similar boiler in Provence, France, is emitting less 

NOx/mmBtu than proposed for RHGF, and RHGF NOx emissions should be even lower. Our 

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P.27 

understanding is that RHPGF would probably blend woodwaste with the lignite to achieve tins 

lower limit.) So, because a proper BACT analysis must evaluate all technically feasible control 

technologies that are capable of achieving a lower emission rate, and because RHPGF has 

already agreed to meet such a lower rate if required to do so, RHPGF should justify why it 

cannot meet a 0.15 lb NOx/mmBtu limit immediately rather than as a future contingency. 

Republic Steel (GRSM/TNV-new mini-mill. The applicant has, when it serves to make the 

addition of S02 and NOx controls more difficult, chosen to combine gas streams from the 

electric arc furnace and ladle melting furnace, even though each has its own baghouse. The 

economic analysis is completely without documentation and the interest rate is inflated. 

Roanoke Electric Steel (SHEN/VAWRoanoke Electric Steel's (RES) proposed to modify their 

steel mill in Roanoke by increasing throughput of its #5 Electric Arc Furnace (EAF) and #5 

Ladle Metallurgical Station (LMS) plus adding a #2 Billet Reheat Furnace (BRF). Roanoke 

Electric Steel provided an excellent analysis of the cost of adding Selective Catalytic Reduction 

(SCR) to control nitrogen oxide (NOx) emissions from the #2 BRF. All cost estimates were very 

well documented and the methodology and assumptions used were quite reasonable and easy to 

follow. We agreed that, for this situation, SCR was not economically feasible 

In performing its analysis of potential control technologies for the BRF, RES did not initially 

include an evaluation of the feasibility of using Selective Non-Catalytic Reduction (SNCR) for 

NOx control. We encouraged DEQ to investigate the economic and environmental feasibility of 

SNCR for the BRF. 

Roanoke Electric Steel also provided an excellent analysis of the cost of changing filter media to 

control particulate emissions from the 45 EAF. All cost estimates are well documented and the 

methodology and assumptions used are reasonable and easy to follow. We agreed that 

conversion to Teflon filter bags was not economically feasible. 

Santa Teresa Pwr (CACA/NMV-Dvnegv Power Corp. (Dynegy) proposed to construct and 

operate two natural gas-fired 220 Megawatt (MW) combined cycle turbines (CCT) in Santa 

Teresa, New Mexico. Dynegy proposed to meet a nitrogen oxides (NOx) limit of 15 parts per 

million (ppm) using Dry-Low-NOx (DLN) combustors, despite our experience over the past year 

that most new gas turbine facilities are including Selective Catalytic Reduction (SCR) for control 

of NOx. Dynegy has rejected SCR on the premise that it would create excessive costs and create 

the potential for ammonia spills. However, we believe that this cost estimate is inflated and 

unsupported. 

Steelcase Furniture (GRSM/NQ-proposal to add a new furniture finishing line. The state's 

review was a verbatim restatement of the applicant's BACT analysis. Although NPS provided 

examples of low-solvent coating technologies in use on furniture of even higher quality than 

made by Steelcase, our examples were rejected because of unsubstantiated "quality concerns". 

TVA-Bellefonte (GRSM/TNV-TVA plans to construct four 85 MW simple cycle turbines to 

supply peaking power. NOx would be controlled to 15 ppm by Dry Low-NOx (DLN) 

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combustors. In view of the application by Oleander Power to meet a 9 ppm NOx limit on its five 

190 MW simple cycle peaking units, TVA should explain why they cannot do as well. 

TVA—Gallatin flylACA/TNWTVA plans to construct four 85 MW simple cycle turbines to 

supply peaking power. NOx would be controlled to 15 ppm by Dry Low-NOx (DLN) 

combustors. In view of the application by Oleander Power to meet a 9 ppm NOx limit on its five 

190 MW simple cycle peaking units, TVA should explain why they cannot do as well. 

TX-NM Pwr—Lordsburg f/TXW Texas-New Mexico Power Company (TNMP) proposed to 

operate two aero-derivative 40-megawatt (MW) gas/#2 oil-fired combined cycle turbines (CCT) 

at Lordsburg, NM. Although the applicant proposed the use of water injection and Selective 

Catalytic Reduction (SCR), the proposed NOx emission concentrations are 15 and 25 ppm 

respectively. These outlet concentrations are significantly higher than current emission limits for 

CCTs. The applicant justified the higher emissions on the grounds that low-NOx burners are not 

compatible with the aero-derivative type turbines proposed at Lordsburg 

Even allowing for the inherent difficulty in controlling the aero-derivative turbines proposed, we 

believe that the SCR proposed can achieve lower emission limits. For example, if emissions from 

gas firing resulting from water injection only are 25 ppm as stated in Table IV-4 of the 

application, an 80% efficient SCR system downstream should lower outlet emissions to 5 ppm, 

putting this project into the range of emissions of most current CCT projects. 

9-lr