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BEFORE THE ADMINISTRATOR

UNITED STATES ENVIRONMENTAL PROTECTION AGENCY

RIN 2060-A012

EPA Docket No. OAR-2009-0119

In the Matter of the Final Rule:

Standards of Performance for New 

Stationary Sources and Emission Guidelines 

for Existing Sources: Commercial and 

Industrial Solid Waste Incineration Units

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PETITION FOR RECONSIDERATION

Pursuant to Section 307(d)(7)(B) of the Clean Air Act, 42 U.S.C. § 7607(d)(7)(B), the 

American Chemistry Council (―ACC‖) hereby petitions the Administrator of the United States 

Environmental Protection Agency (―EPA‖) to reconsider portions of the final rule Standards of 

Performance for New Stationary Sources and Emission Guidelines for Existing Sources: 

Commercial and Industrial Solid Waste Incineration Units (―Final Rule‖), published in the 

Federal Register at 76 Fed. Reg. 15,704 (Mar. 21, 2011). As set forth in detail below, ACC 

respectfully requests that EPA:

 Provide notice and an opportunity to comment on the affirmative defense provision 

for malfunctions 

 Promulgate work practice standards for periods of startup and shutdown for 

CISWI units, as it did for both major and area source boilers in those respective 

rules

 Reconsider the CISWI emissions limits because of significant concerns ACC raised,

and EPA ignored, with the quality of the data used to set those limits 

 Set separate emission standards for PM, Hg, Pb, Cd and HCl from coal-fired units,

and biomass units; these units should not be grouped in the same subcategory for 

these specific emission standards

 Reconsider and solicit comments on the O2 monitoring requirements

 Revise CEMS provisions to adequately provide for existing dilution-extraction SO2

and CO CEMS to be used

 Reconsider and take comment on the elimination of provisions that allow missing 

CEMS data

 Reduce excessive performance testing requirements to make the CISWI rule 

consistent with the more reasonable testing requirements of other rules
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 Reconsider the deletion of the definition of “solid waste” and “contained gaseous 

material” in the Final Rule, which could result in numerous process and other gases 

being considered “solid waste” and regulated under CISWI

 Clarify that operating parameter limits do not apply during subsequent 

performance pretesting and testing

 Include a compliance option that allows the development of a feed stream analysis 

for fuel based pollutants (metals) that are not destroyed

 Provide the same allowance for varying OPLs with varying operating load in the 

CISWI Rule that was finalized in the major source boiler rule

 Reconsider the use of charge rate as an operating limit for energy recovery units

 Establish monitoring requirements for dry scrubbers in the rule and not by petition

 Increase the averaging time for parametric monitoring from 3 hours to 24 hours 

and exclude periods of startup from the averages to allow startup of ESPs without 

causing a deviation

 Allow emissions averaging in the CISWI rule similar to what is allowed in the 

major source boiler rule

 Set parametric monitoring ranges based on performance testing and allow use of 

supplemental information along with the test data

In addition, ACC has included a number of issues that it believes require technical 

correction and/or clarification at the end of this petition for reconsideration.

I. THE PETITIONERS

ACC is a not-for-profit trade association that participates on its members‘ behalf in 

administrative proceedings and in litigation arising from those proceedings. ACC represents the 

leading companies engaged in the business of chemistry. These companies rely in part on the 

use of commercial and industrial solid waste incinerators that are subject to the Final Rule.

II. GROUNDS FOR RECONSIDERATION

Pursuant to section 307(d)(7)(B) of the Clean Air Act (CAA), if a petitioner shows ―that 

it was impracticable to raise [its] objection within [the period for public comment] or if the 

grounds for such objection arose after the period for public comment . . . and if such objection is 

of central relevance to the outcome of the rule, the Administrator shall convene a proceeding for 

reconsideration of the rule.‖ 42 U.S.C. § 7607(d)(7)(B). There are a number of issues for which 

ACC seeks reconsideration that stem from the fact that, as EPA has conceded in public 

statements and court filings, it did not have adequate time to consider fully the thousands of 

comments it received on the suite of boiler rules. Due to that lack of time, EPA finalized similar 
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provisions one way in the major source boiler rule1, and a different way in the CISWI final rule, 

without explaining why it did so. By failing to provide a rational basis for finalizing similar 

provisions differently or otherwise distinguishing the provisions, EPA provided an inadequate 

response to comment leaving these provisions vulnerable to a legal challenge that they are 

arbitrary and capricious. Because we could not have known that EPA would take such different 

approaches in the final rules, we believe that the finalization of certain provisions (which we 

favor) in the major source boiler rule supports a reconsideration of that similar provision in the 

CISWI rule. As detailed below, each of the specific provisions for which ACC seeks 

reconsideration meets these requirements.

III. SPECIFIC PROVISIONS FOR WHICH RECONSIDERATION IS SOUGHT

1. EPA should provide notice and an opportunity to comment on the affirmative 

defense provisions for malfunctions.

The 2000 CISWI rule provided that the standards did not apply during periods of startup, 

shutdown and malfunction. 2 65 Fed. Reg. at 75355 (Dec. 1, 2000). In the revised CISWI rule,

EPA proposed and then finalized precisely the opposite approach -- the emission limits and 

operating requirements apply at all times. See, §§ 60.2105 and 60.2670. 

Moreover, for malfunctions, EPA rejected ACC‘s recommendation for work practice 

standards and instead promulgated an entirely new provision that allows the source to assert an 

affirmative defense if it exceeds a numerical emission limit during a malfunction event as long as 

several conditions are met. See, §§ 60.2120 and 60.2685. This new provision is not a ―logical 

outgrowth‖ of the proposal because it was not a part of the proposal, so ACC did not have an 

opportunity to raise the issues associated with the affirmative defense discussed below. EPA 

stated in its March 21, 2011 Notice of Reconsideration that it intends to reconsider the 

affirmative defense for malfunction events for major and area source boilers and for CISWI units 

and we strongly support that action. 76 Fed. Reg. 15266, 15267 (March 21, 2011).

EPA should, however, reconsider not just the affirmative defense as promulgated. 

Rather, EPA should broaden its reconsideration to include the Agency‘s approach to malfunction 

in general. Accordingly, ACC recommends that EPA reconsider the following issues:

 EPA and case law has for decades recognized that all technologies fail at some 

point; therefore EPA must provide a safety valve for technology-based standards 

during such time periods, and this is consistent with the D.C. Circuit‘s Sierra 

Club v. EPA, 551 F.3d 1019 (D.C. Cir. 2008), cert. denied, 130 S.Ct. 1735 (2010) 

decision.

 

1 National Emission Standards for Hazardous Air Pollutants for Major Sources: Industrial, Commercial, and Institutional Boilers and 

Process Heaters, 76 Fed. Reg. 15608 (March 21, 2011) (hereinafter ―major source boiler rule‖).

2 We note that EPA is initiating reconsideration of this issue. National Emission Standards for Hazardous Air Pollutants; Notice of 

Reconsideration, 76 Fed. Reg. 15266, 15267 (Mar. 21, 2011) (to be codified at 40 C.F.R. Parts 60 & 63) (hereinafter Notice of Reconsideration). 

We support this reconsideration to the extent it is consistent with ACC‘s comments.
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 The Sierra Club decision should have no impact on the legality of source category 

specific SSM provisions for CISWI under Sections 111 and 129 of the Clean Air 

Act.

 EPA should promulgate work practice standards for malfunction periods, 

consistent with Sections 111, 42 U.S.C. § 7411, and 129, 42 U.S.C. § 7429, of the 

Clean Air Act and Sierra Club.

 EPA‘s affirmative defense is not a substitute for setting emission standards for 

periods of malfunction for many reasons:

o It is not clear where EPA finds the legal authority in the Clean Air Act for 

shifting the burden of proving (or disproving) the key elements of an 

alleged violation -- normally EPA would have this burden in an 

enforcement action.

o Being able to asset a defense is obviously not the same as complying with 

specific work practice standards that take into account the limitations of 

technology -- sources may have to conservatively report a violation or 

certify noncompliance until there has been an enforcement action in which 

the source has successfully asserted the defense. This is unacceptable.

o EPA limits the affirmative defense to ―civil penalties.‖ First, it is not clear 

what this means. Does it cover civil administrative penalties under CAA 

§ 113(d)? Does it cover noncompliance penalties under CAA § 120? 

How does the defense apply to state and local governments and citizen 

suits? Finally, EPA specifically states that the affirmative defense is not 

available for claims for injunctive relief. EPA does not provide a

rationale for not extending the defense to injunctive relief, and there is no 

apparent reason why it should be so limited.

 The affirmative defense establishes nine criteria (with some further subparts) that 

a source must satisfy in order to assert the defense, together with stringent 

notification requirements. ACC believes that many of these criteria are 

inappropriate or so vaguely worded that they will vitiate the use of the defense, 

and ACC will provide detailed discussion of the criteria in its comments on 

reconsideration. 

2. EPA should promulgate work practice standards for periods of startup and 

shutdown for CISWI units, as it did in the final rules for both major and area source 

boilers.

The proposed CISWI rule required compliance with emission limitations at all times, 

including during startup, shutdown and malfunction. ACC and others commented that EPA 

should instead set work practice standards for these time periods. See, ACC Comments at 24-25,

43-46. EPA rejected these comments, and finalized its proposal. EPA provided the rationale for 

its action in the preamble to the Final Rule as follows:
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We concluded that CISWI units would be able to meet the emissions limitations during 

periods of startup because most units used natural gas or clean distillate oil to start their 

incinerators and only add waste after the incinerator has reached combustion 

temperatures. Id. We proposed that emissions from burning natural gas or distillate fuel 

oil would generally be significantly lower than from burning solid waste. Id. We further 

proposed that emissions during shutdown would also be generally significantly lower 

because the waste would be almost fully combusted before the unit began shutting down. 

Id. We proposed that these factors, in conjunction with the variability built into the 

MACT standards and the longer averaging periods, meant that sources would be able to 

comply with the standards during periods of startup and shutdown. Id.

76 Fed. Reg. at 15737-38. 

EPA assumes that because CISWI units burn natural gas or distillate oil during periods of 

startup and shutdown (―SS‖) it is technically feasible for these units to meet the strict emissions 

standards established for periods of normal operation during startup and shutdown. This 

assumption is flawed for several reasons.

First, because CISWI units are burning fossil fuels during SS periods, they are no 

different than the combustion units covered by the major source and area source boiler rules.

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In 

both of those rules, EPA determined that it was not feasible to require stack testing during SS 

periods due to physical limitations and the short duration of those periods and therefore used its 

authority to require work practice standards (compliance with the manufacturer‘s recommended 

procedures or procedures for a similar design) during periods of startup and shutdown. See, 

§ 63.7530(h) (major source); and § 63.11201(b) (area source).4 These same technical limitations

apply to CISWI units during SS periods, and EPA has failed to explain in the Final Rule why 

these units should be treated differently than major and area source combustion units. As stated 

above, since ACC could not have known that EPA would finalize work practices for major/area 

sources during periods of startup and shutdown in those final rules, and then arbitrarily treat 

combustion units under CISWI differently, we believe the issue is ripe for reconsideration.

Second, while EPA contends that CISWI units can meet the emission standards during SS 

periods, there is no factual support for this assertion in the record, and indeed, ACC provided 

 

3 National Emission Standards for Hazardous Air Pollutants for Area Sources: Industrial, Commercial, and Institutional Boilers, 76 

Fed. Reg. 15554 (March 21, 2011) (hereinafter ―area source boiler rule‖).

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In the preamble to the final major source boiler rule, EPA states: ―Consistent with Sierra Club v. EPA, EPA has established standards 

in this final rule that apply at all times. In establishing the standards in this final rule, EPA has taken into account startup and shutdown periods 

and, for the reasons explained below, has established different standards for those periods. EPA has revised this final rule to require sources to 

meet a work practice standard, which requires following the manufacturer‘s recommended procedures for minimizing periods of startup and 

shutdown, for all subcategories of new and existing boilers and process heaters (that would otherwise be subject to numeric emission limits) 

during periods of startup and shutdown. ... we considered whether performance testing, and therefore, enforcement of numeric emission limits, 

would be practicable during periods of startup and shutdown. EPA determined that it is not technically feasible to complete stack testing—in 

particular, to repeat the multiple required test runs—during periods of startup and shutdown due to physical limitations and the short duration of 

startup and shutdown periods. Therefore, we have established the separate work practice standard for periods of startup and shutdown. Periods of 

startup, normal operations, and shutdown are all predictable and routine aspects of a source‘s operations.‖ 76 Fed. Reg. at 15613.
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evidence to the contrary in its comments, which EPA did not address. See ACC Comments at 

43-46. Finally, as set forth in the table appended to this petition (Attachment 1), when the 

CISWI emission limits are converted to a similar basis as the major source boiler MACT limits, 

it is apparent that some of the CISWI limits are actually more stringent than the major source 

boiler MACT limits for similar subcategories. EPA‘s assertion that CISWI sources could meet 

the emission limits during startup and shutdown periods is unfounded and further disproved 

when comparing the stringency of the CISWI emission limits with those established for major 

sources in the final boiler rule. EPA concluded, and rightly so, that major source boilers cannot 

meet emissions standards established for normal operations during periods of startup and 

shutdown; the Agency must therefore similarly conclude that CISWI units cannot meet even 

more stringent emissions standards established for normal operations during periods of startup 

and shutdown. 

3. EPA should reconsider the CISWI emissions limits because of significant concerns 

ACC raised with the quality of the data the Agency used to set those limits.

ACC raised numerous concerns in its comments about the quality of the data that EPA 

used to set the emission limits in the final rule. EPA appears to have failed to respond to our 

concerns in its Response to Comments document and promulgated limits based on flawed data.

We describe these flaws below.

A. Emission data from units not burning solid waste during their performance tests 

should be removed from EPA’s MACT database, and the MACT floor should be recalculated.

In footnote 1 to its memorandum dated January 12, 2001 ―CISWI Emission Limit 

Calculations for Existing and New Sources,‖ EPA states that it based the standards on the 

performance of devices which would have been classified as CISWIs had the final waste 

definition been in place at the time of the performance testing. The problem, however, is that the

five units shown in the table below were among the top performers (and hence determined the 

floors), but they were not burning solid wastes as defined in the March 21, 2011 Identification of 

Non-Hazardous Secondary Materials That Are Solid Waste: Final Rule, 76 Fed. Reg. 15456

(―NHSM Rule‖), during their performance tests. Accordingly, these units and their data should

be removed from the CISWI Database and the MACT floor determinations should be revised.
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Boiler ID Type Reason for exclusion

NY Black River Generation 

001

Fluid Bed coal fired boiler 

burning bituminous coal, PET 

coke, and Tire-derived-fuel 

(TDF) with wire.

Does not burn solid waste 

since TDF is a fuel with or 

without wire removal (see

NHSM Rule, 76 Fed. Reg. at 

15490–99) and the facility 

received the tires from a 

recycling program.

NY Black River Generation 

002

NY Black River Generation 

003

PA Kimberly Clark Chester 

Boiler 10

Fluid Bed boiler burning 

anthracite culm and PET coke.

Based on the discussion of 

coal refuse in the NHSM rule 

(id. at 15510), the anthracite 

culm burned in this circulating 

fluidized bed boiler would 

likely be considered a fuel.

TN Packaging Corporation or 

America Combo Unit #2

Combination grate/PC boiler 

burning bark, coal, TDF, and 

OCC rejects

Does not burn solid waste 

since TDF and OCC rejects 

determined to be fuel in the 

NHSM Rule. Id. at 15492, 

15487.

B. EPA must incorporate a fuel variability factor for coal fired boilers similar to 

what the Agency did in the major source boiler rule; the failure to do so renders the CISWI limits 

for these boilers arbitrary and capricious.

ACC argues below that EPA should set separate emission standards for coal fired units 

and biomass units for certain pollutants. When EPA does so, and when the Agency also 

excludes units from the database that do not burn solid waste, as discussed immediately above, 

EPA will find that three coal fired boilers (owned by Eastman Chemical Company (―Eastman‖) )

are the only units left in the database. The data for HCl, Hg, Pb, Cd, and SO2, all fuel dependent 

pollutants, for the three boilers is very limited. There are only one or two emissions tests for 

HCl, Hg, Cd, and Pb, and only 30 days of SO2 CEMS data. Along with its comments, Eastman 

submitted historical data on its coal supply which demonstrates the variability of the pollutant 

concentrations in the coal. Because of this demonstrated variability, Eastman urged EPA to use 

the same methodology it used in the final major source boiler rule to establish Fuel Variability 

Factors (FVFs) for each pollutant, which is then multiplied by the 99 percentile UPL determined 

from the stack test data. However, we have found no response from EPA to this comment in 

either the Response to Comments document or the preamble to the final rule. If EPA were to 

apply this methodology, it would result in the following FVFs:

HCl: 3.6

Hg: 1.3

Pb: 1.12

SO2: 1.4

ACC requests that EPA reconsider its rejection of the use of FVFs in establishing the CISWI 

emission standards for coal fired units and revise these standards to incorporate FVFs as it did in 
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the major source boiler rule. Without such an adjustment, the calculated floors (based on 

Eastman‘s limited stack test and CEMS data) would result in standards that do not reflect what is 

being achieved in practice by the best performers, and cannot be reliably met due to the 

variability of the HAP content of the coal.

C. EPA must either revise the CO limits to incorporate periods of startups in its 

MACT floor calculation, or establish work practice standards for periods of startup and 

shutdown.

When EPA issued its Information Collection Request (ICR) for stack test data, the ICR 

specified that units be tested during normal operations while combusting solid waste. In 

response to the ICR, an ACC member company, Eastman, submitted thirty days of CO CEMS 

data from its Boiler 18 that, per EPA‘s instructions, did not include periods of startup, when CO 

is unavoidably higher than during normal operations. After EPA corrects its database by 

removing units that were not burning solid waste, as discussed above, Eastman‘s three boilers 

will be the top performers in the subcategory (in fact the only existing boilers in the coal 

subcategory). Based on the corrected database and EPA‘s standard setting methodology, the new 

CO standard would be 45 ppmv. And, because emissions data during startup was not included in 

EPA‘s methodology, the 45 ppmv CO standard is not representative of what is being achieved in 

practice by the best performers during periods of startup nor could the best performing units be 

assured of continuous compliance with this standards during periods of startup.

This point is further supported by data included in the Council of Industrial Boiler 

Owners (CIBO) comments. CIBO provided CO data from a startup period for one of Eastman‘s 

stoker boilers. See, Comments of the Council of Industrial Boiler Owners on EPA Proposed 

Rule for Standards of Performance for New Stationary Sources and Emission Guidelines for 

Existing Sources: Commercial and Industrial Solid Waste Incineration Units at 35–38, submitted 

Aug. 20, 2010. That data shows relatively high CO emissions (as compared to normal 

operations) during a typical startup period and illustrates the impact one startup would have on a 

30 day rolling average. While EPA claims to have considered emissions during periods of startup 

and shutdown in establishing the CO standard, we see no evidence of this in the record. 

Therefore, EPA either has to recalculate the CO emission standard taking into account emissions 

during startup and shutdown, or issue work practice standards for these periods as it did in the

final major source boiler rule.

D. EPA must revise CO limits for energy recovery units (ERUs) that were based on 

“high normal” steam load because such limits do not represent reserve units that often operate 

at low steam loads.

Based on our review of the record, it appears that EPA used only CEMS data to set the 

CO emission standard for coal fired boilers. This CEMS data, requested by EPA and submitted 

pursuant to EPA‘s ICR, was exclusively from periods when the boilers were operating at high 

steam load. Since Eastman‘s Boiler 18 is the top performer, it should be capable of meeting the 

MACT floor emission standard at all times. However, this is not the case because the boiler

often operates in ―reserve‖ (low steam load) until it must be ramped up to meet facility steam 

load swings. At low steam load, stoker boilers such as this will have higher CO concentrations 
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than at full steady state load. Therefore, EPA needs to either (1) set the standard for this 

subcategory taking into account different, albeit typical modes of operation, or (2) limit the 

applicability of the standard to periods when the unit is operating above 50 percent of its rated 

heat input capacity. EPA recognized this inverse relationship of CO to load in the 2004 boiler 

NESHAP where it limited the applicability to greater than 50 percent load (see 40 CFR 

63.7525(a)(6)). EPA again should acknowledge this technical fact in the CISWI rule and revise 

the CO limits for ERUs accordingly.

4. EPA should have set separate emission standards for PM, Hg, Pb, Cd, and HCl for 

coal fired units and for biomass units. 

A. EPA must separate coal fired units and biomass units into distinct subcategories.

Several commenters (including Eastman – see pages 3-6) requested that EPA establish 

distinct subcategories for biomass and coal fired units.

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 Eastman‘s comment is shown in 

pertinent part below:

To further support this rationale used by EPA in the Boiler and Process Heater MACT 

proposal and to justify its use in the CISWI rule, Eastman offers the following comments: 

(1) since the Clean Air Act requires EPA to set sulfur dioxide limits for CISWI units and 

since coal contains significant concentrations of sulfur and biomass generally would 

contain little of no sulfur, a subcategory just for coal-fired boilers should be established. 

Expensive control devices such as a spray dryer absorber could not reduce the outlet 

concentrations of sulfur dioxide to a level equivalent to those of a biomass boiler; (2) 

observation of the proposed Boiler MACT floor standards proposed for biomass and coal 

units shows that there are significant differences in outlet emissions of HCl, mercury, and 

carbon monoxide; (3) likewise, the NOx emissions from the top performing biomass, 

coal, liquid, and gas-fired units would all be significantly different due to inherent 

differences in the design of these units.

While we are not commenting on EPA‘s Alternative Approach to the definition of solid 

waste, Eastman believes these distinct subcategories (biomass, coal, liquid) for energy

recovery units is appropriate for whichever approach EPA takes.

EPA‘s response to Eastman‘s comment, set forth (in part) below, demonstrates that the 

Agency understood the problem. EPA states:

The CAA allows EPA to divide source categories into subcategories based on differences 

in class, type, or size. For example, differences between given types of units can lead to 

corresponding differences in the nature of emissions and the technical feasibility of 

applying emission control techniques. The design, operating, and emissions information 

that EPA has reviewed indicates differences in unit design that distinguish different types 

of ERUs. Data indicate that there are generally significant design and operational 

 

5 We note that EPA is initiating reconsideration of this issue. Notice of Reconsideration, 76 Fed. Reg. at 15267. 
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differences between units that burn coal, biomass, liquid, and gaseous fuels. Energy 

Recovery Units are therefore designed for specific fuel types and will encounter problems 

if a fuel with characteristics other than those originally specified is fired. Many ERUs in 

the database are indicated to co-fire liquids or gases with solid fuels, but, in actuality, 

most of these boilers commonly use fuel oil or natural gas as a startup fuel only and then 

operate on solid fuel during the remainder of their operation. In contrast, some co-fired 

units are specifically designed to fire combinations of solids, liquids, and gases. Changes 

to the fuel type would generally require extensive changes to the fuel handling and 

feeding system (e.g., a stoker using wood as fuel would need to be redesigned to handle 

fuel oil or liquid wastes). Additionally, the burners and combustion chamber would need 

to be redesigned and modified to handle different fuel types and account for increases or 

decreases in the fuel volume. In some cases, the changes may reduce the capacity and 

efficiency of the ERU. An additional effect of these changes would be extensive 

retrofitting needed to operate using a different fuel; therefore, the design of the ERU 

impacts the degree of combustion.

In our investigations resulting from commenters' statements, we concluded that the data 

were sufficient for determining that a distinguishable difference in performance exists 

based on unit design type. Therefore, because different types of units have different 

emission characteristics which may influence the feasibility or effectiveness of emission 

control, they should be regulated separately (i.e., subcategorized) for affected pollutants. 

Accordingly, we have subcategorized ERUs based on unit design in order to account for 

these differences in emissions and applicable controls. The two primary ERU 

subcategories are units designed to burn solid wastes (solids) with other solid fuels, and 

units designed to burn liquid wastes with liquid or gaseous fuel (liquid/gas). 

Final Rule, 76 Fed. Reg. at 15733 (emphasis added).

Notwithstanding its lengthy technical discussion of the significant operational and design 

differences between coal and biomass fired units, EPA inexplicably proceeded to ignore its own 

reasoning, combined coal fired units and biomass units into one subcategory and set standards 

for fuel derived HAP (PM, Hg, Pb, Cd, and HCl) for that combined subcategory.

The subcategory, when corrected through the elimination of units not burning solid waste 

(as discussed above), will include three coal fired boilers and approximately twenty other solid 

fuel energy recovery units (ERUs). Each of these ERUs is a biomass unit that burned no coal 

during its performance test. 

Coal fired boilers are fundamentally different than biomass units. For example, a coal

fired boiler by design cannot burn more than 10 percent biomass without experiencing 

unacceptable performance degradation, including fouling and loss of fan capacity. This is due to 

the differing chemical constituents of the ash, which influence fouling characteristics (increased 

fouling potential with biomass), and the significantly higher moisture in biomass versus coal, 

which increases volumetric flow rate and thereby limits fan capacity with biomass.
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Additionally, there are fundamental differences between coal and biomass units for 

metals and chlorine (Cl) content. The concentration of Cd, Pb, and Cl in coal is a function of the 

geology and formation of the coal seams, and is a factor inherent to the coal mined from different 

basins, and seams within basins. The concentration of metals and Cl in biomass is a function of 

surface conditions (e.g., concentrations in the soil) and handling (e.g., logs floated down a 

brackish river can have very high concentrations of Cl). Similarly, the ash constituents in 

biomass tend to be high in certain alkalis that are largely absent in coal (e.g., much more MgO, 

Na2O, K2O), while significantly lower in other areas (SiO2, Al2O3). There is no fundamental 

relationship between Hg and Cl concentrations, or ash constituents in coal and biomass that 

would warrant their being grouped into a single solid fuel subcategory. 

 

Lastly, by grouping coal fired units and biomass units into one subcategory, the resulting 

standards for Hg and HCl were driven in large part on emissions from biomass units. 

Unfortunately, coal fired boilers cannot burn a higher percentage of biomass to meet the Hg and 

HCl standards without experiencing operational limitations, or requiring significant physical 

modifications. 

EPA can remedy this problem by separating biomass units and coal units into separate 

subcategories for all emission standards and by using the same criteria it established in the major 

source boiler rule that a unit that burns more than 10 percent biomass on an average annual heat 

input basis should be classified as a biomass unit. See, § 63.7575. EPA has failed to explain why 

that same sound approach should not be followed in the CISWI rule.

B. EPA should not include emissions data from combination units burning less than 

90 percent coal when establishing standards for coal fired units.

Combination (biomass/coal) units should not be grouped with coal fired units to set 

emission standards. Grouping combination units that burn biomass and coal with coal units raises 

two significant problems. First, because of different design constraints, combination units 

cannot be expected to meet the same CO limit as a coal fired boiler. Second, as discussed above, 

coal units and combination units have different designs for different blends of fuels, which in 

turn have different concentrations of mercury, chlorine, sulfur, cadmium and lead. 

Fundamentally, the combination units are unique and they should be placed in a separate 

subcategory. In the meantime, data from these units should be excluded from MACT floor 

determinations made for coal fired units. We note that in the major source boiler rule EPA 

excluded performance test data from co-fired units that burn less than 90 percent of a particular 

fuel type. That same approach should be taken in the CISWI rule.

5. EPA should reconsider and solicit comments on the O2 monitoring requirements.

The final CISWI rule imposes a CO emission limit on all subcategories with compliance 

demonstrated by either a CO CEMS or an annual Method 10 CO emission test. In the case of 

ERUs with a heat input capacity of 100 MMBtu/hr or greater, the final rule alternatively requires 

that an O2 CEMS be used to continuously monitor oxygen. While ACC agrees that the use of a 

CO CEMS should be optional, the O2 monitoring requirements as finalized for large ERUs are 

not appropriate or workable. The O2 monitoring requirements were not part of the proposed 
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CISWI rule and are not a logical outgrowth of what was proposed. EPA therefore should 

reconsider and solicit comment on these requirements. 6

In the proposed rule, EPA established CO emissions limits for ERUs, with compliance 

demonstrated as a 24 hour basis. Although CO CEMS monitoring was required at all times, the 

CO limits were based only on an analysis of 3-run stack test data, did not adequately consider 

variability, and did not exclude periods of SSM and low load operation. 

ACC addressed the proposed rule CO limits and compliance methodology in our 

comments at 23-25. ACC and others provided extensive information regarding the variability of 

CO emissions and the inappropriateness of setting a limit using full load stack test data on the 

one hand, but on the other hand, requiring units to demonstrate compliance during all operating 

conditions with CO CEMS. 

In the Final Rule, EPA provided two compliance options for ERUs with a heat input 

capacity of 100 MMBtu/hr or greater. Those units may either demonstrate compliance through 

use of a CO CEMS; or, use an annual Method 10 CO performance testing with an O2 CEMS to 

demonstrate compliance on a 30 day rolling average. While ACC generally supports the adoption 

of compliance alternatives, we would like to point out some problems with the final requirements 

that might have been avoided had EPA solicited comment on the O2 monitoring issue.

We do not believe that CO CEMS is an appropriate mandatory monitoring requirement 

for a CO limit based on stack test data obtained at full load conditions. We also do not believe 

that a requirement to monitor O2 levels in the stack, or ductwork leading to the stack, to ensure 

continuous compliance is appropriate for all units. Many existing boilers and process heaters 

already utilize flue gas oxygen analyzers for indication, alarm, and O2 trim control, where the 

fuel/air ratio is automatically controlled for optimum combustion conditions. The sensing 

location for existing O2 monitors is typically in the optimum location to sense flue gas 

composition as reliably as possible, because sensing of oxygen in these cases maintains proper 

excess air levels and helps prevent unsafe operating conditions. For many types of combustion 

units, that location is near the combustion chamber outlet in a position upstream of any potential 

air inleakage points to avoid erroneous excess air indications which would drive controls in the 

wrong direction. This location is also upstream of air preheaters, where utilized, thus avoiding 

the erroneous (high O2) indications due to inherent leakage across regenerative air preheater 

seals or potential tube leakage in recuperative air preheaters. For those units equipped with 

existing O2 sensors and O2 trim control systems, flue gas composition at those locations would 

already be used for combustion tuning and control characterization. Therefore, if O2 monitoring 

was desired for continuous compliance under the CISWI rule, sensing O2 at that current location 

would be logical and proper from a technical perspective. However, O2 analyzers utilized for 

these existing purposes are not compliance CEMS meeting performance specification (PS) 3 

requirements relative to positioning or other QA/QC requirements. They are, however, 

calibrated and maintained to provide reliable and safe service for combustion unit operation.

 

6 We note that EPA may initiate reconsideration of this issue. Notice of Reconsideration, 76 Fed. Reg. at 15267. 
13

Conversely, if O2 was sensed prior to the stack or in the stack, that would be downstream 

of potential air inleakage points and air preheater leakage points, thus leading to variations in 

readings that can impact operation and long term compliance. Where CO or NOx CEMS are 

utilized in the stack with O2 or CO2 correction, the O2 or CO2 reading purposely corrects for 

variations in excess air from the furnace as well as any air inleakage or internal air heater 

leakage, so the impact is not of consequence from a combustion safety or direct compliance 

perspective. However, if it is required to actually monitor and maintain a specific O2 level

(which we note EPA did not establish), then the most appropriate location for sensing that level 

is upstream of any potential leakage points. By definition, those locations will not meet PS 3 

requirements due to their close coupled nature and use of single or multiple point sensors that are 

most appropriate for the application.

ACC believes the most cost effective approach for using O2 CEMS as a compliance 

alternative would be to allow sources use of existing O2 analyzers. If a source wants to use a

new O2 analyzer, it should be of an appropriate design for the application and be located in an 

optimum position for the particular unit involved. Requiring periodic sensor calibration would 

be a way to ensure accurate O2 monitoring. 

EPA‘s requirement that any new O2 sensor be located in the breeching or stack to meet 

PS 3 requirements, will result in additional and unnecessary capital and ongoing O&M expenses

that will not provide any constructive compliance information. For this reason, we urge EPA to 

reconsider and take comment on these requirements.

6. EPA should revise CEMS provisions to adequately provide for existing dilutionextraction SO2 and CO CEMS to be used. 

Some energy recovery units have existing CEMS that utilize a dilution-extraction 

sampling system for compliance with other air emission regulations. Such systems use highpressure ambient air to dilute the stack gas sample as a method of avoiding accuracy and 

reliability problems associated with liquids condensing out of the flue gas sample. Because these 

systems introduce air onto the stack sample, they do not measure O2 and instead typically rely on 

CO2 as the diluent gas. For units equipped with this type of CEMS, the requirement to monitor 

O2 with a system capable of meeting PS 3 requirements would in effect mandate either a 

wholesale replacement of the existing CEMS, or the installation of an entirely redundant CEMS 

(e.g., probe, sample umbilical, sample conditioner, analyzer). Either of these approaches would 

unnecessarily impose significant capital and O&M costs.

The Final Rule allows for use of such CEMS by providing a CO2 alternative in the case 

of NOx CEMS (See, 40 CFR 60.2710(t)(1) and (4)). These provisions require that O2 and CO2

be correlated so NOx emissions can be expressed to an equivalent 7 percent O2 basis. The Final 

Rule also allows for use of CO2 as an alternative diluent gas associated with SO2 CEMS (see 40 

CFR 60.2710(s)(1)), but the SO2 subsection does not include a provision, like 60.2710(t)(4), that 

allows one to correlate CO2 and O2 when using an SO2 CEMS. Such a provision is needed so 

that SO2 emission concentrations measured using CO2 as a diluent can be compared to the 

emission standard, which is expressed corrected to the 7 percent O2.
14

Moreover, the Final Rule also failed to include similar provisions allowing use of CO2 as 

a diluent for CO CEMS. See, 40 CFR 60.2710(g) and (w). Provisions similar to 40 CFR 

60.2710(t)(1) and (4) are needed. We are seeking reconsideration of this issue because we 

believe these would have been included if EPA had had more time to read and fully consider all 

of the comments and to finalize this rule.

7. EPA should reconsider and take comment on the elimination of provisions that 

allow missing CEMS data.

In the proposed rule, EPA included several provisions that allow for some amount of 

missing data from continuous emissions monitoring systems. See, § 60.2710(q)(4) (requires 

85% of hours in a day, 90% of hours in a quarter, and 95% of hours in a year for SO2 CEMS) 

and § 60.2710(r)(4) (similar provisions for NOx CEMS). EPA also solicited comment on 

whether or not the rule should require valid emissions data from CEMS for all times that the 

facility is operated.

ACC‘s comments and those of many others on the proposed rule supported EPA 

inclusion of these provisions. Our comments also requested that EPA include a similar provision 

for CO CEMS, as well as expand the provisions to include continuous parametric monitoring 

systems (CPMS). The comment and EPA‘s response is shown below:

We agree with the CEMS data availability requirements in the proposed rule and do not 

believe that it is appropriate to require 100 percent data availability for these units (e.g., 

redundant CEMS). However, it appears that EPA did not include CO CEMS is (sic) this 

provision. We assume that is an oversight as any CEMS would need some tolerance for 

missing data in the regulation. Facilities operate in a manner that ensures equipment is 

well maintained and strive to meet monitoring responsibilities. However, even top 

performers have equipment malfunctions, and the rule must accommodate occasional 

periods of missing data that are outside the owner or operator ̳s control. In addition, ACC 

does not believe that EPA needs to prescribe redundant CEMS, since even redundant 

CEMS cannot guarantee perfection. Even with the proposed minimum data availability, 

some facilities may install redundant CEMS to ensure that degree of availability without 

EPA mandating it. ACC does not believe EPA should prescribe missing data procedures, 

owner/operator developed missing data, or parametric monitoring, especially since

facilities have incentives to maintain monitoring systems without EPA prescribing how 

they should do it.

Response: The final rule includes revisions to the general requirements for operating 

continuous monitoring systems that addresses this concern. We have not included any 

specific minimum data availability requirement, nor do we require substitute data below 

some threshold as the proposed rule indicated in certain sections. We believe that 

numerical missing data allowances quickly become targets or excuses, not incentives to 

conduct monitoring in a manner consistent with good air pollution control practices. For 

all monitoring required or applied as an option under this rule, we have included 

provisions that would require you to operate the monitoring system and collect data at all 
15

required intervals at all times the affected source is operating except for periods of 

monitoring system malfunctions, repairs associated with monitoring system malfunctions, 

and required monitoring system quality assurance or quality control activities (including, 

as applicable, calibration checks and required zero and span adjustments). Further, you 

may not use data recorded during monitoring system malfunctions, repairs associated 

with monitoring system malfunctions, or required monitoring system quality assurance or 

control activities in calculations used to report emissions or operating levels. A 

monitoring system malfunction is any sudden, infrequent, not reasonably preventable 

failure of the monitoring system to provide valid data. Monitoring system failures that are 

caused in part by poor maintenance or careless operation are not malfunctions. You must 

use all the data collected during all other periods in assessing the operation of the control 

device and associated control system.

Response to Comments at 1068.

Needless to say, EPA‘s complete reversal of what it proposed is disappointing, even 

though it asked for comment on the removal of these provisions. We are particularly 

disappointed because in our review of the Response to Comments document, we found no 

comments that supported, much less advocated for the removal of these provisions. If EPA 

believes these provisions should be removed, it needs to be more transparent and actually 

propose that action. If it had done so, ACC and others would have focused their comments on 

why that is not a sound approach. For example, we believe that removal of these provisions 

along with the fact that CEMS are costly to install and maintain, will create a strong disincentive 

for sources to choose CEMS in lieu of periodic performance tests and parametric monitoring. We 

believe that EPA should provide proper, i.e., clearer, notice to allow the regulated community 

and others to focus their comments on the potential consequences and impact of removing these 

provisions. 

8. EPA should reduce the excessive performance testing requirements to make the 

CISWI rule consistent with the more reasonable testing requirements of other rules. 

Pursuant to the Final Rule, ACC members will be conducting annual stack tests for PM, 

D/F, Hg, HCl, SO2, NOx, CO, Hg, Pb, and Cd. The suite of HAPs subject to stack testing may be 

reduced if a CEMS is used to monitor a pollutant‘s emissions.

7

 

The frequency of testing is reduced somewhat if two consecutive tests are passed with at 

least a 25% margin; in which case, the source need only test every three years for a given 

pollutant. The stack testing frequency required in the final rule is unreasonable, particularly for 

units less than 250 MMBtu/hr. Indeed, several commenters requested that EPA reduce the test 

frequency. The requirement to conduct annual or even triennial performance tests is not usually 

found NESHAP and NSPS rules. For example, the Hazardous Waste Combustion (―HWC‖)

NESHAP requires stack testing every five years. 40 C.F.R. § 63.1207(d)(1). Another example 

is NSPS Subpart Db, which requires no automatic retesting of the initial PM performance test.

 

7 EPA believes that CEMS are an option for PM, D/F, Hg, HCl, SO2, NOx, and CO. See, 40 C.F.R. § 60.2165 (New Sources 76 Fed. 

Reg. at 15757): (h) for PM CEMS, (i) for D/F ―continuous automated sampling system‖,(j) for Hg continuous automated sampling system, (k) for 

NOx CEMS, and (l) for SO2 CEMS; and 40 C.F.R. § 60.2730 (Existing Sources 76 Fed. Reg. at 15778) same sub-paragraphs (h though l).
16

EPA disagreed with the industry commenters, stating that ―the combination of periodic 

compliance emissions testing and continuous monitoring of operational and parametric control 

measure conditions is appropriate for assuring continuous compliance with the emissions 

limitations. Without recurring testing, we would have no way to know if parameter ranges 

established during initial performance testing remained viable in the future.‖ 76 Fed. Reg. at 

15736–37.

We strongly disagree with EPA‘s statement that without recurring testing, the Agency

would have no way to know if parameter ranges remain viable. Absent some change in the air 

pollution control device (APCD) or the source, there is no reason that a parameter range should 

not remain viable. We note that the Final Rule also requires that the APCD be inspected 

annually, which further diminishes the already low likelihood that the parameter range would not 

remain viable in the future. Id. at 15710. Moreover, companies inspect the unit and the control 

devices for proper operation during scheduled maintenance outages. If an APCD or its 

parameter control system were to be impaired between inspections, it would show up in the 

continuous parametric monitoring (e.g., deviations in ESP power, wet scrubber liquid feed rate, 

or pH, or detections of bag leakage.)

Accordingly, while EPA has made some improvements in the testing provisions from the

proposed to the final rule, it should reconsider the onerous nature of these testing provisions. At 

the very least, EPA should reconsider the D/F testing requirements. Given the difficulty and 

expense of these tests and the analytical work, together with the very low dioxin levels detected 

in emissions from CISWI units, EPA should reduce the testing requirement to a one-time test as 

it did in the final major source boiler rule. See, 76 Fed. Reg. at 15649, 15667; 40 C.F.R. §

63.7515(a). Also, where a facility has fuel and waste analytical data showing that an emission 

standard for a constituent can be met when all of a regulated constituent that is fed to a 

combustion device is emitted, performance tests should not be required. Again, the final major 

source boiler rule included this option for Cl and Hg. See § 63.7510(b), id. at 15667. The HWC 

MACT also provides a similar option called maximum theoretical emission concentration 

(―MTEC‖). See, 40 C.F.R. § 63.1207(m). 

EPA has not explained why the emission test frequency requirements of the prior CISWI 

rules, i.e., initial performance test for all listed pollutants, with annual testing for PM, HCl and 

opacity only, with an allowance for triennial testing if emissions for three consecutive years meet 

the limits, needed to be changed. Those requirements have been in effect for a considerable 

period of time and units which were already subject to CISWI before the 2011 Final Rule should 

be allowed continued use of past test frequencies, though we believe these past frequencies 

should be applicable to all CISWI units. 

Moreover, ACC believes that a once-in-five-year testing frequency would be protective 

of the environment, cost effective, and consistent with other EPA regulations. For example, the 

provisions for the Continuous Emission Monitoring for Air Programs require low mass emission 

units to establish NOx emission curves based on testing conducted every five years. 40 CFR 

75.19(c)(1)(iv)(D). It is common practice in several states, e.g., Virginia, North Carolina, etc.,

to require that testing be conducted upon each five-year Title V permit renewal. 
17

9. EPA should reconsider its deletion of the definition of “solid waste” and “contained 

gaseous material” in the Final Rule, which could result in numerous process and other 

gases being considered “solid waste” and regulated under CISWI.

The 2000 CISWI rule contained definitions of ―solid waste‖ and ―contained gaseous 

material‖ to the effect that only gases in a container that itself was combusted were considered to 

be ―solid waste.‖ See 40 C.F.R. Part 60, Subpart CCCC, § 60.2265; Subpart DDDD § 60.2265. 

Gases not in such containers when burned -- gases in pipes that were injected through nozzles 

into the combustion chamber for combustion -- were not solid waste and therefore not regulated 

under CISWI. 

The proposed CISWI rule deleted the definitions of ―solid waste‖ from sections 60.2265 

and 60.2875, but left intact the definition of contained gaseous material. Therefore, since the 

proposed rule referenced the solid waste definition that included ―contained gaseous material‖ 

and the definitions of ―contained gaseous material‖ remained in CCCC and DDDD, there was no 

problem with the proposed rule language. In the final CISWI and the Identification Of NonHazardous Secondary Materials That Are Solid Waste (NHSM) rules, however, EPA for the first 

time, and without notice to the regulated community, deleted the term ―contained gaseous 

material,‖ thereby causing great confusion over whether gases in pipelines, vents, etc., that are 

combusted are now considered ―solid waste‖ and therefore subject to CISWI. This is a 

significant reversal of EPA‘s previous and long-held position.8 EPA did not propose this 

reversal in either the CISWI or NHSM proposals, and made only a passing reference to it in a 

response to comments on the NHSM rule.9 

The ramifications of this reversal are enormous. Process gases in pipelines, ducts and 

vents that are combusted could become subject to CISWI unless the gases are combusted in air 

pollution control equipment considered part of the affected source under another NESHAP. 

Flares and other air pollution control equipment such as regenerative thermal oxidizers that are 

not associated with an affected source under another NESHAP, and boilers, furnaces, and kilns 

that burn process gases could be considered CISWI units. This significantly expands the 

universe of CISWI units, yet EPA‘s proposed CISWI did not consider nor include emissions 

from these gases.

EPA did not provide any opportunity for the regulated community to comment on this 

issue, and in comments on reconsideration, ACC will show that there is no basis for EPA to 

 

8 EPA established its position on this issue in 1982 at 47 Fed. Reg. 27520, 27530 (June 24, 1982); reaffirmed it in 1986, see,

RCRA/Superfund Hotline Monthly Summary, 9488. 1986(03), available at ―RCRA Online‖; in 1987, see Memorandum from Matthew Strauss, 

Chief Waste Characterization Branch, to Clifford Ng, Engineer, EPA Region II (June 17, 1987), available at RCRA Online; in 1989, see, 54 Fed. 

Reg. 50968, 50973; in 1991, see, 56 Fed. Reg. 7134, 7200 (Feb. 21, 1991); and, in the 2000 CISWI rule, see, Response to Comments at 15.

9

 EPA stated, ―In the first place, we are unable to find any Agency reasoning supporting previous EPA interpretations that only gases 

in containers may be considered ―contained.‖ Based on the facts of this case, EPA cannot see how gaseous secondary material that is generated 

in any particular system and is somehow sent to a gas-fired boiler, even through a pipeline, can be considered an ―uncontained gas.‖ NHSM, 

Response to Comments, at 212.
18

change its longstanding interpretation that ―contained gaseous material‖ should include only 

gases that are in a container when that container is combusted.

10

 

10. EPA should clarify that operating parameter limits do not apply during subsequent 

performance testing, including pre-testing. 

In the proposed rule, EPA required that the source continuously monitor operating 

parameter limits (OPLs), and determined that any operation above or below parameter 

requirements would be a deviation. See Standards of Performance for New Stationary Sources 

and Emission Guidelines for Existing Sources: Commercial and Industrial Solid Waste 

Incineration Units; Proposed Rule, 75 Fed. Reg. 31938, 31976 & 31992 (proposed June 4, 2010). 

In its response to comments submitted by ACC and others on these provisions, EPA stated that 

the final rule waives the applicability of operating limits during performance testing:

EPA has revised the rule to waive the operating limits during source testing so that 

sources may adjust their operating limits to provide increased operating flexibility 

provided the emissions limits are met. The intention behind reassessing operating limits 

with new performance testing is to ensure that the limits remain appropriate for the 

source. By allowing the source to conduct performance test with less stringent operating 

levels that may have been initially determined, the source will be able to set the limits at 

levels appropriate for their operations while ensuring emissions limits are met.

Response to Comments, at 1111 (Feb. 20, 2011).

 

In the final rule EPA appropriately revised the regulatory language to reflect the above 

response to comments for Subpart CCCC as follows:

Operation above the established maximum, below the established minimum, or outside 

the allowable range of the operating limits specified in paragraph (a) of this section 

constitutes a deviation from your operating limits subpart, except during performance 

tests conducted to determine compliance with the emission and operating limits or to 

establish new operating limits. Operating limits are confirmed or reestablished during 

performance tests.

See, Final Rule, 76 Fed. Reg. at 15753–54 (emphasis added). EPA did not, however, revise 

similar language for Subpart DDDD. Id. at 15773–77. ACC requests that EPA reconsider and 

correct what ACC believes to be an oversight with respect to subpart DDDD.

ACC is also concerned that, as written, the ongoing testing requirements, particularly for 

existing units (subpart DDDD), could result in a continual reduction of operating limits if 

facilities have to reset the operating limits every time a stack test is done. Facilities typically 

operate with a safety margin with respect to operating limits. Therefore, if the operating limits 

 

10 Since publication of the Final Rule on March 21, 2011, Suzanne Rudzinski, Director of the Office of Resource Conservation and 

Recovery, sent a letter on May 13, 2011 to the AF&PA regarding her office‘s position on ―contained gaseous material‖ and clarified that EPA‘s 

long-held policy on contained gases has not changed. We appreciate this step towards rectifying the situation.
19

are reset with each performance test, they will continue to change, requiring a continual increase 

in energy and operating costs. Other combustion-related MACT rules, for example, HWC 

MACT, explicitly waives current OPLs during subsequent comprehensive performance testing. 

See, 40 C.F.R. § 63.1207(h)(1). The same waiver should be made explicit in the CISWI rule.

Lastly, ACC is concerned about the status of pre-testing associated with performance 

testing since pre-testing is usually an integral component of testing. The proposed CISWI rule 

was silent on the issue. It is common to conduct pretesting prior to conducting a performance 

test, particularly when there are numerous stack sampling trains to be used. For a unit to be able 

to operate at a new condition during a performance test, it must be allowed to operate at that 

condition for a period of time before the actual test so that the operator can determine if the 

condition is feasible. If the condition is outside the existing operating limits, there is no way for 

the operator to do this. Therefore, existing operating limits need to be waived for pre-testing 

associated with subsequent performance tests. Section 63.1207(h)(2) of the HWC MACT states: 

―current operating parameter limits are also waived during pretesting prior to comprehensive 

performance testing for an aggregate time not to exceed 720 hours of operation...‖ ACC urges 

EPA to reconsider and revise the language in the final CISWI rule to clarify that operator 

parameter limits are also waived during pretesting prior to performance testing.

11. EPA should include a compliance option that allows a source to develop a feed 

stream analysis for approval by the permitting authority for fuel based pollutants (metals) 

that are not destroyed.

The proposed rule provided only two compliance methods for feed dependent pollutants 

(Cd, Pb, Hg, SO2, and HCl); stack testing/parameter monitoring or CEMS. ACC and others 

commented that EPA should allow for a third option similar to that allowed under the HWC 

MACT, i.e., allowing a source to develop a feed stream analysis plan for pollutants that are feed 

dependent and not destroyed in the combustion process. See 40 C.F.R. § 63.1209(l)(1)(ii).

11 In 

its response to comments, EPA either dismissed or misunderstood these comments when it 

responded (in a response to similar comments from CIBO) that if a source wants to use this kind 

of approach, it should petition the Administrator for an alternative monitoring method under the 

general provisions. See, Response to Comments at 1150–51. 

First, we believe that requiring sources to petition EPA on a case by case basis to use an 

accepted compliance alternative is burdensome and a waste of both EPA and industry resources.

Second, EPA offers no explanation as to why it believes that the emission standards it has 

established properly consider and address fuel and waste variability. EPA‘s dataset has no more 

than one stack test for few, if any top performing units. Moreover, in EPA‘s memorandum, 

―CISWI Emission Limit Calculations for Existing and New Sources,‖ section II.B ―Data 

Variability Analysis,‖ the Agency purports to address variability but the only mention of EPA‘s 

accounting for fuel variability relates to waste burning kilns. The only review of data variability 

for energy recovery units looked at only three 1-hour stack tests runs for each top performer. A 

 

11 Maximum theoretical emissions concentration (MTEC) is an alternative method used in the HWC MACT for demonstrating 

emissions compliance and is especially useful for sources which have low concentrations of HAP in their feeds. See, 40 CFR 63.1206(m). 
20

1-hour stack test for a best performing unit burning coal will not account for the inherent 

variability of HAP in the coal.

Further, EPA devoted little time to addressing the merits of the issues raised in the 

comments, responding that commenters provided no cost information to support the belief that a 

fuel sampling plan may be more cost-effective than a CEMS. To that end, we offer the following

information from a member company. One member company reports a laboratory cost of $250 

per coal sample to analyze for a suite of metals, chlorine and mercury. If the company analyzed 

one sample per shipment of coal, its annual analytical costs would total $50,000. Based on 

EPA‘s spreadsheet, ―Cost Memo Table 6‖, EPA estimates the annualized cost of a mercury 

CEMS alone at $112,600. Add in the annualized cost of a HCl and a multi-metals CEMS and it 

is clear that the CEMS costs would exceed a rigorous fuel and waste sampling plan. In a case 

where the facility does not need to rely on system removal efficiency, the facility would also 

save in its periodic stack testing by eliminating one or more sampling trains. This could easily 

save the facility $20,000 – $30,000 per year.

Lastly, ACC and others were advocating for a substantive compliance option similar to 

that offered in the HWC MACT. See, Response to Comments at 1153–54. The HWC MACT, 

for example, provides a feed rate option for mercury for liquid fuel-fired boilers based on a 

rolling average not to exceed an annual rolling average. 40 C.F.R. 63.1209(l)(1)(ii). In addition, 

40 CFR 63.1207(m) sets forth a performance test option when using MTEC for mercury, semivolatile metals, low volatile metals, and chloride. This option is particularly useful when the 

concentration of HAP in the feed is low. If the feed concentration is low, then the maximum 

emissions of the pollutant can be no greater than what is present in the feed. If that amount 

would be less than the respective emission standard, then the performance testing for that 

pollutant can be based on a feed analysis and a stack flow rate, and there is no need for a stack 

sample. Sampling and analyzing feeds is much less expensive and complicated than using a 

stack sampling train. Under the HWC MACT, a unit that could avail itself fully of the MTEC 

option for the allowable pollutants, could save $50,000-$80,000 per test in the performance 

testing cost.

ACC‘s comments also highlighted and advocated for another compliance alternative, 

drawn from the HWC MACT, for sources that need to comply with a higher feed rate of metals 

than actually demonstrated in the performance test. See, 40 CFR 63.1209(l) and 63.1209(n). 

Under this alternative, sources with very low emissions of metals can sample both their feeds and 

emissions during the performance test and develop a system removal efficiency and then 

extrapolate a feed rate limit higher than the test demonstrated as long as the extrapolated feed 

rate is not significantly higher than historical levels. The Agency did not prescribe what the 

upper bound would be on the extrapolation, but during implementation EPA generally said no 

more than three times the historical value. Under HWC MACT, the manner in which the source 

followed one of these allowable alternatives was explained in a Feedstream Analysis Plan. 

We believe EPA has failed to provide an adequate response to industry comments 

advocating these compliance alternatives and these alternatives would reduce the overall costs of 

the Final Rule, while still providing the same substantive compliance data, we urge EPA to 

reconsider its position.
21

12. EPA should provide the same allowance for varying OPLs with varying operating 

load in the CISWI Rule as set forth in the major source boiler rule. 

The 2000 final CISWI rule required operating parameter limits (―OPLs‖) to be 

established based on average operating parameter levels demonstrated during the performance 

test, with additional allowances to increase maximum limits by 10% of the actual average level 

demonstrated and to reduce minimum limits by 10% of the actual average level demonstrated.

See 40 C.F.R. §§ 60.2110, 60.2675. The 2010 proposed CISWI rule added OPLs for other air 

pollution control devices and required that the limits be set based on the data from the 

performance test, without any 10% increases for maximum limits or 10% decreases for minimum 

limits. However, the 2010 proposed rule did not revise the language of the 2000 rule, such that 

OPLs required by the previous rule were still allowed to be established with the 10% allowance. 

See, CCCC § 60.2110 p. 31974; DDDD § 60.2675 p. 31990.

12

In response to the 2010 proposed CISWI rule, ACC, Eastman, and others commented that 

operating limits and monitoring requirements need to incorporate operating flexibility, and that 

EPA should allow sources to set operating limits based on data gathered during performance 

tests and any supplemental information. See, EPA Response to Comments, pp. 1103–04, 1111–

12. In the Final Rule, EPA rejected these comments and eliminated the use of the 10% 

minimum and maximum allowances in the calculation of OPLs from the operating data 

demonstrated during the performance test. See, Final Rule, 76 Fed. Reg. at 15751, 15771.

13 The 

Final Rule also changed the methodology for calculating OPLs. Whereas the previous and 

proposed rules established the OPLs based on averages, the Final Rule establishes the OPLs as 

the lowest 1-hour average from the test for minimum limits, not from the overall test averages. 

So, the fundamental issue here, which involves each of the technical issues discussed 

above, is that EPA did not address ACC‘s comments and the real world situation that ERUs and 

other units covered by the CISWI rule operate at various loads. At such varying loads, operating 

parameters also vary. A performance test at a high operating load does not allow the unit or its 

air pollution controls to operate efficiently at lower loads. Accordingly, EPA should reconsider 

this issue and allow for the variation of OPLs with operating loads. The approach we 

recommend is precisely the approach EPA took in the major source boiler rule.14 

13. Charge rate is not an appropriate limit to monitor on energy recovery units. 

 

12 Note that in the proposed rule, these sections begin with (d), they do not amend (a), (b), or (c). 

13 The final rule did not change the use of a 10% allowance for the maximum charge rate for a wet scrubber. See, Id. at 15751, 15771.

14 See, Table 7 of the major source boiler, i.e., ―When your unit operates at lower loads, multiply your sorbent injection rate by the 

load fraction (e.g., for 50 percent load, multiply the injection rate operating limits by 0.5) to determine the required injection rate;‖ When your 

unit operates at lower loads, multiply your activated carbon injection rate by the load fraction (e.g., actual heat input divided by heat input during 

performance test, for 50 percent load, multiply the injection rate operating limits by 0.5) to determine the required injection rate.‖ 76 Fed. Reg. 

15696, Table 7 #3.
22

Section 60.2675(a)(1) requires any unit using a wet scrubber to comply with the emission 

limitations to establish maximum charge rate as an operating limit. The limit is set at 110 percent 

of the charge rate during the performance test. Until this Final Rule, this provision only applied

to incinerators. Now that EPA is including energy recovery units in CISWI, commenters urged 

EPA to re-think this provision, arguing that there was no need for maximum charge rate of fossil 

fuel for a steam generating unit such as a boiler. This is not part of the compliance requirements 

for a solid-fuel boiler burning hazardous waste and subject to 40 CFR 63 Subpart EEE (HWC

MACT). EPA rejected these comments with the following response, but the Agency did not 

address the distinction between incinerators and energy recovery units.

Response: Disagree. As commenter points out earlier, operating conditions affect 

parameter range. Process operation outside conditions established during emissions 

testing can and will cause changes in emissions control device operation and in 

emissions. Source owners and operators, who best understand the operating 

characteristics of their processes, need to conduct emissions testing so that parameter 

ranges established reflect actual operating conditions.

Response to Comments at 1113.

Commenters further urged that if charge rate has to be monitored, it should be redefined 

as ―operating load‖ for energy recovery units, similar to the major source boiler rule. However, 

this position is not reflected in the Final Rule. Accordingly, because EPA has (1) not addressed 

the difference between incinerators and energy recovery units; and (2) not addressed commenters 

proposal that charge rate could alternatively be redefined as operating load, this issue should be 

reconsidered.

14. Monitoring requirements for dry scrubbers should be established in the rule and 

not by petition. 

The Final Rule sets forth monitoring requirements for wet scrubbers, activated carbon 

injection, SNCR and ESPs. See, 76 Fed. Reg. at 15751-52, 15771-72; §§ 60.2110, 60.2675. The 

proposal did not contain requirements for duct sorbent injection or dry scrubbers, meaning that 

sources that use those technologies for pollution control would have to petition EPA for 

monitoring requirements. Commenters requested that EPA promulgate monitoring requirements 

for these technologies15 and EPA failed to respond adequately to the comments.16 Accordingly, 

 

15 One commenter stated, ―A source should not have to petition to establish operating parameters for fabric filters, electrostatic 

precipitators (ESPs), activated carbon injection, selective noncatalytic reduction (SNCR), duct sorbent injection, or spray dryer absorbers. 

§60.2680 requires a source to petition the Administrator for specific operating limits if you use an air pollution control device other than a wet 

scrubber. However, in proposed § 60.2675(d), (e), and (f), EPA‘s proposes operating limits for fabric filters, ESPs, activated carbon injection, and 

SNCR. Therefore, no petition should be required in these cases. Also, since spray dryer absorbers or duct sorbent injection are likely control 

technologies for coal-fired boilers, EPA should determine appropriate operating parameters and include them in the final rule.‖ Response to 

Comments at 1113 (emphasis added). 

16 EPA responded to the comments as follows: ―EPA disagrees because the rule recognizes common types of emissions control 

devices and names appropriate operating parameters for each. The rule allows source owners or operators flexibility to use other emissions 

control devices, subject to approval by the Administrator. The commenter is incorrect concerning types of control devices for which operating 

parameters are specified In the rule; for example, the rule addresses SNCR and ESPs, like wet scrubbers, so these controls do not need the 

Administrator's approval to select appropriate parameters.‖ Response to Comments at 1113–14 (emphasis added).

(Continued ...)
23

because dry scrubbing technology will be a common technology applicable to coal-fired boilers 

to reduce emissions of HCl or SO2, EPA should reconsider this portion of the rule and propose 

monitoring requirements for these technologies. EPA recognized the need for such provisions in 

the major source boiler rule and included the appropriate monitoring requirements. See, 76 Fed. 

Reg. at 15683, 15695-96; 40 C.F.R. Part 63, Subpart DDDDD, Table 7.

15. The 3 hour averaging time for parametric monitoring is not realistic for energy 

recovery units and should be increased to 24 hours. In addition, periods of startup need to 

be excluded from the averages to allow startup of ESPs without causing a deviation.

In the proposed CISWI rule, EPA set forth a three-hour averaging time for parametric 

monitoring. ACC commented that this is not realistic for energy recovery units, especially those 

that burn multiple fuels and have varying emissions characteristics, if those units are to preserve

their operational flexibility and ensure cost-efficient operation. Response to Comments at 708–

09. The facility must be able to operate the boiler in a manner that is responsive to process 

needs, which may not be at full load all the time. Longer averaging periods are necessary if the 

emission limits are going to apply at all times, including periods of startup, shutdown, and 

malfunction. ACC urged the use of at least daily block averages for both emissions and 

operating parameters. A 24-hour block averaging period acknowledges process variability, 

lessens the effect of short process upsets on compliance, and captures the variable emissions and 

operating characteristics of a unit over an operating day. EPA has used 24-hour block averages 

for control device parametric monitoring in other MACT rules such as the Hazardous Organic 

NESHAP (HON) (Subpart G) and the Miscellaneous Organic NESHAP (MON) (Subpart FFFF).

See, 40 C.F.R. §§ 63.152(f)(5) and 63.998(b)(3). EPA responded as follows:

In the final rule, a 30-day rolling average is used where a CEMS is used to determine 

compliance. For parameter monitoring, the final rule uses a 3-hour block average. We 

based the operating parameter 3-hour block average on the estimated sampling time 

required to perform a three run performance test under this rule.

Response to Comments at 1096. 

This response is inadequate as it does not address the comment. As we stated, many rules 

set operating parameter limit averaging time longer than the three run performance test. The 

purpose of the parametric monitoring is to assure continuous compliance. EPA is not bound to

the averaging time during a performance test. By definition, the performance test is done during 

periods of normal operation with no air pollution control device upsets or process upsets. EPA 

should reconsider this comment and set 24 hour averaging times for parametric monitoring. 

If EPA leaves the averaging time at 3 hours, many sources will shut down units that are 

having temporary problems (e.g., an ESP that is having low power issues due to a water leak into 

the ESP) to avoid a permit deviation. Once the problem is corrected, the source will re-start the 

 

(Continued ...)
24

unit, resulting in a net increase in emissions caused by the re-start. Another example of the 

problems caused by a 3 hour average is when starting up a unit coming off its annual 

maintenance outage when the ESP has been washed. Until adequate dust loading has built up in 

the ESP, maintaining the minimum power may not be possible without more hours to average 

out the initial low periods of power. This is another reason that startups should be excluded from 

the averaging periods.

16. EPA should allow emissions averaging in the CISWI rule in a manner similar to the 

major source boiler rule. 

Three major trade associations (CIBO, ACC, and AF&PA) requested in comments that 

an emissions averaging provision similar to that provided in the proposed major source boiler 

rule be included in CISWI. See, Response to Comments at 1124–26, 1127–28, and 1130–31.

EPA‘s response, set forth below in its entirety, is inadequate and not entirely correct:

Based on the limited number of comments received on this option, the concerns raised by 

state regulators on potential for increased emissions, and a review of the overall approach 

to the rule and its requirements, EPA elected not to incorporate an emissions averaging 

compliance option into the final rule. See the preamble generally for a discussion of the 

final approach on the units covered by this rule and the emission limits that apply.

Response to Comments at 1127. It is simply not true that there were a ―limited number of 

comments.‖ There were four commenters that requested emissions averaging. Three of these 

were major trade associations representing hundreds of companies that collectively represent a 

large majority of CISWI sources. While a provision such as emissions averaging may not be 

utilized by many sources, it is particularly of value to ERUs. If ERUs were allowed to use 

emission averaging the cost of this Final Rule would be reduced and ERUs could potentially 

save large sums of capital and operating expenses. It has proven to be of value in other 

NESHAP standards, and there is no good reason to deny its inclusion in the CISWI rule.

Moreover, we searched the record and it does not appear that there were any comments in 

opposition to emissions averaging. Moreover, we believe that a properly written provision 

would not create a potential for increased emissions. The emissions averaging provision in the 

HON, for example, ensures there are actually less emissions when using emissions averaging by 

applying a 10 percent discount to the emission credits and requiring an implementation plan be 

approved by the permitting authority to assure debits and credits are determined properly and 

that all appropriate performance tests, monitoring, and inspections are conducted. See, 40 CFR 

63.151(d). 

17. Parametric monitoring ranges should be set based on performance testing and allow 

use of supplemental information along with the test data. 

Section 60.2675 of the proposed rule required that operating parameter (including 

minimum pressure drop and liquid flowrate for wet scrubbers, minimum voltage and secondary 

power or total power input for electrostatic precipitators, minimum wet scrubber pH, minimum 

sorbent for dry scrubbers, minimum carbon injection rate) limits be set exclusively (using a 
25

preset fraction of the level demonstrated during the test) on operating levels for the parameters 

measured during the most recent performance test. Eastman commented that, ―It is inappropriate 

and in many cases not technically feasible to use operating conditions during a performance test, 

which are typically conducted at or near the unit‘s maximum firing rate, to establish a minimum 

requirement for all possible load ranges.‖ Response to Comments at 1111–12. Eastman urged to 

allow operating limits for parametric monitoring to be based on a combination of performance 

tests and supplemental information. Eastman went on to explain the technical basis for its 

comments:

With many pollution control technologies, this approach to establishing operating limits 

would result in needless over-consumption of sorbents at great cost to the facility with 

little or no commensurate reductions in emissions. As an example, the sorbent injection 

rate of activated carbon for the control of mercury varies with the volume of flue gas 

generated during combustion. To establish a minimum sorbent injection rate at or near 

the unit‘s maximum continuous rating (MCR) would result in nearly double the sorbent 

injection rate `during turndown to 50% load. Because institutional, commercial and 

industrial boilers vary loads widely based on site conditions, business conditions, season 

and time of day, this would result in pointless expense to the facility with no benefit to 

the environment or to human health. Other pollution control technologies cannot 

practically maintain operating conditions established at or near full load during turndown 

conditions. For example, a Spray Dryer Absorber (SDA) slurry injection rate is limited 

by the ability of the flue gas to evaporate the liquid portion of the slurry. At or near full 

load, with high flue gas flowrates and high flue gas temperatures, the flowrate of slurry

will be relatively high. If this were established as a site-specific minimum sorbent 

injection rate, the unit would inject more slurry than the flue gas could accommodate at 

low loads. Eastman has solid-fuel fired boilers equipped with SDA‘s and we have 

experienced catastrophic failures due to operation where more slurry was injected than 

the flue gas could evaporate. This operating mode caused a total shutdown of the unit that 

lasted several days and imposed considerable economic hardship (see submittal for 

Figures submitted by commenter).

Other MACT standards recognize that it is not always possible to establish these 

operating ranges solely on performance test data. The HON (40 CFR 63 Subpart G) for 

example has the following relevant provision: 40 CFR 63.152(b)(2)(ii)(A) If a 

performance test is required by this subpart for a control device, the range shall be based 

on the parameter values during the performance test and may be supplemented by 

engineering assessments and/or manufacturer‘s recommendations. Performance testing is 

not required to be conducted over the entire range of permitted parameter values. This 

type of provision allows each source to use the performance test data to then extrapolate 

operating limits based on equipment specific considerations. This is done in an operating 

plan that is submitted to the air permitting authority for review. A similar provision is 

needed in the final rule to accommodate situations such as those we have described 

above.

Id. 
26

EPA‘s response to this comment refers the reader to the preamble to the final rule,17 but 

the preamble does not contain any discussion of the issue. Therefore, EPA should reconsider 

this comment. In the related rulemaking for major source boilers, EPA responded to a similar 

comment by defining ―minimum sorbent injection rate‖ and ―minimum carbon injection rate‖ 

such that the rates vary with ―load fraction‖ (defined as the actual heat input of the boiler or 

process heater divided by the average operating load determined according to Table 7). See

EPA, Major Source Boiler Rule, Response to Comments Vol. 2 at 631-32 (citing 76 Fed. Reg. at 

15695-96; 40 C.F.R. Part 63, Subpart DDDDD, Table 7). This approach is equally applicable to 

CISWI units of all subcategories and types.

Technical Corrections/Clarifications

In reviewing the Final Rule, ACC identified a number of provisions that we believe 

require technical correction or clarification. We include them below for EPA‘s consideration 

and action.

1. 76 Fed.Reg.15765-66. In comparing final rule emission limits for new incinerators, 

Subpart CCCC, Table 5, to EPA Excel file Appendix E ―Summary Table‖ sheet, the 

following two limits are significantly different:

 SO2- the 99.0% UL in Appendix E is 39.5 ppmvd compared to the Table 5 limit 

of 11 ppmvd.

 D/F TEQ- the 99.0% UL in Appendix E is 2.5 ng/dscm at 7% O2 compared to the 

Table 5 limit of 0.13 ng/dscm.

The D/F total Mass values are also different, but in the opposite direction (not as drastic): 0.023 

ng/dscm in Appendix E compared to 0.052 ng/dscm in final rule Table 5. These values appear to 

require technical corrections (assuming the Appendix data is correct) since EPA‘s conclusions in 

the spreadsheet calculations are not reflected accurately in the final rule in these cases.

All limits for existing incinerators are reasonably comparable between the final rule Subpart 

DDDD Table 6 and Appendix C.

2. 76 Fed.Reg.15766. Table 6 does not include a CO limit for new coal fired energy 

recovery units. It is listed in the ―Liquid/Gas‖ column of the table, which we believe is 

incorrect. We believe it needs to be listed in the ―Solids‖ column.

3. Subpart CCCC, § 60.2265 and Subpart DDDD, § 60.2875. EPA added definitions in the 

final rules for ―Burn-off oven,‖ ―Chemical recovery unit,‖ ―Cyclonic burn barrel‖, and 

―Laboratory analysis unit.‖ Part of the purpose of these definitions is to clarify that they 

are not units subject to the requirements of the rules. The following sentence was 

included in the definitions of ―Burn-off oven:

 

17

Response to Comments at 1112, 1104.
27

―A burn-off oven is not an incinerator, waste burning kiln, an energy 

recovery unit or a small, remote incinerator under this subpart.‖

The definitions of ―Cyclonic burn barrel‖ and ―Laboratory analysis unit‖ include similar 

wording. However, the definition for ―Chemical recovery unit‖ does not include this 

sentence relative to those units. The following sentence needs to be added to the 

―Chemical recovery unit‖ definition in § 60.2265 (Subpart CCCC) and § 60.2875 

(Subpart DDDD) in order to provide consistency and avoid confusion: ―A Chemical 

recovery unit is not an incinerator, waste burning kiln, and energy recovery unit, or a 

small, remote incinerator under this subpart.‖

4. For both Subpart CCCC and Subpart DDDD, EPA finalized QA/QC requirements for 

several types of parameter monitors. One of the types of devices was for measuring pH. 

There seems to be an error in § 60.2710(o) and (n) in that one repeats the other and both 

relate to pressure devices. When compared to the analogous section in Subpart CCCC, it 

seems that paragraph (o) was supposed to be for pH devices.
28

Attachment 1

Comparison of Major Source Boiler Rule (BMACT) and CISWI Emission Limits

HAP/Fuel Major Boiler Rule Limits CISWI Rule Limits for ERUs Higher Limit

Final Final Units Final Final Units

Existing New Existing New Existing 

Sources

New 

Sources

Hg Biomass 4.6 3.5 lb/TBtu 0.29 0.29 lb/TBtu BMACT BMACT

PM Biomass 0.039 0.0011 lb/MMBtu 0.22 0.22 lb/MMBtu CISWI CISWI

HCl Biomass 0.035 0.0022 lb/MMBtu 0.00059 0.00059 lb/MMBtu BMACT BMACT

Hg Coal 4.6 3.5 lb/TBtu 0.30 0.30 lb/TBtu BMACT BMACT

PM Coal 0.039 0.0011 lb/MMBtu 0.23 0.23 lb/MMBtu CISWI CISWI

HCl Coal 0.035 0.0022 lb/MMBtu 0.00063 0.00063 lb/MMBtu BMACT BMACT

Hg Oil 3.5 0.21 lb/TBtu 1.12 0.22 lb/TBtu BMACT CISWI

Hg Oil noncontinental 0.78 0.78

lb/TBtu 1.12 0.22 lb/TBtu CISWI BMACT

PM Oil 0.0075 0.0013 lb/MMBtu 0.095 0.095 lb/MMBtu CISWI CISWI

HCl Oil 0.00033 0.00033 lb/MMBtu 0.018 0.018 lb/MMBtu CISWI CISWI

Hg Gas 2 13 7.9 lb/TBtu 1.06 0.20 lb/TBtu BMACT BMACT

PM Gas 2 0.043 0.0067 lb/MMBtu 0.090 0.090 lb/MMBtu CISWI CISWI

HCl Gas 2 0.0017 0.0017 lb/MMBtu 0.017 0.017 lb/MMBtu CISWI CISWI

CO Biomass stoker 490 160

ppm at 3%O2

631 206

ppm at 3%O2 CISWI CISWI

CO Biomass FB 430 260 ppm at 3%O2 631 206 ppm at 3%O2 CISWI BMACT

CO Biomass 

Dutch/ Suspension 470 470

ppm at 3%O2

631 206

ppm at 3%O2 CISWI BMACT

CO Biomass Fuel 

Cell 690 470

ppm at 3%O2

631 206

ppm at 3%O2 BMACT BMACT

CO Biomass 

Hybrid Suspension/ 

Grate

3500 1500

ppm at 3%O2

631 206

ppm at 3%O2 BMACT BMACT

CO Coal pulverized 160 12

ppm at 3%O2

76 59

ppm at 3%O2 BMACT CISWI

CO Coal stoker 270 6 ppm at 3%O2 76 59 ppm at 3%O2 BMACT CISWI

CO Coal FB 82 18 ppm at 3%O2 76 59 ppm at 3%O2 BMACT CISWI

CO Oil 10 3 ppm at 3%O2 46 46 ppm at 3%O2 CISWI CISWI

CO Oil noncontinental 160 51

ppm at 3%O2 46 46 ppm at 3%O2 BMACT BMACT
29

HAP/Fuel Major Boiler Rule Limits CISWI Rule Limits for ERUs Higher Limit

CO Gas2 9 3 ppm at 3%O2 46 46 ppm at 3%O2 CISWI CISWI

D/F Biomass stoker 0.005 0.005 ng TEQ/dscm 

at 7%O2

0.059 0.011 ng TEQ/dscm 

at 7%O2 CISWI CISWI

D/F Biomass FB 0.02 0.02 ng TEQ/dscm 

at 7%O2

0.059 0.011 ng TEQ/dscm 

at 7%O2 CISWI BMACT

D/F Biomass 

Dutch/ Suspension 0.2 0.2 ng TEQ/dscm 

at 7%O2

0.059 0.011 ng TEQ/dscm 

at 7%O2 BMACT BMACT

D/F Biomass Fuel 

Cell 4 0.003 ng TEQ/dscm 

at 7%O2

0.059 0.011 ng TEQ/dscm 

at 7%O2 BMACT CISWI

D/F Biomass 

Hybrid 

Suspension/Grate

0.2 0.2

ng TEQ/dscm 

at 7%O2

0.059 0.011

ng TEQ/dscm 

at 7%O2 BMACT BMACT

D/F Coal 

pulverized 0.004 0.003 ng TEQ/dscm 

at 7%O2

0.059 0.011 ng TEQ/dscm 

at 7%O2 CISWI CISWI

D/F Coal stoker 0.003 0.003 ng TEQ/dscm 

at 7%O2

0.059 0.011 ng TEQ/dscm 

at 7%O2 CISWI CISWI

D/F Coal FB 0.002 0.002 ng TEQ/dscm 

at 7%O2

0.059 0.011 ng TEQ/dscm 

at 7%O2 CISWI CISWI

D/F Oil 4 0.002 ng TEQ/dscm 

at 7%O2 0.320 0.002

ng TEQ/dscm 

at 7%O2 MACT CISWI

D/F Gas2 0.08 0.08 ng TEQ/dscm 

at 7%O2 0.320 0.002

ng TEQ/dscm 

at 7%O2 CISWI BMACT