1

EPA's Responses to Public Comments on EPA's National Emission 

Standards for Hazardous Air Pollutants for Major Source Industrial 

Commercial Institutional Boilers and Process Heaters

Chapter 11

(Missing from Original Volume 2 EPA-HQ-OAR-2002-0058-3289)

Comments letters and transcripts of the public hearings are also available electronically through 

http://www.regulations.gov by searching Docket ID EPA-HQ-OAR-2002-0058.
2

FOREWORD 

This document provides EPA's responses to public comments on EPA's Proposed National 

Emission Standards for Hazardous Air Pollutants for Major Source Industrial Commercial

Institutional Boilers and Process Heaters. EPA published a Notice of Proposed Rulemaking in the 

Federal Register on June 4, 2010 at 75 FR 32005. EPA received comments on this proposed rule 

via mail, e-mail, facsimile, and at three public hearings held in Washington, DC, Houston, Texas, 

and Los Angeles, California in June 2010. Copies of all comments submitted and transcripts for the 

public hearings are available at the EPA Docket Center Public Reading Room. Comments letters and 

transcripts of the public hearings are also available electronically through http://www.regulations.gov 

by searching Docket ID EPA-HQ-OAR-2002-0058. 

Due to the size and scope of this rulemaking, EPA paraphrased a limited amount of major comment 

themes in the preamble of the final rule. This document contains the verbatim comments 

provided by each commenter extracted from the original letter or public hearing transcript.

Several of EPA's responses to comments are provided immediately following each comment 

excerpt. However, in instances where several commenters raised similar or related issues, EPA 

has grouped these comments together and provided a single response after the first comment 

excerpt in the group and referenced this response in the other comment excerpts. In some cases, 

EPA provided responses to specific comments or groups of similar comments in the Preamble to 

the final rulemaking. Rather than repeating those responses in this document, EPA has 

referenced the Preamble or the appropriate technical support document for a description of the 

analysis included in the final rule. In other cases EPA has provided a general response at the 

beginning of each section of this document.

Parallel with this rulemaking effort are three separate, but related rulemakings that may be of 

interest to stakeholders. These three rules are: National Emission Standards for Hazardous Air 

Pollutants for Area Source Industrial/Commercial/Institutional Boilers (Docket ID: EPA-HQOAR-2006-0790); Identification of Non-Hazardous Secondary Materials That Are Solid Waste

(Docket ID: EPA-HQ-RCRA-2008-0329); and Standards of Performance for New

Stationary Sources and Emission Guidelines for Existing Sources: Commercial and Industrial 

Solid Waste Incineration Units (Docket ID: EPA–HQ–OAR–2003–0119). 

Given the identical proposal dates, and the related nature of these other rules, many commenters 

submitted comments to this rulemaking docket that were specific to one of these related 

rulemakings. Some commenters submitted a single DCN with comments on all four rules while 

others submitted a separate DCN specific to each rule. Many commenters submitted identical 

comments to all of these dockets. In order to reduce duplicative comments, this document flags 

comments associated with any of the above three related rulemakings as out-of-scope comments 

for this response to comment document. To the extent that the commenter submitted these 

comments to the appropriate rulemaking document, responses have been developed in the 

response to comment documents for each of these related rulemakings. For this reason, EPA 

encourages the public to read the other response to comment documents prepared for these three 

other rulemakings as they may contain topics relevant to these other rulemakings. 
3

Table of Contents

Testing and Monitoring................................................................................................................... 4

Stack Test Methods..................................................................................................................... 4

CEMS: General......................................................................................................................... 38

CO CEMS................................................................................................................................. 62

PM CEMS............................................................................................................................... 107

COMS (opacity)...................................................................................................................... 179

Averaging Times for Monitored Pollutants............................................................................ 185

Fuel Analysis Methods ........................................................................................................... 197

Detection Levels ..................................................................................................................... 227

Measurement Methodology Impractical................................................................................. 271

Reduced Testing Allowance ................................................................................................... 273

Compliance Flexibility for Small Entities.............................................................................. 293

Operating Parameter Monitoring ............................................................................................ 296

Other - Testing and Monitoring .............................................................................................. 374
4

Testing and Monitoring

Stack Test Methods

Commenter Name: Dwayne Arino

Commenter Affiliation: Jeld-Wen, Inc

Document Control Number: EPA-HQ-OAR-2002-0058-0856.1

Comment Excerpt Number: 4

Comment: In consideration of the concern of the reliability of OTM 28, if EPA’s approved 

testing method (OTM 28) is recognized to contain problems in extracting particulate matter from 

an emission stream is the data provided by the sources in this category reliable? 

Response: EPA must base the floors on the data provided to the Agency. We have made several 

corrections to data submitted but determined that a general exclusion of all OTM 28 data is 

inappropriate in this case. The commenter did not provide specific instances of where the test 

report or results of OTM 28 were inappropriate for the standard-setting process.

Commenter Name: Carter Strickland, Jr

Commenter Affiliation: New York City Department of Environmental Protection

Document Control Number: EPA-HQ-OAR-2002-0058-1600.1

Comment Excerpt Number: 4

Comment: Allow for additional test methods. The EPA should adopt economical test methods 

such as the use of handheld devices. According to stack testing laboratories in the City, relatively 

inexpensive handheld meters are not currently acceptable for NESHAP compliance tests. Cost 

information obtained by DEP indicates the annual cost using approved methods for particulate 

matter, mercury, hydrogen chloride, carbon monoxide, dioxins, and furans will be approximately 

$100,000 for a boiler in a major source. 

Response: EPA disagrees that handheld devices should be used for compliance testing of major 

source boilers. The limits are based on measurement with EPA stack testing methods, and 

equivalency of the handheld devices has not been established. Furthermore, handheld devices 

are not available for all of the pollutants for which measurement is required. Finally, it should be 

noted that EPA has lessened the testing costs associated with the final rule through changes to 

CO monitoring requirements, the dioxin testing requirements, and a provision allowing for skip 

testing for certain units.

Commenter Name: Michael L. Steele

Commenter Affiliation: CraftMaster Manufacturing, Inc
5

Document Control Number: EPA-HQ-OAR-2002-0058-1907.1

Comment Excerpt Number: 8

Comment: Test Run Duration §63.7S20(d) 

The proposed rules specify that each test run must last at least four (4) hours. Testing should be 

performed per the applicable USEPA test method. One hour test runs are specified in many of 

the USEPA methods. 

MACT Floor data is based on three at 1-hour test runs. Limits should be consistent with their 

bases. 

Response: We agree with commenters that the rule must clarify minimum sample volumes and 

assure that the specifications are consistent between test methods and with the method 

capabilities. The correct approach to measuring low quantities of emissions is to specify 

collection of a minimum sample volume that assures accuracy sufficient to determine 

compliance at the level of the emissions standard. EPA has adjusted the sampling times and 

volumes in the final rule to be specific to the pollutant and desired detection levels needed to

demonstrate compliance with each emission limit. Four-hour testing is no longer required across 

the board. EPA has retained four-hour sampling times for the one-time dioxin/furan testing. 

Refer to Tables 1, 2 and 12 of the final rule for revised sampling times. 

Commenter Name: Jack Carter

Commenter Affiliation: Weyerhaeuser Company

Document Control Number: EPA-HQ-OAR-2002-0058-2797.1

Comment Excerpt Number: 21

Comment: The performance testing requirements need to be more clear (e.g. as the AWC and 

AF&PA comments note, what does EPA mean by “normal maximum” operating rate?). And the 

combination of multiple HAP worst case fuels and longer run times (i.e., the 4 hour requirement, 

which EPA should make clear is not necessary in all cases) may require some of our facilities 

with combination boilers to stockpile certain fuels just for test purposes and then run their boilers 

for long periods at steaming rates inappropriate for their current production schedules and 

unsustainable for some boilers. This may create operational problems, and in any case will waste 

fuels, energy, and money and, unnecessarily emit higher levels of HAPs. As proposed, EPA’s 

performance testing requirements have the potential to be the “tail wagging the dog.” 

For example, the proposed PM emission standards are so low that EPA has specified 4-hour test 

runs to demonstrate compliance with the standard. This may create significant challenges to 

facilities because they may not be able to maintain the maximum fuel firing rate for a four hour 

period in order to demonstrate compliance with the standard. If, as an alternative, a facility 

requests shorter duration runs to test for demonstrating compliance, the mass of PM collected 

may be below the quantitation limit of the test method, which would make it impossible to 
6

demonstrate compliance with the standard. As a solution, EPA could either set the PM emission 

standards based on shorter runs and method quantitation limits or provide relief in the test 

program on the boiler fuel firing rate. For example, EPA could set the firing rate a more 

reasonable average of 80-85 percent of maximum rate for the 4-hour duration of the test, or for 

more flexibility allow the permitting agency and facility to establish the appropriate rate for the 

specific boiler application. 

Response: EPA has clarified the requirements for performance testing, including a requirement 

that testing be conducted at representative operating load conditions. This allows sources 

additional flexibility, although sources need to operate within 10 percent of their planned 

maximum operating load so that the compliance test will demonstrate that they can meet the 

required levels while combusting the maximum amount of fuel. EPA also clarified that worst 

case fuels should be tested for HCl and for Hg, and recognizes that this requirement could result 

in more than one test being conducted. Also, EPA has specified required sample volumes for the 

emission test methods.

Commenter Name: Britt S. Fleming

Commenter Affiliation: Auto Group

Document Control Number: EPA-HQ-OAR-2002-0058-2775.1

Comment Excerpt Number: 45

Comment: Proposed § 63.7520(e), which requires use of F-Factors from EPA Method 19, 

Sections 12.2 and 12.3. Table 19-2 shows “default” F-Factors for several fuel types; however, 

there is no default F-Factor for landfill gas. This may be due in part to the fact that landfill gas 

can vary from landfill to landfill and even within the same landfill over time. 

Response: Reference Method 19 includes procedures for determining a site specific F-factor, or 

an F-factor for a fuel like landfill gas that is not listed in Table 19.2 (see Section 12.3.2 of 

Reference Method 19) .

Commenter Name: Stephen R. Gossett

Commenter Affiliation: Eastman Chemical Company

Document Control Number: EPA-HQ-OAR-2002-0058-3137.1

Comment Excerpt Number: 57

Comment: As far as we know, the only rationale for 4 hour runs is to achieve detection limits 

lower that the extremely low D/F standard proposed. From our experience, one to two hour test 

runs will be adequate to demonstrate compliance with the proposed emission standards for PM, 

HCl, and Hg. Rather than dictate a minimum run time, EPA should specify minimum sample 

volumes. 
7

Response: See response to EPA-HQ-OAR-2002-0058-1907.1, Comment Excerpt Number 8. 

Commenter Name: Britt S. Fleming

Commenter Affiliation: Auto Group

Document Control Number: EPA-HQ-OAR-2002-0058-2775.1

Comment Excerpt Number: 62

Comment: Proposed § 63.7520(d) – This provision requires three (3) four-hour test runs during 

a performance test. Increasing test run times from one hour to four hours will significantly 

increase the costs associated with stack testing. This provision raises the question as to whether 

the standard test methods are adequate for measuring the pollutants EPA is regulating at such 

low levels. If a source has emissions that are too low to detect with current approved or 

promulgated sampling methods, this might be an indication that the limits are so low as to be 

impractical to regulate and impossible to accurately test. Increasing the sample time for each run 

to four hours also may not be possible for some sources since industrial and commercial boilers 

may not have adequate demand or vent enough steam to operate at sufficient load through the 

three runs. 

Response: See response to EPA-HQ-OAR-2002-0058-1907.1, Comment Excerpt Number 8.

Commenter Name: Timothy Hunt

Commenter Affiliation: American Forest and Paper Association (AF&PA)

Document Control Number: EPA-HQ-OAR-2002-0058-3213.1

Comment Excerpt Number: 282

Comment: EPA proposes to require each stack test run to last at least 4 hours (see 63.7520(d)). 

While we agree that the limits in this rule may require sampling times of at least 4 hours for 

mercury and dioxin/furan, we do not agree that 4 hour runs are appropriate in all cases for PM, 

CO, and HCl. In addition, load-following boilers may not be able to sustain maximum normal 

operating load for 3 4-hour test runs. EPA should instead require a minimum sample volume or 

minimum mass be collected. 

Response: See response to EPA-HQ-OAR-2002-0058-1907.1, Comment Excerpt Number 8.

Commenter Name: Timothy Hunt
8

Commenter Affiliation: American Forest and Paper Association (AF&PA)

Document Control Number: EPA-HQ-OAR-2002-0058-3213.1

Comment Excerpt Number: 283

Comment: Table 5 of the proposed rule contains the performance testing requirements and 

acceptable test methods. Mercury emissions testing needs to include EPA Method 30B - Sorbent 

Trap Method as well as an option to include a certified continuous mercury emissions monitor 

(CEMS). Equipment vendors have communicated that Method 29 and Ontario Hydro are not 

considered accurate enough for them to guarantee mercury control performance at the extremely 

low proposed emission limit levels. These are standard tests utilized by the electric utility 

industry for mercury compliance measurements and Method 30B is allowed under the proposed 

CISWI rule (see Table 6 of 40 CFR 60, Subparts CCCC and DDDD, at 75 FR 31986 and 32001). 

Response: The final rule will include EPA Methods 30A and 30B.

Commenter Name: Randall D. Quintrell

Commenter Affiliation: Georgia Paper and Forest Products Association, GPFPA

Document Control Number: EPA-HQ-OAR-2002-0058-2905

Comment Excerpt Number: 8

Comment: The Rule also proposes excessive and unreasonable test methods, test duration and 

testing conditions. A good example of this is in the PM testing requirement. For the PM 

standards, the bulk of data available for PM emissions evaluation and determination of the floor 

is based on testing using of the standard EPA Method 5. This test consists of three one-hour runs 

for a total of three hours testing time. However, the Rule proposes three four-hour runs for a total 

of 12 hours testing time. This means the test requires drawing 4 times the sample volume 

through the filter. The stated rationale is to have the test method correspond to the averaging 

period and provide a 12-hour averaging period. This reasoning is problematic in several regards. 

First, it ignores the fact that longer sampling runs may result in artificially higher PM values 

compared to the database data that were used to set the standard. Many of the low end test results 

used in the floor evaluation were at or below the quantitation limit of 6 mg filter catch. By 

adjusting the test to pull 4 times the sample volume through the filter medium higher PM 

retention rates occur, making the emission rates seem higher, when in fact they are not. This is an 

even greater problem for high moisture sources, which are very common among the affected 

units. 

EPA’s apparent justification for the longer test times is the fact that at the proposed emission 

levels, the PM emissions may be below the quantitation level for the standard Method 5 test. 

EPA’s way of addressing this is to extend the testing time to collect more sample. Unfortunately, 

the test data upon which the standard is based are all Method 5 data. This means the low end 

source data were below the PQL and are unreliable data. The PM limits should be re-evaluated, 

substituting 6mg (the PQL) for any data that were less than 6 mg to develop valid floor data. One 

solution would be for any PM tests with filter catch below the quantitation limit, both in the floor 
9

data and subsequent performance test data, to have the data reported at the PQL value of 6 mg so 

the problem with shorter Method 5 runs is overcome. In any event, the performance test method 

should certainly match the method used to establish the emission floors for a true comparison of 

emission rates. 

Response: See response to EPA-HQ-OAR-2002-0058-1907.1, Comment Excerpt Number 8.

Also, we recognize that uncertainty of the measurement may gradually increase at particulate 

matter (PM) catch levels below 5 mg. We have taken this uncertainty (variability) into account in 

setting the standard. Refer to the preamble for a discussion of the three times detection level 

analysis that was conducted on emissions data reported below the MDL.

Commenter Name: Randall D. Quintrell

Commenter Affiliation: Georgia Paper and Forest Products Association, GPFPA

Document Control Number: EPA-HQ-OAR-2002-0058-2905

Comment Excerpt Number: 10

Comment: If EPA insists that the testing and averaging period be the same then the requirement 

to maintain "normal maximum" firing rates must be dropped and "representative average" should 

be used as the testing criterion instead. This would allow more flexibility in situations where 

conditions at the boiler suddenly change in the middle of a run - a scenario that often occurs even 

in current Method 5 testing. Under the current proposal, if the boiler load suddenly drops and 

does not average near the "normal maximum" operating rate targeted, 4 hours of testing may 

have to be discarded instead of just one hour. This significantly increases the difficulty of testing, 

as well as the cost and the logistical problems in maintaining or restoring target loads for 

extended periods of time. As EPA has been advised repeatedly, industrial boilers in the pulp and 

paper industry, as in most manufacturing operations, are load following boilers. For those 

facilities with only one or two boilers that supply the entire facility, any sudden change in 

operation such as a paper break or other unexpected interruption of production causes significant 

swings in the steam demand and thus the load on the boilers. There is simply insufficient load 

swapping capability to handle these changes and maintain maximum normal operating load. 

Completing a single test (12 hours of sampling) will take a minimum of two days even if all goes 

very well, and more realistically, it will take three days for a single test. If things do not go well, 

it could take much longer for a single test. On top of this, there may be problems with 

availability of the testing firm to stay for the duration if problems do occur. Multiply this by the 

number of units to be tested and the number of other test parameters required and the excessive 

burden becomes readily evident. Because of this unreasonable burden, testing should be limited 

to an IPT and the test conditions should be modified to a "representative average" instead of a 

"normal maximum" for the entire test. Such a change in load conditions would be consistent with 

EPA’s floor development. For example, the baseline data upon which EPA developed the limits 

were not at maximum load with maximum fuel for mercury. Mills in the study used typical fuels 

for typical steam flows. These facts bias the results to the low side for establishing limits while 
10

using maximum rates and worst case mix biases the results to the high side for compliance 

monitoring. This creates an unacceptable dilemma. 

Response: EPA has changed the requirement to representative operating load conditions. 

However, the boiler load during the performance test will be used to establish an operating limit, 

which requires that units operate at no more than 110% of the load during the test, on a 12-hour 

block average basis. See response to EPA-HQ-OAR-2002-0058-1907.1, comment excerpt 

number 8 in response to four hour testing.

Commenter Name: Walter Tyler

Commenter Affiliation: Invista

Document Control Number: EPA-HQ-OAR-2002-0058-2761.1

Comment Excerpt Number: 11

Comment: This proposal would require an anticipated three-day testing event for each 

individual emission unit subject to the Boiler MACT. All five compounds (PM, HCl, Hg, CO, 

Dioxin/Furan) cannot be tested simultaneously. Based on input from a stack testing contractor, 

the typical number of compounds that can be tested simultaneously would be four. Thus, at a 

minimum, a single emission unit must be tested for six 4-hour periods which, at best, could occur 

in two consecutive days. More likely it will need to extend across three separate operating days 

for each emission unit to be tested. 

Stack testing completed with the more traditional three 1-hour runs (for all pollutants but 

Dioxin/Furan) could be completed at roughly one half the cost. Overall, this longer testing 

requirement would result in a significant cost burden to the affected facility without additional 

environmental benefit. Accordingly, INVISTA recommends that EPA reconsider this lengthy 

testing period and replace it with the more traditional 1-hour test runs for PM, HCl, Hg, and CO. 

Response: See response to EPA-HQ-OAR-2002-0058-1907.1, Comment Excerpt Number 8.

Commenter Name: Randall D. Quintrell

Commenter Affiliation: Georgia Paper and Forest Products Association, GPFPA

Document Control Number: EPA-HQ-OAR-2002-0058-2905

Comment Excerpt Number: 17

Comment: On page 32052 of the Federal Register, EPA notes: You must conduct each 

performance stack test under the specific conditions listed in Tables 5 and 7 to this subpart. You 

must conduct performance stack tests at the maximum normal operating load while burning the 

type of fuel or mixture of fuels that has the highest content of chlorine and mercury, and you 

must demonstrate initial compliance and establish your operating limits based on these tests. 

These requirements could result in the need to conduct more than one performance test. 
11

The basic logistics of these proposed testing requirements can be extremely difficult, time 

consuming, and costly especially with the proposed 10 month frequency, with testing for all 5 

parameters on all sources, even those known to have very low emissions, at high loading rates 

and under multiple "worst case" fuel mixes for the different pollutants. These criteria are also not 

consistent with many of the test conditions used to develop the data that were used in setting the 

standards. 

As EPA has been advised repeatedly, industrial boilers are typically load following boilers with a 

wide range of normal operation depending on facility operations. The variations can be caused 

by production rates that are mandated by market needs and customer schedules, by grade 

changes, by production upsets or equipment downtime, or even normal process cycles. In an 

integrated facility like a paper mill, there are many batch processes that have different cycles, 

causing irregular steam demand, and different product grades that significantly impact steam and 

electrical demand. It would be impossible to schedule production to meet a stack test schedule 

that has to be arranged at least 60 days in advance to try to accommodate "maximum" normal 

loads. 

What does EPA intend by "maximum normal operating load"? How is this to be managed for a 

test duration that will of necessity have to cover a minimum of 2 days to get 3 four-hour runs? 

We believe the intent is to run the unit at the high end of normal operating rates (e.g., averaging 

80% of a typical 24-hour maximum loading scenario, or testing at a rate greater than the annual 

average loading). Anything more stringent would be unworkable given the onerous frequency 

and time consuming testing requirements in the proposed Rule which, when combined with mill 

operational variability, could prevent maintaining higher loads throughout the extended test 

duration. For boilers with a low annual capacity limit but a high short term capacity, we believe 

the only workable test condition would be similar, e.g., 80% of a typical high 24-hour operating 

rate or alternately, some rate greater than the annual average coal firing rate. This should be 

clarified in the final Rule. We recommend that the firing rate requirement be changed to 

"representative average load" as discussed elsewhere in these comments and defined as being at 

or above the annual average load operated for the fuels being tested. 

Response: See response to EPA-HQ-OAR-2002-0058-2905, Comment Excerpt Number 10.

Commenter Name: Robert D. Morrison

Commenter Affiliation: Abbott Laboratories

Document Control Number: EPA-HQ-OAR-2002-0058-2764.1

Comment Excerpt Number: 25

Comment: Additional alternatives should be provided for stack testing and data reduction 

procedures for HCl (40 CFR 63.7520 and Table 5). The proposed Boiler MACT standard offers 

two alternative testing methods for HCl that are based essentially on one emission testing 

methodology – “wet” chemical Methods 26 and 26a. However, in the test program required by 

USEPA’s 2009 Section 114 request, Method 320 (instrumental sampling via FTIR) was accepted 

as an alternative. Abbott’s experience with Method 26 for HCl from a coal-fired unit has been 
12

inconsistent and subject to interferences. Abbott’s recent experience with the FTIR method was 

good. This would offer another alternative if Method 26 or 26a is limited by test interference or 

other testing problems. The performance testing requirement for HCl should provide this 

alternative. (In principle, an alternative test method could be requested and approved through the 

provisions of 40 CFR 63.7(f) for approval of an alternative test method. However, this 

mechanism is cumbersome, time consuming, and labor intensive for both USEPA and the 

facility.) 

Response: We disagree with the commenter suggestion to include the FTIR Method 320. 

Method selection is critical when measuring compliance with HCl emissions limits as low as the 

proposed values, therefore EPA has specified Method 26 or 26A for this purpose. These wet 

chemistry methods with suitable sampling collection periods have minimum detection levels 

lower than does Method 320 or Method 321 using the currently available technology. 

Commenter Name: David A. Buff

Commenter Affiliation: Golder Associates Inc

Document Control Number: EPA-HQ-OAR-2002-0058-2801.1

Comment Excerpt Number: 56

Comment: The FSI has the following comments regarding the performance testing provisions in 

the proposed rule: 

The proposed rule requires 4-hour test runs for all pollutants. This length of stack testing is 

unnecessary, and was not required in the ICR Phase 2 for all pollutants, and was not required in 

the area source Industrial Boiler MACT (GACT) rule. The source testing required by the 

proposed rule (PM, metals, HCl, Hg and D/F) will require up to a week to perform for one boiler, 

due to the different sampling trains that must be used. This will be extremely costly for a facility 

that has 5 or 6 boilers (like FSI sugar mills). Also, a source may not have sufficient quantities of 

worst case fuel to conduct the tests over this long of a period. A different worst case fuel may be 

needed for each pollutant or group of pollutants. 

Response: See response to EPA-HQ-OAR-2002-0058-1907.1, Comment Excerpt Number 8.

Commenter Name: David A. Buff

Commenter Affiliation: Golder Associates Inc

Document Control Number: EPA-HQ-OAR-2002-0058-2801.1

Comment Excerpt Number: 61

Comment: Need to include additional test methods (e.g., Method 5B for PM, sorbent traps for 

Hg) 
13

Response: The final rule includes Methods 5 and 17 for PM, but not Method 5B. A source 

wishing to use Method 5B will need to apply for an alternative testing procedure per Section 

63.7(f). The final rule includes the additional test method cited for mercury, Method 30B 

(Sorbent Trap Method).

Commenter Name: Robert D. Bessette

Commenter Affiliation: Council of Industrial Boiler Owners (CIBO)

Document Control Number: EPA-HQ-OAR-2002-0058-2702.1

Comment Excerpt Number: 136

Comment: As discussed elsewhere in these comments, CIBO does not believe D/F standards 

should be set at this time. As far as we know, the only rationale for 4 hour runs is to achieve 

detection limits lower that the extremely low D/F standard proposed. From our experience, one 

hour test runs will be adequate to demonstrate compliance with the proposed emission standards 

for PM, HCl, and Hg. 

Response: EPA has adjusted the sampling times and volumes in the final rule to be specific to 

the pollutant and desired detection levels needed to demonstrate compliance with each emission 

limit. Four-hour testing is no longer required across the board. EPA has retained four-hour 

sampling times for the one-time dioxin/furan testing. Refer to Tables 1, 2 and 12 of the final rule 

for revised sampling times.

Commenter Name: Robert D. Bessette

Commenter Affiliation: Council of Industrial Boiler Owners (CIBO)

Document Control Number: EPA-HQ-OAR-2002-0058-2702.1

Comment Excerpt Number: 137

Comment: Inaccuracies and Other Emissions Testing Methods For Final Rule. 

The language in the Proposed Rule referencing the a "summary of the results of the performance 

tests" is inconsistent. Specifically, proposed §§ 63.7550(c)(5) and 63.7555(d)(6) refer to 90 

percent emission limit threshold, while the proposed § 63.7515(b)-(c) refer to 75 percent of the 

emission limit. See 75 FR 32051 and 32061. EPA should include in the final rule specifications 

for minimum collection quantity and minimum test time for each test method. In addition, the 

final rule needs to specify how to handle detection levels and reporting of data that is detection 

level limited relative to compliance with emission limits. 

EPA should include in the final rule additional options for mercury emissions testing. The 

Ontario Hydro Method is not considered accurate enough to guarantee mercury control 

performance at the extremely low proposed emission limit levels. Therefore, CIBO recommends 
14

that mercury emissions testing include Method 30A (Instrumental Analyzer) and 30B (Sorbent 

Trap Method). Finally, for units without PM CEMS, EPA should allow M5B for PM when using 

a wet scrubber. 

Response: Thank you for pointing out the inconsistency. EPA has corrected §§ 63.7550(c)(5) 

and 63.7555(d)(6) by changing 90 percent to 75 percent. Also, the final rule reflects changes 

regarding minimum sampling volumes, and includes the additional test methods cited for 

mercury.

The final rule includes EPA Methods 30 A and 30B. A source wishing to use Method 5B will 

need to apply for an alternative testing procedure per Section 63.7(f). Refer to comment EPAHQ-OAR-2002-0058-3213.1 excerpt 89 for further information on treatment and reporting of 

detection limits.

Commenter Name: Matthew Todd and David Friedman

Commenter Affiliation: American Petroleum Institute (API) and National Petrochemical and 

Refiners Association (NPRA)

Document Control Number: EPA-HQ-OAR-2002-0058-2960.1

Comment Excerpt Number: 165

Comment: 63.7515(a) requires annual performance tests for all units with applicable emission 

limits (except alternately Cl and Hg may be measured monthly in the fuel). Requiring annual 

performance tests for units and pollutants where CO or PM CEMS are installed is unreasonable 

and duplicative and this proposed requirement should be deleted for those situations. The 

requirement to perform annual stack tests for boilers and process heaters where continuous 

monitoring is required may, in fact, not be what the Agency intended and may be an oversight in 

the drafting of 63.7515(a). 

Recommendation: Revise 63.7515(a) to exclude boilers and process heaters with CO or PM 

CEMS from the annual performance test requirement. 

Response: For CO, the rule no longer requires a CO CEMS. For PM CEMS, section 63.7510(d) 

exempts sources from stack testing and operational limits, with the initial and ongoing CEMS 

performance testing serving as the applicable requirements. Because initial stack testing is not 

required, annual stack testing under section 63.7515 is not “applicable.”

Commenter Name: Matthew Todd and David Friedman

Commenter Affiliation: American Petroleum Institute (API) and National Petrochemical and 

Refiners Association (NPRA)

Document Control Number: EPA-HQ-OAR-2002-0058-2960.1

Comment Excerpt Number: 168
15

Comment: According to proposed 63.7525(c), stack tests must be performed at maximum 

normal operating load. This will require the boiler or process heater to be at that particular rate 

for a significant part of a day (e.g., 12+ hours). This has several potential consequences that do 

not appear to have been considered. If the boiler or process heater is not needed to run at these 

high rates, fuel will be wasted, for boilers excess steam or hot water will have to be vented to the 

atmosphere and extra CO2 and pollutants will be emitted and for process heaters, process 

operations will be upset and all combustion devices associated with the process will usually have 

to be operated at high rates whenever any of them are being tested, thus emitting additional 

unnecessary CO2, criteria pollutants and HAPs. For standby and emergency boilers and process 

heaters, essentially all the firing during the test period would be waste and all pollutants emitted 

would be excess. 

We are particularly concerned about having to upset process operations to test boilers and 

process heaters. Regardless of the testing frequency, it is unreasonable to require processes be 

upset and operations changed and be unoptimzed in order to perform a stack test that provides 

questionable value. 

Recommendation: For any repetitive performance test requirement, the test should be allowed to 

be deferred until the boiler or process heater is operating at least at 80% of capacity for 

operational reasons. If such a provision is not provided EPA must estimate the excess emissions 

generated as a result of not providing this relief and incorporate that estimate of excess emissions 

in the record and all associated regulatory analyses. If such a provision is not provided, the final 

rule must also specifically specify that the general duty requirement in 63.6 to minimize 

emissions does not apply for EPA mandated performance tests, since it certainly is not consistent 

with good air pollution practice to generate unnecessary emissions by doing unnecessary 

performance tests. 

Response: EPA has changed the requirement to representative operating load conditions. 

However, the boiler load during the performance test will be used to establish an operating limit, 

which requires that units operate at no more than 110% of the load during the test, on a 12-hour 

block average basis. In the final rule, EPA has adopted tune-up work practices for limited use 

units and these units are no longer subject to emission limits and performance testing 

requirements.

Commenter Name: Matthew Todd and David Friedman

Commenter Affiliation: American Petroleum Institute (API) and National Petrochemical and

Refiners Association (NPRA)

Document Control Number: EPA-HQ-OAR-2002-0058-2960.1

Comment Excerpt Number: 175

Comment: Proposed 63.7520(d) specifies that You must conduct three separate test runs for 

each performance test required in this section, as specified in 63.7(e)(3). Each test run must last 

at least 4 hours. The basis for this unusual requirement is not explained or justified. 
16

Extending test runs from the 1 hour specified in the part 60 Appendix A procedures to 4 hours 

raises many concerns. First, it significantly raises the cost of testing, since the stack test will take 

at least 12 hours, meaning the field personnel will be working extended times at premium pay 

levels. The additional costs and burdens for these extended runs were not considered in the cost 

and burden estimates for this rulemaking. Second, extended runs make it likely many tests will 

be aborted and have to be redone. Weather conditions, operating conditions, and sample systems 

are prone to significant change over a 12 hour time and it is likely many more tests than 

historically typical will have to be stopped due to rain, snow, operating changes or sampling 

problems. Additionally, testing will be partially in the dark. Third, this extended time greatly 

increases the excess emissions generated due to having to run high rates and high mercury and 

chlorine feeds, as discussed in comment VII.B.6 and 8. Finally, this requirement is inconsistent 

with the MACT floor basis, since the performance tests from which the data on the floor was 

developed were traditional 1-hour runs. 

Recommendation: Justify the requirement that all performance test runs for all pollutants be 4 

hours, rather than the standard 1 hour. Demonstrate the legality of changing the compliance 

requirements from those used in gathering the data that was used to establish 

the emission limits and incorporate the costs and burdens resulting from the change in the 

supporting analyses and in the ICR. 

Response: See response to EPA-HQ-OAR-2002-0058-1907.1, Comment Excerpt Number 8.

Commenter Name: Matthew Todd and David Friedman

Commenter Affiliation: American Petroleum Institute (API) and National Petrochemical and 

Refiners Association (NPRA)

Document Control Number: EPA-HQ-OAR-2002-0058-2960.1

Comment Excerpt Number: 176

Comment: Proposed Table 5 requires determining O2 and CO2 during every performance test. 

For CO and dioxin/furan performance tests CO2 is not needed because the emission limit is a 

concentration limit. For the other tests, either O2 or CO2 can be used for the F-factor calculation. 

Since O2 is needed for adjusting the measured results to the specified O2 level, measuring CO2

is not needed for these tests either. Thus, CO2 should be removed from the performance test 

requirements in Table 5. If sources wish to measure CO2 during these tests they can make that 

choice, but it is not required for demonstrating compliance with this rule and thus should not be 

mandatory. 

Recommendation: Make the measurement of CO2 during performance tests optional. 
17

Response: EPA agrees with the commenter. Sources should correct for O2 or CO2, and there is 

no need to measure both during all performance tests. However, O2 must be measured during the 

CO and dioxin tests.

Commenter Name: Jon T. Howard

Commenter Affiliation: Weston Solutions, Inc

Document Control Number: EPA-HQ-OAR-2002-0058-2737.1

Comment Excerpt Number: 1

Comment: The extended run times for sampling methods have not been validated and the 

methods do not provide definitive guidance about performance criteria for sampling over 

extended periods of time. As a result, ICR data generated using these methods and extended run 

times may be biased. We suggest that EPA verify that extended run times do indeed yield 

representative source data and establish performance criteria for extended run times. If extended 

run data are shown to be biased, the rule limits should be re-evaluated and method modifications 

to compensate for the bias should be developed for use. 

Response: See response to EPA-HQ-OAR-2002-0058-1907.1, Comment Excerpt Number 8.

Commenter Name: Steve Smith

Commenter Affiliation: LyondellBasell Industries

Document Control Number: EPA-HQ-OAR-2002-0058-3118.1

Comment Excerpt Number: 3

Comment: Many Gas 2 streams (e.g., petrochemical fuel gas) are often integrated in refinery 

fuel systems and have comparable compositions and emission profiles to natural gas and refinery 

gas. We are very concerned by the proposal not to treat such streams as Gas 1 sources just 

because they happen to be generated outside a refinery. The potential for implementing the 

numeric emissions limits for Gas 2-fired boilers and process heaters included in the proposal will 

result in technically and practically infeasible standards. Attempting to meet those standards will 

result in operations that are non-optimum from an energy efficiency and emissions standpoint. 

Therefore, we propose EPA merge the Gas 1 and Gas 2 subcategories and apply the Gas 1 work 

practice requirements to the merged subcategory. Treating a particular type of gas or similar 

gases differently, based on where it is generated, has no scientific basis and puts some facilities 

at a competitive disadvantage to other facilities. 

Response: See the preamble for a discussion of a fuel specification that has been added to the 

rule that will allow “Gas 2” units to qualify as “Gas 1.”

Commenter Name: Jon T. Howard

Commenter Affiliation: Weston Solutions, Inc
18

Document Control Number: EPA-HQ-OAR-2002-0058-2737.1

Comment Excerpt Number: 3

Comment: EPA Method 29 allows the tester to determine if analysis of the HCl rinse fraction 

should be analyzed. This fraction can contain appreciable levels of Hg. It is unclear, and likely 

undocumented in the ICR database, how testers treated the analysis of this fraction. As a result, 

Hg levels in the database used to develop the proposed rules may be lower than actual emission 

levels. WESTON recommends that EPA query sources about the inclusion of this fraction in 

reported results and require sources to document why the fraction was not included. Most 

significantly, WESTON believes that the most accurate data are those that include the HCl rinse 

and that promulgated limits should be based on data which includes this fraction. 

Response: EPA made several corrections to reported mercury data based on detailed reviews of 

test reports provided during the public comment period. Information on whether or not an HCl 

rinse was conducted was not data available to the Administrator for each and every Method 29 

test.

Commenter Name: H. Allen Faulkner

Commenter Affiliation: Ascend Performance Materials, LLC

Document Control Number: EPA-HQ-OAR-2002-0058-2743.1

Comment Excerpt Number: 4

Comment: Ascend is very concerned about the requirement that each test run must last at least 4 

hours for all parameters. Ascend believes that this is an excessive testing run time and requests 

the EPA to consider the use of a sample volume requirement rather than time requirement. For 

example, in the Boiler MACT ICR testing completed in 2009, the run requirement was 4 hours 

or 2.5 cubic meters of sample volume for Dioxin/Furans. In addition, Mercury testing during the 

ICR only required 2.5 cubic meters of sample volume. In both examples, EPA has give the 

owner/operator and stack tester, the ability to determine the best sample run time to get the 

necessary sample volume for the given parameter. Ascend believes that the same accuracy is 

achievable when the sample runs are set by sample volume rather than time while minimizing 

the performance testing time. Ascend requests that the EPA consider giving the same flexibility 

as in the ICR testing. 

Response: See response to EPA-HQ-OAR-2002-0058-1907.1, Comment Excerpt Number 8.

Commenter Name: Jeffrey R.Klieve

Commenter Affiliation: Monsanta Company

Document Control Number: EPA-HQ-OAR-2002-0058-2754.1

Comment Excerpt Number: 5
19

Comment: In the proposed 63.7520(d), an affected source must conduct three separate test runs 

for each performance test as specified in 63.7(e)(3) and each run must last at least 4 hours. 

Monsanto believes that USEP A underestimates the time and expense involved in conducting 

performance testing capable of demonstrating compliance with the dioxin/furan (D/F) limits in 

Table 2. In support of the ICR, Monsanto conducted stack testing in the fall of 2009 on a coalfired stoker boiler. Based on the results of that testing and the proposed D IF limit of 0.003 ngl 

dscm (TEQ), Monsanto feels that the testing time will need to be extended by a factor of 2 (up to 

8 hours per run) to ensure that an adequate sample size is obtained to meet the minimum 

detection limit requirements and compliance with the 0.003 limit can be demonstrated through 

the testing. This additional sampling time will greatly increase the cost of the testing, as it will 

now extend across a minimum of 3 days, unless sampling is conducted around the clock. This 

presents personnel and safety issues which are inconsistent with our corporate policy. 

Monsanto maintains its own stack testing department and, therefore, testing is performed at cost, 

which is less expensive than if an outside testing firm conducted these performance tests. 

Monsanto’s cost to perform the ICR testing approached $44,000, which could increase by as 

much as 35% in order to demonstrate compliance with the proposed D/F limit. 

Response: See response to EPA-HQ-OAR-2002-0058-2775.1, Comment Excerpt Number 62. 

Commenter Name: John C. Hendricks

Commenter Affiliation: American Electric Power

Document Control Number: EPA-HQ-OAR-2002-0058-2703.1

Comment Excerpt Number: 6

Comment: EPA Should Add Alternative Testing Methods. Methods 30A and 30B should be 

included as an acceptable test method for Mercury. Method 30B is being utilized for the EGU 

MACT Information Collection Request (ICR) and would be an appropriate and suitable test 

method for the 1B MACT performance testing. 

Response: The final rule includes EPA Methods 30 A and 30B.

Commenter Name: Jon T. Howard

Commenter Affiliation: Weston Solutions, Inc

Document Control Number: EPA-HQ-OAR-2002-0058-2737.1

Comment Excerpt Number: 6

Comment: We noted that the ICR data set includes Method 5 data that where either probe wash 

or filter weights was negative. Method 5 does not address negative filter weights. We encourage 
20

EPA to evaluate the inclusion of this data in the standard setting process and issue guidance 

regarding the use of negative weights for filter or probe was fractions. 

Response: We agree with the commenter that it would be useful to have guidance on how to 

treat negative filter weights resulting from Method 5 testing. The proper approach is to treat the 

negative filter weights as zero. We are planning to include such guidance in our next rulemaking 

update to Method 5. In the meantime, EPA plans to include a recommendation as part of the 

frequently asked questions (FAQ) for Method 5 on our Emission Measurement Center website at 

www.epa.gov/ttn/emc. We recognize that uncertainty of the measurement may gradually 

increase at particulate matter (PM) catch levels below 5 mg, and have taken this uncertainty 

(variability) into account in setting the standard. 

Commenter Name: Jeffrey R.Klieve

Commenter Affiliation: Monsanta Company

Document Control Number: EPA-HQ-OAR-2002-0058-2754.1

Comment Excerpt Number: 7

Comment: Conducting three separate test runs of four hours duration is excessive and 

unwarranted for PM, CO, and HCl. Provisions in NESHAP Subpart SS (40 CFR 63.997(e)(1)(v) 

require test runs of one hour each. The USEP A’s standard test methods for these pollutants 

established in 40 CFR 60 Appendix A are also based on the average of three one-hour test runs. 

Monsanto has conducted numerous successful tests of this duration on its sources, and extending 

each test run’s duration to four hours unnecessarily increases the cost of these efforts. 

Gas 2 Approaches and Related Table 2 Emission Limits (75 Fed. Reg. 32065 - 68) 

The proposed rule identifies two categories for gas-fired boilers: 

Gas 1 includes any boiler or process heater that bums at least 90% natural gas and/ or refinery 

gas on a heat input basis on an annual average, and 

Gas 2 includes any boiler or process heater that burns gaseous fuels other than the above that are 

not combined with any solid or liquid fuels. 

Response: See response to EPA-HQ-OAR-2002-0058-2775.1, Comment Excerpt Number 62.

Commenter Name: Pamela F. Faggert

Commenter Affiliation: Dominion

Document Control Number: EPA-HQ-OAR-2002-0058-2908.1

Comment Excerpt Number: 11
21

Comment: EPA should also clarify the CO methods that are allowed under the rule (for 

example, the same options as for CO performance tests - Reference Method or ASTM portable 

method or operator-defined portable analyzer method). 

Response: Comment appears to be directed at the methods for measuring CO emissions (ppmv) 

in the effluent stream as part of the boiler tune-up. The rule is clear on the initial and annual 

performance test methods. Reference Method 10, or other EPA approved method, is required.

Commenter Name: John Hopewell

Commenter Affiliation: American Coatings Association

Document Control Number: EPA-HQ-OAR-2002-0058-2886.1

Comment Excerpt Number: 15

Comment: Test methods that received EPA approval under the original rule need to be included 

in the final rule. 

Response: The final rule includes EPA Methods 30 A and 30B. A source wishing to use other 

methods not in the rule may apply for an alternative performance test procedure per Section 

63.7(f). Additional fuel analysis methods, that were previously included in the vacated standard 

(as long as they are the most updated versions of the methods) will be updated in a future 

revision to this rule since there was not time to incorporate additional methods by reference in 

this final rule.

Commenter Name: John Hopewell

Commenter Affiliation: American Coatings Association

Document Control Number: EPA-HQ-OAR-2002-0058-2886.1

Comment Excerpt Number: 18

Comment: Four hour runs are not necessary for all pollutants 

Response: See response to EPA-HQ-OAR-2002-0058-1907.1, Comment Excerpt Number 8.

Commenter Name: David Foerter

Commenter Affiliation: Institute of Clean Air Companies

Document Control Number: EPA-HQ-OAR-2002-0058-2937.1

Comment Excerpt Number: 41
22

Comment: ICAC does not take issue with the proposed requirement for initial and annual testing 

of HAPS, including mercury. However, we disagree with EPA’s proposed use of EPA Method 

29 or ASTM D-6784-02 Ontario Hydro (Section III. F. (75 FR 32013)), as the measurements 

protocol, as EPA Method 30B, Sorbent Traps, is superior for the following reasons: 

1. No Hg speciation, only total Hg, is required by the proposed requirement. 

2. EPA Methods 30A and 30B, plus the use of certified Hg CEMS, have been successfully 

demonstrated and used on a variety of processes including waste incinerators, cement process, 

steel process and coal-fired power plants. (Levels of detection of less than 0.05 ug/m3, have been 

reported at a number of these facilities). 

3. There are numerous testing and consulting companies as well as owner/operators, who are 

well versed in sorbent trap measurements protocol, 

4. EPA Method 30B can achieve low-level (e.g., <0.1 ug/m3) Hg determinations and accuracies. 

This is accomplished by simply increasing flow rates and sampling times to effect sufficient 

collection of Hg for analyses at lower levels. At higher Hg concentrations (i.e. >1 ug/m3), and 

using sampling rates of 1-2 liters per minute, the collected Hg will result in collected Hg total 

mass, which is comfortably addressed by recognized analytical methods (e.g., Cold Vapor 

Atomic Fluorescence Spectrophotometry (CVAFS)). 

5. Sorbent Trap tests require fewer resources and typically cost less substantially less than 

Method 29 or Ontario Hydro tests. 

Response: The final rule includes EPA Methods 30 A and 30B.

Commenter Name: Russ A. Wozniak

Commenter Affiliation: Dow Chemical Company

Document Control Number: EPA-HQ-OAR-2002-0058-2632.1

Comment Excerpt Number: 43

Comment: EPA Should Only Require the Duration of a Performance Test to be 4 Hours if 

Testing is Required for Dioxins/Furans. The Duration of a Performance Test Should Be 1 Hour 

for Other Air Pollutants. EPA proposes in Section 63.7520(d) that the owner/operator conduct 

three separate test runs for each performance test and that each test run must last at least 4 hours. 

Requiring a minimum of 4 hours for each test run is excessive, especially if the test may need to 

include more than one test condition. Performance testing is expensive, and one of the main 

drivers for cost is the length of time for a test. In general, testing contactors try to complete a 

minimum of two runs per day and sometimes more. Considering set-up time and time between 

runs, it would be difficult to complete more than run per day if EPA maintains this 4 hour 

minimum. 

A 4 hour test run may be appropriate for Dioxin/Furan testing, but the rule should be clarified so 

that a 1-hour test run can be conducted for PM, HCl, Mercury, and CO. 

A 1-hour test run is adequate for these other air contaminants. 
23

Response: See response to EPA-HQ-OAR-2002-0058-1907.1, Comment Excerpt Number 8.

Commenter Name: Chris M. Hobson

Commenter Affiliation: Southern Company

Document Control Number: EPA-HQ-OAR-2002-0058-2741.1

Comment Excerpt Number: 56

Comment: Many of the test runs were conducted using sampling times that did not meet the 

minimum required sampling time specified by in the ICR, which was four hours for all test 

methods. [Footnote: EMC Guidance Document 051b. ] Reported sampling times ranged from 60 

to 180 minutes and varied according to test method. (See submittal Attachment G for a list of test 

runs that did not meeting the required minimum sampling time.) 

Response: EPA based the standard on data provided to the Agency. Although the run times were 

different for different tests EPA determined that use of all of these tests, instead of only a subset 

of the tests were relevant to the standard setting process, given the limited data available for 

certain subcategories.

Commenter Name: Chris M. Hobson

Commenter Affiliation: Southern Company

Document Control Number: EPA-HQ-OAR-2002-0058-2741.1

Comment Excerpt Number: 58

Comment: EPA should include the following reference methods for compliance demonstration: 

EPA Method 30A, 30B (mercury) 

EPA Method 5B (total, filterable PM) 

EPA Method 320 (HCl) 

EPA Method 23 (dioxin/furans) 

Response: The final rule includes EPA Methods 30 A and 30B, and Method 23. 

We disagree with the commenter suggestion to include the FTIR Method 320. Method selection 

is critical when measuring compliance with HCl emissions limits as low as the proposed values, 

therefore EPA has specified Method 26 or 26A for this purpose. These wet chemistry methods 

with suitable sampling collection periods have minimum detection levels lower than does 

Method 320 or Method 321 using the currently available technology. 

We also disagree on Method 5B. A source wishing to use Method 5B may apply for an 

alternative testing procedure per Section 63.7(f).
24

Method 23 was inadvertently left out of the proposal and the final rule has been updated to 

include this method.

Commenter Name: Chris M. Hobson

Commenter Affiliation: Southern Company

Document Control Number: EPA-HQ-OAR-2002-0058-2741.1

Comment Excerpt Number: 60

Comment: In 63.7520(d), EPA specifies a minimum sampling time of four hours for each test 

method. While this is consistent with the procedures used to establish the MACT floor data, 

[Footnote: EMC Guidance Document GD-051b (7/14/2009)] it seems excessive for certain 

pollutants. RMB recommends that EPA reevaluate the required sampling times for each method 

and/or provide alternative minimum sample volumes for each method, taking into account 

representative analytical detection limits and emissions standards that are properly adjusted for 

non-detect values. 

Response: See response to EPA-HQ-OAR-2002-0058-1907.1, Comment Excerpt Number 8.

Commenter Name: Russ A. Wozniak

Commenter Affiliation: Dow Chemical Company

Document Control Number: EPA-HQ-OAR-2002-0058-2632.1

Comment Excerpt Number: 88

Comment: Section 63.7520(e) Should Be Amended to Allow Utilization of Alternate Fc values 

that are Approved for Use Per 40 CFR 75. 

Proposed Section 63.7520(e) requires that F-Factor methodology from equations in Sections 12.2 

and 12.3 of EPA Method 19 of Appendix A to part 60 be used for PM, Hg, and HCl emission 

calculations. Dow comments that a boiler in West Virginia has alternate-approved Fc calculation 

factors pursuant to EPA’s Clean Air Interstate Rule. Thus, Dow comments that Section 

63.7520(e) should be amended to allow utilization of alternate Fc values that are approved for 

use per 40 CFR Part 75. 

Response: Reference Method 19 includes procedures for determining a site specific F-factor, or 

an F-factor for a fuel not listed in Table 19.2 (see Section 12.3.2 of Reference Method 19) .

Commenter Name: Jim Eubank

Commenter Affiliation: Kentucky Division of Air Quality

Document Control Number: EPA-HQ-OAR-2002-0058-3176.2
25

Comment Excerpt Number: 5

Comment: Method 30b is not listed as an option for mercury compliance testing in table 5 of 

subpart DDDDD of Part 63. Method 30b is currently in use for mercury compliance testing over 

Method 29. 

Response: The final rule includes Methods 30A and 30B.

Commenter Name: Michael L. Corvese

Commenter Affiliation: Thermo Fisher Scientific, Inc

Document Control Number: EPA-HQ-OAR-2002-0058-2997.1

Comment Excerpt Number: 6

Comment: Recommend that EPA allow use of ASTM D6831-02 “Standard Test Method for 

Sampling and Determining Particulate Matter in Stack Gasses Using an In-Stack, Inertial 

Microbalance” for PM testing to demonstrate compliance with emission standards and to 

perform correlation testing for PM CEMS applications. 

EPA failed to consider the voluntary consensus standard ASTM D6831-02 “Standard Test 

Method for Sampling and Determining Particulate Matter in Stack Gasses Using an In-Stack, 

Inertial Microbalance” under its obligations to comply with the National Technology Transfer 

and Advancement Act. This ASTM standard is not mentioned or discussed in Section H of the 

preamble. We assert that EPA is legally obligated to consider this standard, and that it should be 

approved for the following reasons: 

Developers of this method met with EPA EMB representatives on numerous occasions, acquired 

method validation data in accordance with Method 301 by comparison to Method 5 and Method 

17 at coal-fired facilities, and submitted the data demonstrating acceptability to EPA. 

EPA provided letter accepting demonstration showing equivalency (See attached October 3, 

2002 letter from Conniesue B. Oldham, Ph.D. Source Measurement Technology Group, EPA to 

Edward Burgher, Rupprecht and Patashnick, Inc.) and agreeing to approve on a case-by-case 

basis. The letter stated that EPA did not have authority to approve broadly applicable alternatives 

at the time. 

EPA previously published the subject method and the referenced letter on its website. 

An equivalent method (ASTM D6831-02) was later approved and published by ASTM during 

2002 (with EPA representatives participating in ASTM Task Group for this standard and the 

D22.03 Subcommittee during the development and approval process). 

The method provides advantages of real time test data for PM and capabilities for stratification 

tests, PM CEMS calibrations, and PM compliance tests, and capabilities for measurement at 

concentrations too low for accurate measurement by EPA Method 5 or 17.. 
26

We have acquired Rupprecht and Patashnick, Inc including intellectual property rights and 

patents on Series 7000 and may consider reintroducing this or a similar product when approved 

by EPA. 

Test firms such as Emission Monitoring Inc., Clean Air Engineering, TRC and some electric 

utilities continue to use the Series 7000 for emission tests. 

Response: EPA is in the process of evaluating ASTM D6831-02. For compliance with this 

rule, a source will need to apply per the alternative performance test procedures in Section 

63.7(f).

Commenter Name: Kevin M. Dempsey

Commenter Affiliation: American Iron and Steel Institute

Document Control Number: EPA-HQ-OAR-2002-0058-2998.1

Comment Excerpt Number: 10

Comment: Method 5B was selected for filterable PM because it is believed to be a superior 

surrogate for non-mercury metallic HAPs when sulfuric acid may be present, as discussed 

elsewhere in these comments. Sulfur dioxide (SO2) concentrations in the exhaust gas indicate 

that sulfuric acid may be present at concentrations on the order of 5-7 ppmv, which represents a 

potentially large fraction of the proposed filterable PM limit (on a lb/MMBTU basis). Method 

5B is designed to mitigate the effect of sulfuric acid on the filterable PM results, which allows 

for a more accurate surrogate for non-mercury metallic HAP. For the Method 29 and Method 

101A tests, filterable PM samples were collected with the probe and filter temperature at 160 

degrees C as specified in Method 5B, but the laboratory analysis was modified by drying the 

samples in a desiccator at room temperature as specified in Methods 29 and 101A rather than in 

an oven at 160 degrees C as specified in Method 5B, so that Hg was preserved in these samples. 

For the Method 26A tests, Method 5B was performed normally. 

Response: Method 5B will not be included in the final rule. A source wishing to use Method 

5B may apply for an alternative testing procedure per Section 63.7(f).

Commenter Name: Wayne J. Galler and Deborah A. Phillips

Commenter Affiliation: Georgia Industry Environmental Coalition, Inc

Document Control Number: EPA-HQ-OAR-2002-0058-2882.1

Comment Excerpt Number: 10

Comment: EPA has also proposed to change the testing methodology in a manner that will 

increase the financial burden for companies by requiring, for example, three 4-hour test runs, or a 

total of 12 hours of testing to be averaged and compared to the MACT standard for particulate 
27

matter, in lieu of the current testing requirement which is to perform three, 1-hour runs and 

average those results. This will likely more than triple the costs that stack testing firms have to 

change in order to have testing personnel onsite for such long periods of time With normal 

change-over between testing runs, it will take as long as 16 hours, or longer, to complete one 

compliance test. Since many of our member companies have multiple units on similar testing 

schedules, the additional time it will take to complete a compliance test represents a significant 

increase in the financial burden that our companies will have to bear. 

Response: See response to EPA-HQ-OAR-2002-0058-2775.1, Comment Excerpt Number 62.

Commenter Name: Mark W. Kowlzan

Commenter Affiliation: Packaging Corp. of America

Document Control Number: EPA-HQ-OAR-2002-0058-2913.1

Comment Excerpt Number: 13

Comment: Testin~ Burden 

The Agency issued an Information Collection Request (lCR) in June 2009 that required 

recipients to conduct mandatory performance tests for select pollutants in order to fill data gaps 

in emission test data that EPA identified relative t0 CIWSI units. Our Counce, TN mill received 

an ICR and was required to perform stack tests on one boiler for cadmium, lead, mercury (Hg ), 

dioxin/furan carbon monoxide, condensable PM and PM2.5. The lCR prescribed three 2-hour 

test runs for Hg and three 4-hour test runs for D/F or, in lieu of the specified run durations,

alternative minimum sample volume .... The demands that this exercise placed on the stack 

testing contractor’s staff mill personnel overseeing the testing, and mill operations staff was 

extreme due to the duration of the test run". Just the cost of the stack testing personnel was 

$65,000. 

The proposed rule requires that three -l-hour stack test runs he performed annually in the worstcase fuel mix for the respective parameter of interest. We wonder if the Agency appreciates 

the magnitude of labor and cost associated with this requirement. There will be a lack of 

qualified stack resting contractors if/when the rule goes into effect. Assuming that over 10.000 

industrial boilers arc affected by the rule and that the annual stack testing requirements must be 

satisfied for the entire population of affected units within a narrow window of time (e.g. within 

180 days of the effective date of the rule and within 10 to 12 months, at least every year for three 

years and then annually or tri-annually thereafter). It is unlikely that there will be sufficient 

qualified stack testers to go around. Tests .for sensitive parameters like Hg and D/F required an 

experienced stack testing team that understands the pitfalls associated with the test methods. 

Factor in fatigue due to performing extended stack tests and the stage is set for a high probability 

of questionable results. Finally the proposed rule requires performance stack testing while 

combusting “worst-case” fuel blends. This requirement multiplies the number of stack tests 

required as s a function of fuels combusted at a facility as well as the parameter in question. To 

wit, it is entirely probable that a facility night need to conduct a set of three+4 hour performance 

tests runs for D?F using one fuel blend, another set of tests for Hg using a different fuel blend, 
28

yet another set of complicated testing matrix are multiples greater than what we incurred at our 

Counce facility to satisfy the ICR-and something that we believe is entirely unnecessary. 

Response: The final rule requires only an initial performance test for D/F. The final rule also 

replaces minimum run times with minimum sample volumes. Only one fuel mix is required, the 

one with the highest content of both chlorine and mercury. The final rule ICR includes the costs 

and burdens of these testing requirements, and EPA has determined that they are reasonable as a 

component of the overall compliance costs of the rule.

Commenter Name: Bruce A. Steiner

Commenter Affiliation: American Coke and Coal Chemicals Institute

Document Control Number: EPA-HQ-OAR-2002-0058-2849.1

Comment Excerpt Number: 14

Comment: ACCCI supports EPA’s proposal to use filterable PM as a surrogate for non-mercury 

metals. These metals, if present, will be contained within the solid PM entrained in the flue gas. 

Thus, the PM test method should focus on quantifying the solid PM that may contain HAP 

metals to the exclusion of volatile material, including sulfuric acid, that does not contain HAP 

metals but may condense on the Method 5 filter. Method 5B is designed to eliminate potential 

distortions to the quantification of solid PM caused by the presence of volatile sulfuric acid in the 

flue gas. 

Table 5 to Subpart DDDDD of Part 63 – Performance Testing Requirements of the proposed rule 

should expressly include Method 5B in 40 CFR Part 60, Appendix A, which determines 

filterable non-sulfuric acid PM. The dew point of sulfuric acid can extend above and below the 

filter temperature specified in Method 5 depending on sulfuric acid and water vapor 

concentration. In the presence of high concentrations of sulfuric acid, Method 5B is 

recommended to avoid distortions of the filterable particulate matter results caused by 

condensing sulfuric acid. To minimize this distortion, Method 5B modifies two parts of the 

standard Method 5 procedure: (1) the probe and filter are maintained at a higher temperature, 

160±14°C (320±25°F), during sample collection; and (2) the probe rinse and filter are dried in an 

oven for 6 hours at 160±5°C (320±10°F), then cooled in a desiccator at room temperature for 2 

hours, prior to gravimetric analysis. 

EPA has implicitly recognized the benefits of a higher temperature probe and filter in allowing 

either Method 5 or Method 17 for determining compliance. In Method 5, the sample nozzle, 

probe and an ex-situ filter placed in a controlled temperature oven are maintained at 120±14°C 

(248±25°F). In Method 17, the filter and close-coupled sample nozzle are located in-situ within 

the stack and hence samples are filtered at stack gas temperature. Gas-fired industrial boilers at 

cokemaking facilities routinely operate with flue gas temperatures of approximately 200-260°C 

(approximately 400-500°F). Hence, the filtration temperature using Method 17 would be in that 

same range. In this application, the filter temperature for Method 5B is lower than the Method 17 

temperature, but greater than the standard Method 5 temperature. Because the filter temperature 

for Method 5B may fall within the range allowed by the two methods proposed by EPA in Table 

5, Method 5B is implicitly permitted in the proposed rule. To avoid ambiguity when interpreting 
29

the rule after finalization, we recommend that EPA expressly approve the use of Method 5B in 

the final rule. 

Method 17 alone is insufficient to address the presence of sulfuric acid. First, Method 5B is often 

required as a test method for determining compliance with other regulatory particulate matter 

standards at facilities. Expressly including Method 5B in Table 5 of the rule would reduce the 

cost burden imposed on facilities by allowing a single test method to demonstrate compliance 

with the proposed MACT standard and other regulatory emission limits. Also, due to Method 

17’s in-stack apparatus, it is not an appropriate method for smaller stacks. See 40 CFR Part 60, 

Appendix A, Method 17, Section 1.2. EPA also states that Method 17 is not applicable for stacks 

that contain liquid droplets or that are saturated with water vapor. Id. Finally, Method 17 

specifies the sample analysis procedures given in Method 5, which may not be sufficient to 

eliminate residual sulfuric acid in the sample as noted above. Therefore, Method 5B is an 

appropriate and necessary addition to the approved methods in Table 5 of the proposed rule for 

quantifying filterable PM as a surrogate for non-mercury HAP metals. 

Response: Method 5B will not be included in the final rule. A source wishing to use Method 

5B may apply for an alternative testing procedure per Section 63.7(f).

Commenter Name: Mark W. Kowlzan

Commenter Affiliation: Packaging Corp. of America

Document Control Number: EPA-HQ-OAR-2002-0058-2913.1

Comment Excerpt Number: 15

Comment: It is puzzling that EPA is mandating performance testing for Hg and HCI on boilers 

that fire biomass and liquid fossil fuels despite unequivocal evidence that these fuels contain 

only trace amounts of either constituent. The Agency is requiring extensive, expensive and 

exhaustive testing on affected boilers to demonstrate the efficacy of a control technology when, 

in fact, the emissions of Hg and HCI are a function of natural fuel variation. 

Response: These boilers may conduct fuel analyses in accordance with the rule as an 

alternative. 

Commenter Name: Douglas A. McWilliams

Commenter Affiliation: ArcelorMittal USA, Inc

Document Control Number: EPA-HQ-OAR-2002-0058-2811.1

Comment Excerpt Number: 20

Comment: EPA should modify Table 5 of the Proposed Rule to include EPA Method 5B as an 

expressly approved option for determining compliance with particulate matter emission limits. 

We support EPA’s proposal to use filterable particulate matter as a surrogate for non-mercury 

metals. These metals, if present, will be contained within the solid particulate matter entrained in 
30

the flue gas. Thus, the particulate matter test method should focus on quantifying the solid 

particulate matter that may contain HAP metals to the exclusion of volatile material, including 

sulfuric acid, that does not contain HAP metals but may condense on the Method 5 filter. Method 

5B is designed to eliminate potential distortions to the quantification of solid particulate matter 

caused by the presence of volatile sulfuric acid in the flue gas. 

Sulfuric acid is a volatile compound at flue gas temperatures that can partially condense and/or 

adsorb on the filter and collected solid particulate matter. Sulfuric acid’s dew point can extend 

above and below the filter temperature specified in EPA Method 5 depending on sulfuric 

acid and water vapor concentration. When high concentrations of sulfuric acid are present, 

Method 5B is recommended to avoid distortions of the filterable particulate matter results caused 

by condensing sulfuric acid. To minimize this distortion, Method 5B modifies two parts of the 

standard EPA Method 5 procedure: 1) the probe and filter are maintained at a higher 

temperature, 160±14 °C (320±25 °F), during sample collection; and 2) the probe rinse and filter 

are dried in an oven for 6 hours at 160±5 °C (320±10 °F), then cooled in a desiccator at room 

temperature for 2 hours, prior to gravimetric analysis. 

EPA has implicitly recognized the benefits of a higher temperature probe and filter in allowing 

either EPA Method 5 or EPA Method 17 for determining compliance. In EPA Method 5, the 

sample nozzle, probe and an ex-situ filter placed in a controlled temperature oven are maintained 

at 120±14 °C (248±25 °F). In EPA Method 17, the filter and close-coupled sample nozzle are 

located in-situ within the stack and hence samples are filtered at stack gas temperature. Gas-fired 

industrial boilers at iron and steel manufacturers routinely operate with flue gas temperatures of 

approximately 200-260 °C (approximately 400-500 °F). Hence, the filtration temperature using 

EPA Method 17 would be in that same range. In this application, the filter temperature for EPA 

Method 5B is lower than the EPA Method 17 temperature, but greater than the standard EPA 

Method 5 temperature. Because the filter temperature for EPA Method 5B may fall within the 

range allowed by the two methods proposed by EPA in Table 5, Method 5B is implicitly 

permitted in the proposed rule. To avoid ambiguity, we request that EPA expressly approve the 

use of Method 5B in the final rule. 

EPA Method 17 alone is insufficient to address the presence of sulfuric acid. Rather, Method 5B 

is often required as a test method for determining compliance with other regulatory particulate 

matter standards. For example, due to Method 17’s in-stack apparatus, it is not appropriate for 

smaller stacks. See 40 CFR Part 60, Appendix A, Method 17, Section 1.2. Similarly, EPA has 

acknowledged that Method 17 is not applicable for stacks that contain liquid droplets or that are 

saturated with water vapor. Id. Finally, Method 17 specifies the sample analysis procedures 

given in Method 5, which may not be sufficient to eliminate residual sulfuric acid in the sample 

as noted above. Therefore, Method 5B is an appropriate and necessary addition to the approved 

methods in Table 5 of the proposed rule for quantifying filterable particulate matter as a 

surrogate for non-mercury HAP metals. [Footnote: Expressly including Method 5B in Table 5 of 

the rule would thus have the ancillary benefit of reducing the cost burden imposed on facilities 

by allowing a single test method to demonstrate compliance with the proposed MACT standard 

and other regulatory emission limits.] 

Response: Method 5B will not be included in the final rule. A source wishing to use Method

5B may apply for an alternative testing procedure per Section 63.7(f).
31

Commenter Name: Richard Rosvold

Commenter Affiliation: Xcel Energy Services, Inc

Document Control Number: EPA-HQ-OAR-2002-0058-2955.1

Comment Excerpt Number: 20

Comment: Four-hour sampling test runs, as required in §63.7520(d), are excessive, especially 

for CO and acid gases testing. Accurate measurements of these pollutants can be completed 

using one-hour test runs. 

Response: See response to EPA-HQ-OAR-2002-0058-2632.1, Comment Excerpt Number 43.

Commenter Name: Jim Eubank

Commenter Affiliation: Kentucky Division of Air Quality

Document Control Number: EPA-HQ-OAR-2002-0058-3176.2

Comment Excerpt Number: 24

Comment: The required ASTM methods listed in the tables 5 and 6 to Subpart DDDDD of Part 

63 are not available free of charge. In order for state, local, or tribal agencies to observe and 

review testing methods following the ASTM methodology, the agencies would be required to 

purchase copies of the testing methods. A free resource library such as the online EMC website 

would be beneficial to financially strapped agencies seeking the method information. 

Response: Copyright would prevent EPA from providing ASTM method documents for free on 

the EMC website.

Commenter Name: Lee B. Zeugin

Commenter Affiliation: Utility Air Regulatory Group

Document Control Number: EPA-HQ-OAR-2002-0058-2880.1

Comment Excerpt Number: 26

Comment: UARG agrees that because EPA’s proposed emission limits were based on test data 

collected using runs of at least four hours, EPA cannot require compliance with the emission 

limits based on runs of shorter length. Moreover, in some cases, four hours (or longer) may be 

needed to obtain an adequate sample volume. However, in those cases where a source is able to 

obtain an adequate sample and meet an emission limit with a shorter run time, that option should 

be provided. UARG requests that EPA provide for that possibility by allowing shorter sampling 

times when the owner/operator can meet the comparable data quality objectives of the longer 

sampling time. Allowing shorter run times could significantly reduce the cost of compliance for 

some sources. 
32

Response: See response to EPA-HQ-OAR-2002-0058-1907.1, Comment Excerpt Number 8.

Commenter Name: Lee B. Zeugin

Commenter Affiliation: Utility Air Regulatory Group

Document Control Number: EPA-HQ-OAR-2002-0058-2880.1

Comment Excerpt Number: 27

Comment: To demonstrate compliance with Hg emission limits, EPA proposes to allow use of 

EPA Method 29 (in 40 C.F.R. Part 60, Appendix A), Method 101A (in 40 C.F.R. Part 60, 

Appendix B), or ASTM Method D6784-02. [Standard Test Method for Elemental, Oxidized, 

Particle-Bound and Total Mercury in Flue Gas Generated from Coal-Fired Stationary Sources 

(Ontario Hydro Method).]Proposed Table 5. Inexplicably, EPA does not propose to allow use of 

either of the most recently promulgated federal reference methods for Hg -- Method 30A -

Determination Of Total Vapor Phase Mercury Emissions From Stationary Sources (Instrumental 

Analyzer Procedure) and Method 30B - Determination Of Total Vapor Phase Mercury Emissions 

From Coal-Fired Combustion Sources Using Carbon Sorbent Traps (in 40 C.F.R. Part 60, 

Appendix A). Because EPA has provided no explanation for the exclusion, UARG assumes this 

was an oversight and asks that the methods be included in the final rule. Although UARG is 

sensitive to the fact that EPA did not rely on any data from those methods in setting the proposed 

limits, UARG notes that EPA had sufficient confidence in the technical validity of the methods 

to promulgate them by direct final rule and that no relevant adverse comments were received. 72 

Fed. Reg. 51,494 (Sept. 7, 2007). Moreover, as part of its evaluation of the methods, the Agency 

examined data comparing Method 30B to both Method 29 and the Ontario-Hydro Method and 

concluded that the “sorbent trap-based technique coupled with appropriate performance criteria 

and QA procedures can provide Hg emissions data of quality comparable to that produced by the 

Ontario Hydro Method.” Id. at 51,497. If EPA does not include these methods in the final rule, 

EPA must provide a reasoned explanation for the exclusion and provide further opportunity to 

comment. 

Response: The final rule includes EPA Methods 30 A and 30B.

Commenter Name: Lee B. Zeugin

Commenter Affiliation: Utility Air Regulatory Group

Document Control Number: EPA-HQ-OAR-2002-0058-2880.1

Comment Excerpt Number: 28

Comment: To demonstrate compliance with the PM limits through stack tests, EPA proposes to 

allow use of Methods 5, 5D (required for positive pressure fabric filters), or 17. Proposed Table 

5. Sources performing calibrations of PM CEMS under PS 11, on the other hand, are also 

allowed the option of using Method 5B -- Determination of Nonsulfuric Acid Particulate Matter 
33

Emissions from Stationary Sources. Method 5B was specifically developed to determine primary 

filterable PM emissions from sources with wet scrubbers and is routinely allowed for stack 

testing under federal regulations. See, e.g., 40 C.F.R. Part 60, Subparts D (§ 60.46(b)), Da (§ 

60.50Da(e)(1)), Db (§ 60.46b(d)(2)), Dc (§ 60.45c(a)(2)) and Part 63, Subparts QQQ (§ 

63.1450(b), UUU (§ 63.1579 and Tables). EPA should allow use of Method 5B or explain why 

the method is not appropriate for demonstrating compliance with the proposed limits. 

Response: Method 5B will not be included in the final rule. A source wishing to use Method 5B 

may apply for an alternative testing procedure per Section 63.7(f).

Commenter Name: Bill Wemhoff

Commenter Affiliation: National Rural Electric Cooperative Association

Document Control Number: EPA-HQ-OAR-2002-0058-2835.1

Comment Excerpt Number: 28

Comment: In addition, NRECA suggests that EPA provide options for use of several additional 

well established test methods not included in the proposed rule, and other options that would 

allow for reduced run length when appropriate. 

Response: See response to EPA-HQ-OAR-2002-0058-1907.1, Comment Excerpt Number 8, 

with respect to run length. The final rule also includes Methods 23, 30A, and 30B as additional 

methods allowed for determining compliance.

Commenter Name: Lee B. Zeugin

Commenter Affiliation: Utility Air Regulatory Group

Document Control Number: EPA-HQ-OAR-2002-0058-2880.1

Comment Excerpt Number: 29

Comment: Proposed Table 5 lists Methods 2, 2F or 2G as the methods to determine the velocity 

and volumetric flow rate of the stack gas when testing for PM, HCl, and Hg, and Method 4 to 

determine moisture content for all pollutants. 75 Fed. Reg. at 32,069. Use of these methods is not 

necessary, or reasonable, because all of the methods specified in Table 5 for concentrations of 

those emissions also provide measurements of velocity and flow. Likewise, the methods used to 

determine pollutant concentrations (e.g., Methods 5, 23, and 26A) also determine stack moisture. 

Therefore, EPA should either remove those references or make use of those methods optional. 

Response: EPA disagrees, and has retained Methods 2, 2F, and 2G.

Commenter Name: David O'Keefe
34

Commenter Affiliation: USEC, Inc

Document Control Number: EPA-HQ-OAR-2002-0058-3122

Comment Excerpt Number: 32

Comment: Test runs in § 63.7520. This section requires each test run to last at least 4 hours 

and 3 test runs for each performance test. Normally a 1-hour test run is adequate. Requiring 

long test run times is unnecessary and burdensome. For many of the pollutants, detection ability 

is more important than the time of the test run. Adequate samples must be collected to ensure 

subject pollutants are detected in the samples. Test run time should be determined based on 

analytical requirements. 

The requirement for 3 test runs already provides assurance that performance testing will occur 

over an adequate period of time. A typical test run might last an hour followed by another 

hour of sample recovery and setup for the next run. This process allows additional time to 

capture emission variability. 

For some pollutants, such as coal PM, detection is normally not an issue and relatively short run 

times are adequate. Testing is usually conducted under worst case emission conditions, normally 

near maximum rated capacity. This methodology ensures compliance with emission standards 

under worst case conditions and long (4 hour) test runs are not necessary. 

Long test runs unnecessarily increase performance test cost.Costs will increase 

significantly both in man hours to oversee the testing and the services provided by the vendor. 

Longer test runs increase the likelihood of failure (sample equipment failure, failure to sample 

isokinetically, operator error, etc.) which could invalidate the test run. This would lead to less 

data (if 2 out of the 3 runs are accepted), repeat testing, and increased costs. There does not 

appear to be a sound basis for requiring at least 4 hours for test runs compared to a typical 1-hour 

test run. The method should determine the minimum sampling time and not the regulation. 

Response: See response to EPA-HQ-OAR-2002-0058-2775.1, Comment Excerpt Number 62 

with respect to increase the costs associated with extended test run. See response to EPA-HQOAR-2002-0058-1907.1, Comment Excerpt Number 8 with respect to a minimum sample 

volume and test duration.

Commenter Name: David M. Kiser

Commenter Affiliation: International Paper Company

Document Control Number: EPA-HQ-OAR-2002-0058-2777.1

Comment Excerpt Number: 41

Comment: EPA should adopt into the rule the list of equivalent test methods listed in the 

preamble to the December 6, 2006 rule (71 FR 70651). 

In the December 6, 2006 rule, EPA published in Table 1 of the preamble a list of testing methods 

that were reviewed and approved by EPA for use as “alternative” methods that were considered 

“equivalent” for purposes of Subpart DDDDD. Since these methods have been approved, they 

should appear in the final rule or be adopted by reference. 
35

Response: The final rule has added EPA Methods 30 A and 30B. A source wishing to methods 

not in the rule may apply for an alternative testing procedure per Section 63.7(f).

Commenter Name: Kevin M. Dempsey

Commenter Affiliation: American Iron and Steel Institute

Document Control Number: EPA-HQ-OAR-2002-0058-2998.1

Comment Excerpt Number: 43

Comment: EPA Should Modify Table 5 to Include EPA Method 5B as an Expressly Approved 

Option for Determining Compliance with Proposed PM Emission Limits 

AISI supports EPA’s proposal to use filterable PM as a surrogate for non-mercury metals. These 

metals, if present, will be contained within the solid PM entrained in the flue gas. Thus, the PM 

test method should focus on quantifying the solid PM that may contain HAP metals to the 

exclusion of volatile material, including sulfuric acid, that does not contain HAP metals but may 

condense on the Method 5 filter. Method 5B is designed to eliminate potential distortions to the 

quantification of solid PM caused by the presence of volatile sulfuric acid in the flue gas. 

Table 5 to Subpart DDDDD of Part 63 – Performance Testing Requirements of the proposed rule 

should expressly include Method 5B in 40 CFR Part 60, Appendix A, which determines 

filterable non-sulfuric acid PM. Sulfuric acid is a volatile compound at flue gas temperatures that 

can partially condense and/or adsorb on the filter and collected solid PM. The dew point of 

sulfuric acid can extend above and below the filter temperature specified in Method 5 depending 

on sulfuric acid and water vapor concentration. In the presence of high concentrations of sulfuric 

acid, Method 5B is recommended to avoid distortions of the filterable particulate matter results 

caused by condensing sulfuric acid. To minimize this distortion, Method 5B modifies two parts 

of the standard Method 5 procedure: (1) the probe and filter are maintained at a higher 

temperature, 160±14 degrees C (320±25 degrees F), during sample collection; and (2) the probe 

rinse and filter are dried in an oven for 6 hours at 160±5 degrees F (320±10 degrees F), then 

cooled in a desiccator at room temperature for 2 hours, prior to gravimetric analysis. 

EPA has implicitly recognized the benefits of a higher temperature probe and filter in allowing 

either Method 5 or Method 17 for determining compliance. In Method 5, the sample nozzle, 

probe and an ex-situ filter placed in a controlled temperature oven are maintained at 120±14 

degrees F (248±25 degrees F). In Method 17, the filter and close-coupled sample nozzle are 

located in-situ within the stack and hence samples are filtered at stack gas temperature. Gas-fired 

industrial boilers at iron and steel manufacturers routinely operate with flue gas temperatures of 

approximately 200-260 degrees F (approximately 400- 500 degrees F). Hence, the filtration 

temperature using Method 17 would be in that same range. In this application, the filter 

temperature for Method 5B is lower than the Method 17 temperature, but greater than the 

standard Method 5 temperature. Because the filter temperature for Method 5B may fall within 
36

the range allowed by the two methods proposed by EPA in Table 5, Method 5B is implicitly 

permitted in the proposed rule. To avoid ambiguity when interpreting the rule after finalization, 

we recommend that EPA expressly approve the use of Method 5B in the final rule. 

Method 17 alone is insufficient to address the presence of sulfuric acid. First, Method 5B is often 

required as a test method for determining compliance with other regulatory particulate matter 

standards at facilities. Expressly including Method 5B in Table 5 of the rule would reduce the 

cost burden imposed on facilities by allowing a single test method to demonstrate compliance 

with the proposed MACT standard and other regulatory emission limits. Also, due to Method 

17’s in-stack apparatus, it is not an appropriate method for smaller stacks. See 40 CFR Part 60, 

Appendix A, Method 17, Section 1.2. EPA also states that Method 17 is not applicable for stacks 

that contain liquid droplets or that are saturated with water vapor. Id. Therefore, Method 5B is an 

appropriate and necessary addition to the approved methods in Table 5 of the proposed rule for 

quantifying filterable PM as a surrogate for non-mercury HAP metals. 

Response: Method 5B will not be included in the final rule. A source wishing to use Method 

5B may apply for an alternative testing procedure per Section 63.7(f).

Commenter Name: Traylor Champion

Commenter Affiliation: Georgia-Pacific LLC

Document Control Number: EPA-HQ-OAR-2002-0058-2745.1

Comment Excerpt Number: 62

Comment: The proposed rule at Table 5 of Subpart DDDDD requires the use of EPA Method 5 

or 17 for determination of compliance with the Particulate Matter (PM) emission limits. Table 5 

also specifies the use of EPA Method 29 for the determination of compliance with mercury 

emission limits and EPA Methods 26 or 26A for the determination of compliance with HCl 

emission limits. Materials available on EPA’s Emission Measurement Center Website indicate 

that both Method 29 and Method 26A can be used to determine the PM emission rate along with 

that of their respective hazardous air pollutant. The ability to use these methods in lieu of 

Method 5 or 17 would result in significant convenience and test cost savings. While this could be 

accomplished via a request to EPA for approval of alternative monitoring, amendment of the 

proposed rule to explicitly allow for their use would be a far more efficient resolution. 

Response: A source wishing to use the commenter's approach may apply for an alternative 

testing procedure per Section 63.7(f).

Commenter Name: Lee B. Zeugin

Commenter Affiliation: Utility Air Regulatory Group

Document Control Number: EPA-HQ-OAR-2002-0058-2880.1
37

Comment Excerpt Number: 106

Comment: In Table 5 to proposed Subpart DDDDD, we believe EPA should include Method 

30B as an acceptable mercury performance testing method. RMB’s experience with Method 30B 

indicates that the method can provide superior precision and accuracy at low mercury 

concentrations. Method 30B has been shown to produce comparable results to the methods that 

were specified to collect the Hg emission data upon which EPA has developed the proposed Hg 

emission limits For example, when EPA promulgated Method 30B as a direct final rule, the 

Agency provided the following rationale.[ 14 72 Fed. Reg. 51497 (September 7, 2007).] 

In considering development of a sorbent trap-based reference method, EPA has reviewed 

historical emissions data where sorbent trap measurement systems 

were operated concurrently with either the Ontario Hydro Method or Method 29 (40 CFR part 

60, appendix A-8). EPA has also conducted several field test evaluations of sorbent trap systems 

versus the Ontario Hydro Method in collaboration with the Electric Power Research Institute 

(EPRI). Based on 

these efforts, we have concluded that a sorbent trap-based technique coupled with appropriate 

performance criteria and QA procedures can provide Hg emissions data of quality comparable to

that produced by the Ontario Hydro Method. 

Response: The final rule has added EPA Methods 30 A and 30B. 

Commenter Name: Jim Griffin

Commenter Affiliation: American Chemistry Council

Document Control Number: EPA-HQ-OAR-2002-0058-2792.1

Comment Excerpt Number: 195

Comment: Four Hour Runs Are Not Necessary For All Pollutants. EPA proposes to require each 

stack test run to last at least 4 hours (see 63.7520(d)). While we agree that the limits in this rule 

may require sampling times of at least 4 hours for mercury and dioxin/furan, we do not agree that 

4 hour runs are appropriate in all cases for PM, CO, and HCl. EPA has required only 1-hour runs 

for PM and 2-hour runs for mercury testing under the proposed area source boiler rule. [75 Fed. 

Reg. at 31926; Proposed section 63.11212.] In addition, load-following boilers and process 

heaters may not be able to sustain maximum normal operating load for 3 4-hour test runs. EPA 

should require instead that a minimum sample volume or minimum mass be collected. 

Response: See response to EPA-HQ-OAR-2002-0058-1907.1, Comment Excerpt Number 8.

Commenter Name: Jim Griffin

Commenter Affiliation: American Chemistry Council

Document Control Number: EPA-HQ-OAR-2002-0058-2792.1

Comment Excerpt Number: 196
38

Comment: EPA Should Include Additional Test Methods In The Rule. Table 5 of the proposed 

rule contains the performance testing requirements and acceptable test methods. Mercury 

emissions testing needs to include EPA Method 30B - Sorbent Trap Method as well as an option 

to include a certified mercury CEMS and use EPA Method 30A. Equipment vendors have 

communicated to our members that Method 29 and the Ontario Hydro method (ASTM D6784-

02(2008)) are not considered accurate enough for them to guarantee mercury control 

performance at the extremely low proposed emission limit levels. These are standard tests 

utilized by the electric utility industry for mercury compliance measurements and Method 30B is 

allowed under the proposed CISWI rule.[See Table 6 of 40 C.F.R, Part 60, Subparts CCCC and 

DDDD, at 75 Fed. Reg. 31986 and 32001).] 

Response: The final rule has added EPA Methods 30 A and 30B. 

CEMS: General

Commenter Name: Margaret Sheehan

Commenter Affiliation: Energy Justice Network

Document Control Number: EPA-HQ-OAR-2002-0058-1884.1

Comment Excerpt Number: 6

Comment: The EPA should require Continuous Emissions Monitoring for mercury from all 

biomass boilers. 

The EPA should require biomass plants to use Continuous Emissions Monitoring Systems 

(CEMS) for toxic air pollutants, and to have the data released real time on websites that can be 

accessed by the public. Yearly stack tests do not give an accurate estimate of emissions during 

start-up, shut-down or upset conditions – which, for some pollutants, most notably dioxins – can 

be hundreds of times higher than during steady-state operation (which is when stack testing is 

typically done) [See references 5 and 6 provided by commenter]. CEMS equipment for many of 

these pollutants has been tested and verified by EPA’s Environmental Technology Verification 

Program [See reference 7 provided by commenter]. 

An additional reason that annual and/or quarterly testing for mercury emissions will not provide 

accurate data about the actual day-to-day emissions is because emissions can vary by type of fuel 

used. According to the EPA, the formation of fuel-dependent HAP (hazardous air pollutants), 

including mercury, is dependent upon the composition of the fuel [See reference 8 provided by 

commenter]. Biomass plants mix fuels day-to-day and over time, particularly those burning 

construction, demolition and disaster debris and those co-firing different types of biomass fuels 

or wastes, where the fuel mix may vary depending on market conditions. The fact that biomass 

facilities do not necessarily burn the same materials on a day-to-day basis is reflected in the 

EPA’s definition of biomass that includes many types of materials [See reference 9 provided by 
39

commenter]. Each fuel source (i.e. animal litter, trees, etc.) has different constituents. Some 

biomass plants burn poultry litter, which is included in the EPA’s definition of biomass, and 

which contains mercury [See reference 10 provided by commenter]. Mercury is expected to be 

present in wood in trace amounts attributable to root uptake from soil and deposition of airborne 

mercury to leaves, buds is a highly toxic threat to public health. 

Response: For the operations and facilities subject to the rule, we believe that the combination of 

periodic compliance emissions testing and continuous monitoring of operational and parametric 

control measure conditions is appropriate for assuring ongoing compliance. Using the alternative 

monitoring procedures of the general provisions, the rule allows for the source owner or operator 

to install and operate continuous emissions monitoring systems in lieu of some testing and 

parametric monitoring. This process requires source owners to propose site-specific monitoring 

plans for approval. These plans would include CEMS performance specifications and periodic 

quality assurance and quality control steps to assure the quality of the alternative monitoring 

data. Currently, EPA has the requisite CEMS performance specifications for mercury monitoring 

systems and not for multiple metals CEMS. 

Commenter Name: Kerry Flick

Commenter Affiliation: Metso Power

Document Control Number: EPA-HQ-OAR-2002-0058-2388.1

Comment Excerpt Number: 12

Comment: Measurement of mercury using continuous mercury monitors (CMMs) is currently 

not reliable below about 1 ug/m3. The problem is twofold. The National Institute of Standards 

and Technology has not certifiedcalibrators for low-level measurements, so calibration in these 

low ranges is not possible, and secondly, the errors associated with these low-level 

measurements can be as large as the measured value. Use of CMMs for compliance at the 

proposed limit are just now beginning to be evaluated for low-level measurements. Preliminary 

indications are that they will Dot work reliably to certify low-level numbers to any degree of 

certainty. For some fluegases, the CMMs may work fine, but for other measurements, the CMMs 

may present serious problems. Recent tests were conducted at the EERC’s pilot plant facility 

with known mercury levels at 0.37 ug/m) Measured values from one instrument provided by a 

major vendor indicated a high bias equal to the actual mercury concentration (instrument reading 

0.74 umlm\ Any permit or regulatory limit needs to incorporate the possibility of this bias, 

should continuous monitoring be required. Otherwise, the high bias could potentially cause the 

facility to be noncompliant. 

Response: The proposed rule does not require Hg CEMS.

Commenter Name: Peter Zalzal
40

Commenter Affiliation: Environmental Defense Fund

Document Control Number: EPA-HQ-OAR-2002-0058-2869.1

Comment Excerpt Number: 2

Comment: MERCURY IS A NEUROTOXIN WITH SERIOUS HEALTH AND 

ENVIRONMENTAL EFFECTS 

Mercury is a toxic heavy metal that contaminates water bodies across the nation, threatens the 

development of newborns and children, and contributes to the risk of heart disease. 

Mercury vented into ambient air deposits from the atmosphere in precipitation or attached 

particles, and through runoff or deposition can end up in lakes, rivers, and the ocean. Toxic 

methylmercury results from the transformation of mercury by microorganisms in the sediments 

of water bodies. The methylated mercury accumulates in the aquatic food chain, with 

concentrations increasing at each level in the food chain. According to EPA, the concentrations 

of mercury and other bioaccumulative contaminants in fish tissue far exceed the concentrations 

found in the waterbodies: “top predators in a food chain, such as largemouth bass or walleye, 

may have concentrations of bioaccumulative 

contaminants in their tissues a million times higher than the concentrations found in the 

waterbodies.” [Footnote: U.S. EPA, 2005/2006 NATIONAL LISTING OF FISH ADVISORIES, 

FACT SHEET, EPA-823-F-07-003 (2007).] 

Humans are exposed to methylmercury predominantly through the “[c]onsumption of 

contaminated fish.” [Footnote: Leonardo Trasande, Philip J. Landrigan, & Clyde Schechter, 

Public Health and Economic Consequences of Methyl Mercury Toxicity to the Developing 

Brain, 113 ENVT’L HEALTH PERSP. 590 (May 2005).] As of 2008, all fifty states, the District 

of Columbia, five Native American tribes, Guam, and American Samoa have mercury fish 

consumption advisories. [Footnote: U.S. EPA, 2008 BIENNIAL NATIONAL LISTING OF 

FISH ADVISORIES, TECHNICAL FACT SHEET, EPA-823-F09-007 (2009).] A total of 3,361 

advisories for mercury have been issued at water bodies across the nation encompassing 

16,808,032 lake acres and 1,254,893 river miles. Thirty-eight states have issued statewide fish 

consumption advisories due to extensive mercury contamination in freshwater lakes or rivers, 

coastal waters, or marine fish. [Footnote: These include: Alabama, Alaska, Connecticut, 

Delaware, Florida, Georgia, Hawaii, Idaho, Illinois, Indiana, Kentucky, Louisiana, Maine, 

Maryland, Massachusetts, Michigan, Minnesota, Mississippi, Missouri, Montana, New 

Hampshire, New Jersey, New York, North Carolina, North Dakota, Ohio, Oklahoma, Oregon, 

Pennsylvania, Rhode Island, South Carolina, Texas, Vermont, Washington, West Virginia, 

Wisconsin, and Wyoming.] 

Each year approximately 630,000 newborns in the United States are exposed to mercury levels in 

blood above the levels designed to protect the developing nervous system. [Footnote: 

KATHRYN MAHAFFEY, METHYLMERCURY: EPIDEMIOLOGY UPDATE (2004) 

available at http://www.cetonline.org/ Home/Health/HgEpidemilogyUpdate.pdf.] The 

neurological effects of mercury include documented impairments “in ability to use language, to 

process information, and in visual/motor integration.” [Footnote: U.S. EPA, Methylmercury 

Exposure, www.epa.gov/mercury/exposure.htm.] 
41

The developing brain of infants and young children is distinctly vulnerable to exposure of 

methylmercury, and the National Academy of Sciences’ National Research Council found that 

the brain development of infants and young children is threatened by chronic, low-dose 

environmental exposures to methylmercury. [Footnote: NATIONAL ACADEMY OF 

SCIENCES’ NATIONAL RESEARCH COUNCIL, TOXICOLOGICAL EFFECTS OF 

METHYLMERCURY 4 (2000) (“Chronic, low-dose prenatal MeHg exposure from maternal 

consumption of fish has been associated with more subtle end points of neurotoxicity in children. 

Those end points include poor performance on neurobehavioral tests, particularly on tests of 

attention, fine-motor function, language, visual-spatial abilities (e.g., drawing), and verbal 

memory.”)] In children, low doses may produce deficits in vision and hearing, delayed walking 

and speech development, and other developmental delays. [Footnote: Castoldi, Coccini, 

Ceccatelli, & Manzo, Neurotoxicity and molecular effects of methylmercury, 55 BRAIN RES. 

BULL. 197, 197-203 (2001).] 

In adults, the National Research Council’s assessment of the toxicological effects of 

methylmercury found evidence of “adverse effects on the developing and adult cardiovascular 

system (blood-pressure regulation, heart-rate variability, and heart disease)” including potential 

impacts below neurodevelopmental effects. [Footnote: TOXICOLOGICAL EFFECTS OF 

METHYLMERCURY, supra note 7 at 4.] The National Research Council’s analysis spurred 

scientific research to examine the potential for cardiovascular effects. In 2005, an extensive 

review of studies examining cardiovascular health effects sharpened the focus on the potential 

connection between adult heart disease and methylmercury exposure. The review determined 

that the body of available epidemiological studies ‘suggest an association between MeHg 

exposure and heart disease, including (but possibly not limited to) AMI [acute myocardial 

infarction].” [Footnote: Alan Stern, A review of the studies of the cardiovascular health effects of 

methylmercury with consideration of their suitability for risk assessment, 98 ENVT’L RES. 133, 

133-42 (May 2005).] 

RIGOROUS, ENFORCEABLE MEASURES ARE CRITICAL TO SECURE MERCURY 

EMISSION REDUCTIONS FROM INDUSTRIAL BOILERS AND ADVANCED MERCURY 

MONITORING SYSTEMS ARE A CORNERSTONE OF FINAL RULES FOR INDUSTRIAL 

BOILERS THAT ENSURE TRANSPARENCY AND ACCOUNTABILITY IN PROTECTING 

HUMAN HEALTH AND THE ENVIRONMENT 

Given these serious health and environmental consequences, EPA’s ICI Boiler MACT proposes 

critically important emission limits on mercury from major industrial, institutional, and 

commercial boilers and process heaters. EPA must couple these mercury emission limits with 

rigorous, enforceable monitoring requirements to ensure actual emissions do not exceed the 

limits proposed by EPA. We are concerned that EPA’s proposal, allowing affected sources to 

demonstrate mercury emissions compliance through parameter monitoring or fuel analysis, does 

not provide the emissions monitoring accuracy necessary to ensure actual compliance. EDF 

therefore strongly recommends EPA finalize emissions monitoring and reporting standards that 

are based on advanced mercury monitoring technologies, ensuring transparency and 

accountability in protecting human health and the environment. 
42

Response: See the response to EPA-HQ-OAR-2002-0058-2937.1, Comment Excerpt Number 

42.

Commenter Name: Rich Raiders

Commenter Affiliation: Arkema, Inc

Document Control Number: EPA-HQ-OAR-2002-0058-2751.1

Comment Excerpt Number: 6

Comment: EPA Should Provide Compliance Flexibility For Owners of Continuous Emissions 

Monitors. 

Arkema appreciates that EPA did not require continuous emissions monitors (“CEMS”) in the 

proposed Boiler MACT and generally achievable control technology (“GACT”) area source 

standards. EPA also did not require extensive CEMS use in the proposed CISWI standards. 

However, situations may exist where a facility may elect to install, or may have already installed, 

one or more CEMS units on units regulated in one of the proposed source categories. In these 

cases, EPA should allow facilities to demonstrate compliance using common CEMS protocols 

and relative accuracy test audit (“RATA”) protocols used for other Clean Air Act obligations. 

Facilities opting into using CEMS for compliance with one or more pollutants should be 

exempted from the proposed testing requirements so long as the facility follows appropriate 

CEMS performance demonstrations. 

Response: We agree that we should encourage use of CEMS including for conducting initial 

compliance tests and for demonstrating ongoing compliance. The final rule includes use of 

CEMS in some applications and the general provisions will allow for use of CEMS as 

alternatives to other monitoring in other applications. We agree that we should encourage use of 

CEMS including for conducting initial compliance tests and for demonstrating ongoing 

compliance, and will look to provide guidance that could streamline acceptance of the use of 

CEMS as an option for demonstrating compliance with this rule. 

Commenter Name: Peter Zalzal

Commenter Affiliation: Environmental Defense Fund

Document Control Number: EPA-HQ-OAR-2002-0058-2869.1

Comment Excerpt Number: 6

Comment: Advanced mercury monitoring technologies accurately account for mercury 

emissions 

Advanced mercury monitoring technologies, including mercury CEMS and sorbent traps, 

continuously monitor mercury emissions and provide the needed data accuracy to ensure a robust 

ICI Boiler MACT. CEMS ensure affected units continuously sample and monitor their flue gas, 

thereby providing the accuracy and reliability to secure compliance without relying on highly 

variable proxies that may or may not approximate actual emissions. Sorbent traps provide an 
43

indication of cumulative mercury mass emissions over a period of time. These devices pull gas 

through a set of sorbent traps that capture mercury, which are later analyzed for cumulative 

mercury content. 

These advanced mercury monitoring technologies provide accurate emissions data – both in 

terms of their ability to accurately capture small concentrations of mercury and to continuously 

aggregate these emissions over time. Both mercury CEMS and sorbent traps, for instance, have 

demonstrated the ability to measure mercury concentrations well below 1.0 μg/m3, showing 

good precision in repeat measurements. CEMS and sorbent trap data are available over 90% of 

the time, allowing affected sources to demonstrate compliance based on actual emissions tests far 

more frequently than annual stack tests. CEMS and sorbent traps provide continuous, accurate, 

and precise data on mercury emissions, and as part of its final rule, EPA should require facilities 

to monitor mercury emissions using these advanced mercury technologies. 

Response: See response to Document Control Number: EPA-HQ-OAR-2002-0058-2869.1, 

Comment Excerpt Number: 2.

Commenter Name: Peter Zalzal

Commenter Affiliation: Environmental Defense Fund

Document Control Number: EPA-HQ-OAR-2002-0058-2869.1

Comment Excerpt Number: 7

Comment: IN EPA’S 2005 CLEAN AIR MERCURY RULE, THE AGENCY FOUND THAT 

MERCURY CEMS AND SORBENT TRAPS WERE AVAILABLE AND ESTABLISHED 

MERCURY MONITORING PERFORMANCE STANDARDS BASED ON THEIR 

AVAILABILITY 

The Agency has recognized the bedrock importance of advanced mercury monitoring 

technologies to accurate mercury emissions monitoring. In its 2005 Clean Air Mercury Rule, 

EPA concluded that advanced mercury monitoring technologies were necessary: “Given the 

variability in the unit type, manner of operation, and fuel mix among coal-fired Utility Units, 

EPA believes that emissions must be monitored continuously in order to ensure the precision, 

reliability, accuracy, and timeliness of emissions data that support [CAMR].” 70 Fed. Reg. at 

28631 (May 18, 2005). The Agency also found these advanced mercury technologies were 

available, concluding “[advanced technologies] will be well developed by the time a Hg 

emissions trading program is implemented” and established mercury monitoring performance 

standards based on their availability. Id. at 28636. 

EPA’s 2005 conclusions with respect to the availability of mercury CEMS technology are more 

robust. As of July 2010, facilities had purchased roughly 625 mercury CEMS from primarily two 

manufacturers, with 515 in active operation. [Footnote: NESCAUM Report] In 2009 alone, these 

manufacturers sold 116 CEMS, with 85 already in active operation. [Footnote: NESCAUM 
44

Report] Moreover, in its recently-finalized Portland Cement MACT, the Agency concluded “that 

the growing body of evidence of the successful use of Hg CEMS in the utility industry in the 

U.S. is further evidence that Hg CEMS can be used in the cement kiln industry.” [Footnote: 

Portland Cement MACT at 185] EPA’s conclusion that mercury CEMS are available for cement 

kilns is even stronger with respect to ICI boilers given the substantial similarities between ICI 

boilers and utility boilers. This rapid technological development underscores the conclusion that 

“[m]any of the technical challenges that existed with [Hg CEMS] only a few years ago have now 

been addressed.” [Footnote: Portland Cement MACT] 

Response: See response to Document Control Number: EPA-HQ-OAR-2002-0058-2869.1, 

Comment Excerpt Number: 2.

Commenter Name: Peter Zalzal

Commenter Affiliation: Environmental Defense Fund

Document Control Number: EPA-HQ-OAR-2002-0058-2869.1

Comment Excerpt Number: 8

Comment: SINCE 2005 THE NATION HAS HAD EXPANSIVE IMPLEMENTATION 

EXPERIENCE WITH ADVANCED MERCURY MONITORING TECHNOLOGIES THAT 

HAS FURTHER CONFIRMED AND ADVANCED THEIR AVAILABILITY 

Just as the availability of advanced mercury monitoring technologies has dramatically increased 

since 2005, so too have federal and state agencies expanded their implementation experience 

with these technologies. In the wake of the D.C. Circuit’s vacatur of CAMR, at least 20 states 

have, or plan to have, mercury emissions regulations of their own. [Footnote: U.S. EPA, 

MERCURY MONITORING BY STATES 5 (2009) available at http://www.epa.gov/airmarkt/ 

presentations/docs/epri09/State%20Hg%20Monitoring.ppt#797,5] Of these 20 states, 14 plan to 

use CEMS technology to monitor emissions from electric generating units. [Footnote: U.S. EPA, 

MERCURY MONITORING BY STATES 5 (2009) available at http://www.epa.gov/airmarkt/ 

presentations/docs/epri09/State%20Hg%20Monitoring.ppt#797,5] 

Moreover, the National Institute of Standards and Technology (NIST), the Electric Power 

Research Institute, and EPA are working collaboratively to approve protocols for quality 

assurance and control for mercury CEMS that will ensure the continued accuracy of this 

emissions data. [Footnote: NESCAUM REPORT, supra note 21 at 2.4.] In July 2009, these 

organizations provided interim procedures to states that require use of mercury CEMS and other 

groups that use these systems. [Footnote: NIST, EPA, EPRI, INTERIM EPA TRACEABILITY 

PROTOCOL FOR QUALIFICATION AND CERTIFICATION OF ELEMENTAL MERCURY 

GAS GENERATORS (2009).] As part of its final Portland Cement MACT, EPA adopted the 

NIST protocol as a performance specification, expressly noting the protocol’s applicability to Hg 

CEMS installed on other facilities. [Footnote: Portland Cement MACT at 185 (concluding the 
45

NIST protocol is “fully capable of properly measuring the performance of gaseous Hg CEMS in 

many applications, including cement kilns”).] 

Both the federal government and the states have likewise required installation of advanced 

mercury technologies as part of settlement agreements with affected facilities. As part of its 

settlement agreement with Eastern Kentucky Power Cooperative, EPA required EKPC to install 

mercury CEMS by October 1, 2008, concluding this relief would be “valuable to its efforts to 

encourage the use and development of . . . mercury 

CEMS.” [Footnote: U.S. EPA, EASTERN KENTUCKY POWER COOPERATIVE FACT 

SHEET 3 (Jul. 2, 2007), available at 

http://www.epa.gov/compliance/resources/cases/civil/caa/eastkentucky-fcsht.pdf.] Some states 

have likewise required installation of advanced mercury technologies as part of settlement 

agreements with affected industry. [Footnote: See, e.g., Settlement Agreement Between State of 

Washington Department of Ecology and Transalta Centralia Generation LLC of Air Quality 

Matters, available at http://www.ecy.wa.gov/programs/air/ 

TransAlta/Final_agreement/Transalta_signed_agreement.pdf] Requirements to implement 

advanced mercury monitoring technologies – both through state regulations and federal and state 

settlement agreements – along with developed protocols to ensure these systems provide quality 

data, have further confirmed and advanced the availability of these important technologies. 

Response: See response to Document Control Number: EPA-HQ-OAR-2002-0058-2869.1, 

Comment Excerpt Number: 2.

Commenter Name: Michael Palazzolo

Commenter Affiliation: Alcoa Inc

Document Control Number: EPA-HQ-OAR-2002-0058-2967.1

Comment Excerpt Number: 13

Comment: The proposed provision that CEMS and COMS out of control periods constitute a 

deviation is unreasonable. 

The proposed provisions in §63.7525(a)(6) and c(6) that CEMS and COMS out of control 

periods constitute a deviation is unreasonable and inconsistent with other continuous monitoring 

requirements. Even well-maintained CEMS will have inoperable periods and a requirement for 

100% availability is not appropriate. EPA has past precedents for substitution of missing data 

(for example in 40 CFR 75.33) and typical State CEM requirements allow for minimum data 

availability as a percent of source operating hours. We recommend that EPA revise the rule to 

either require a minimum CEMS or COMS availability of 95 percent of source operating time or 

specify a reasonable missing data substitution procedure based on monitor availability. 

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 
46

data availability requirement. 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 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. 

Commenter Name: Richard T. Metcalf

Commenter Affiliation: Louisiana Mid-Continent Oil and Gas Association

Document Control Number: EPA-HQ-OAR-2002-0058-2699.1

Comment Excerpt Number: 14

Comment: Continuous monitors not needed on work practices. 

EPA should revise the proposed regulatory text to reflect EPA’s intent, expressed in the 

preamble, that CEMS are only required for equipment subject to emission limits and are not 

required for equipment subject to work practice standards. 

Response: EPA believes that the text of the rule is consistent with this approach.

Commenter Name: Stephen R. Gossett

Commenter Affiliation: Eastman Chemical Company

Document Control Number: EPA-HQ-OAR-2002-0058-3137.1

Comment Excerpt Number: 58

Comment: Continuous emission monitoring systems (CEMS) should be allowed in lieu of 

performance testing and continuous parametric monitoring (CPMS). 

While the proposed rule mandates use of a PM CEMS for units over 250 mmBtu/hr rated heat 

input, it does not allow the option to use CEMS in lieu of performance testing, COMS, and 

CPMS. The NSPS for Hospital/Medical/Infectious Waste Incinerators (see Federal Register 

October 6, 2009) includes such a provision (see §60.56c(b)) for PM, D/Fs, HCl, and mercury. 

This rule also allows CEMS to be used in lieu of CPMS (see §60.57c(a)). Likewise, the proposed 
47

CISWI rule (page 31961) allows units using PM CEMS to be exempt from annual performance 

tests and opacity monitoring. Similar provisions should be included in the Boiler and Process 

Heater MACT for PM, mercury, HCl, and D/F. 

Response: See the response to EPA-HQ-OAR-2002-0058-2751.1, Comment Excerpt Number 6.

Commenter Name: Stephen R. Gossett

Commenter Affiliation: Eastman Chemical Company

Document Control Number: EPA-HQ-OAR-2002-0058-3137.1

Comment Excerpt Number: 60

Comment: The provision that any period of CEMS, COMS, or CPMS out of control or loss of 

data is a deviation is unreasonable and inconsistent of other monitoring requirements typical for 

CEMS. 

§63.7525(a)(6) states: “Any period for which the monitoring system is out of control and data are 

not available for required calculations constitutes a deviation from the monitoring requirements.” 

There is a similar provision for COMS at §63.7525(c)(6). With the understanding that any well 

maintained CEMS or COMS will inevitably have periods where it is out of control or out of 

operation, we believe this provision is unreasonable. Many other regulations recognize this and 

build in some reasonable tolerance for missing data. Typical state permit conditions require data 

availability for a minimum percentage of operating hours in a calendar month or quarter. The 

minimum percentage depends on the CEMS technology. Some monitors such as opacity can 

reasonably obtain a 95 percent availability. Regarding CPMS, the HON (40 CFR 63 Subpart G), 

for example, only defines a deviation (excursion) as an operating day where less than 75 percent 

of the parametric data is captured. We note that the proposed CISWI regulation provides for 

minimum data availability (see proposed §60.2735. It would be capricious of EPA to set a 

monitoring requirement that cannot possibly be complied with 100 percent of the time. EPA 

should revise the rule to allow for reasonable amounts of missing data. 

Response: See response to EPA-HQ-OAR-2002-0058-2967.1, Comment Excerpt Number 13.

Commenter Name: N/A

Commenter Affiliation: Sierra Club, Clean Air Task Force, Earthjustice, and Natural Resources 

Defense Council

Document Control Number: EPA-HQ-OAR-2002-0058-3187.1

Comment Excerpt Number: 70

Comment: While EPA explains why it believes CEMs are “reasonable” for larger boilers and 

process heaters for PM and CO, the Agency does not explain why it would not be reasonable to 

require continuous emissions monitoring devices for all pollutants on units that must comply 

with MACT-based standards. In its recent final MACT rulemaking for the Portland cement 
48

industry, EPA requires CEMS to demonstrate compliance with the standards set for mercury, 

HCl, THC, and PM emissions. EPA nowhere explains in the boilers proposal why it does not 

similarly propose CEMS for all boilers and process heaters subject to MACT-based standards. 

Response: For the operations and facilities subject to the rule, and based on the technical and 

economic factors analyzed in developing the monitoring and testing requirements, we believe 

that the combination of periodic compliance emissions testing and continuous monitoring of 

operational and parametric control measure conditions is appropriate for assuring ongoing 

compliance. Using the alternative monitoring procedures of the general provisions, the rule 

allows for the source owner or operator to install and operate continuous emissions monitoring 

systems in lieu of some testing and parametric monitoring. This process requires source owners 

to propose site-specific monitoring plans for approval. These plans would include CEMS 

performance specifications and periodic quality assurance and quality control steps to assure the 

quality of the alternative monitoring data. Currently, EPA has the requisite CEMS performance 

specifications for mercury monitoring systems and not for multiple metals CEMS. 

Commenter Name: N/A

Commenter Affiliation: Sierra Club, Clean Air Task Force, Earthjustice, and Natural Resources 

Defense Council

Document Control Number: EPA-HQ-OAR-2002-0058-3187.1

Comment Excerpt Number: 71

Comment: Moreover, although EPA asserts that it has taken into account periods of start-up and 

shut-down in establishing MACT floors, 75 Fed. Reg. at 32,012, the Agency’s failure to include 

a universal CEMs requirement means that it will not be possible to assess whether sources are 

indeed continuously meeting the MACT floors. That is because parameter testing, by its nature is 

intermittent – as EPA points out, these are stack tests taken periodically, or fuel analysis, 

undertaken periodically, or a combination of both – not “continuous” monitoring. Id. 32,033. 

Assuming “continuous compliance” on the basis of such testing assumes there is no variability 

between one sampling period and the next. EPA’s own data show the falseness of that 

assumption. 

Response: See response to Document Control Number: EPA-HQ-OAR-2002-0058-3187.1, 

Comment Excerpt Number: 70. 

Commenter Name: Mike D. Craig

Commenter Affiliation: New Energy Corp.

Document Control Number: EPA-HQ-OAR-2002-0058-2695.1

Comment Excerpt Number: 1

Comment: The proposed Industrial Boiler MACT standard’s requirement to install CEMs for 

PM, CO, and 02 is unduly burdensome and unnecessary. Two separate Method 5 PM tests show 
49

that NEC is at —50% of the PM limit. A Method 10 CO test showed that NEC was at 22% of the 

CO emission limit. NEC suggests that EPA revise the Industrial MACT standard to require a PM 

and CO performance test every three years, which should be sufficient to demonstrate 

compliance. 

Response: The final rule does not require use of a CO CEMS. EPA has retained the other 

CEMS requirements in the final rule, although specific sources can apply for alternative 

monitoring requirements under the Part 63 general provisions to address some site-specific 

situations.

Commenter Name: Henry T. Graham

Commenter Affiliation: Louisiana Chemical Association

Document Control Number: EPA-HQ-OAR-2002-0058-2731.1

Comment Excerpt Number: 14

Comment: EPA should revise the proposed regulatory text to reflect EPA’s intent, expressed in 

the preamble, that CEMS are only required for equipment subject to emission limits and are not 

required for equipment subject to work practice standards. 

Response: See response to EPA-HQ-OAR-2002-0058-2699.1, Comment Excerpt Number 14.

Commenter Name: W. Randall Rawson

Commenter Affiliation: American Boiler Manufacturers Association

Document Control Number: EPA-HQ-OAR-2002-0058-2698.1

Comment Excerpt Number: 22

Comment: * ABMA believes that the monitoring and CEMS requirements of the Proposed 

Boiler MACT should be clarified. As an initial matter, ABMA recommends that EPA evaluate 

the technical feasibility of in-situ measurements at the very low emission levels identified in the 

proposed rule. To the extent that EPA has not done any such evaluation, ABMA recommends 

that EPA contact CEMS manufacturers to ensure that CEMS will provide an accurate and 

feasible tool for compliance. 

Response: CO CEMS will not be required in the final rule. See the preamble for revisions to the 

CO limitations and compliance demonstration methods. PM CEMS can demonstrate compliance 

with the rule's stringent emission limits.

Commenter Name: Matthew Todd and David Friedman
50

Commenter Affiliation: American Petroleum Institute (API) and National Petrochemical and 

Refiners Association (NPRA)

Document Control Number: EPA-HQ-OAR-2002-0058-2960.1

Comment Excerpt Number: 148

Comment: Proposed 63.7505(d) contains requirements applicable to any continuous monitoring 

system (CMS) associated with demonstrating compliance with an emission limit where a stack 

test is required. This section requires development of a site specific monitoring plan that 

addresses the CMS installation, operation and maintenance. For continuous parameter 

monitoring systems (CPMS), 63.7525(e), (f) and (g) specify QA/QC requirements for continuous 

flow meters, continuous pressure sensors and continuous pH monitors. 

For Continuous Emission Monitors (CEMS) and Opacity Monitors, a subset of CMS, this section 

duplicates the requirements from part 60, Appendix B and 63.2525 that apply to CEMF and 

COMS. There is no justification for requiring site specific plans that essentially will duplicate the 

requirements spelled out in the part 60 Appendices and in the regulation. Thus we believe CEMS 

and COMS should be exempted from the 63.7505(d) requirements. 

Recommendation: Exempt CEMS and COMS from 63.7505(d) requirements. 

Response: EPA will not require monitoring plans under section 63.7505 for sources with 

existing monitoring plans under part 60, Appendix B that meet the requirements of 63.7525 that 

apply to CEMS and COMS.

Commenter Name: Matthew Todd and David Friedman

Commenter Affiliation: American Petroleum Institute (API) and National Petrochemical and 

Refiners Association (NPRA)

Document Control Number: EPA-HQ-OAR-2002-0058-2960.1

Comment Excerpt Number: 154

Comment: Proposed 63.7525(a)(6) specifies For purposes of calculating data averages, you 

must use all the data collected during all periods in assessing compliance. Any period for which

the monitoring system is out of control and data are not available for required calculations 

constitutes a deviation from the monitoring requirements. 63.7525(c)(6) specifies, relative to 

COMS, Any 6-minute period for which the monitoring system is out of control and data are not 

available for required calculations constitutes a deviation from the monitoring requirements. 

As recognized in the General Provisions, other places in this proposal (e.g., 63.7535) and in most 

other rules, CEMS and COMS require routine calibrations, span and drift checks and significant 

outages for Relative Accuracy Test Audits (RATAs). Breakdowns also occur with these 

instruments. It is unprecedented to make outages for these occurrences deviations, particularly 

since the QA/QC activities are required by the rule. Nor has the Agency reflected the costs or 

burdens associated with reporting hundreds of QA/QC activities per year per monitor as 
51

deviations under this rule and Title V in the cost and burden analyses or the Information 

Collection Request. This paragraph should be revised to excuse CO CEMS, O2 CEMS and 

COMS breakdowns, repairs, calibration checks, zero and span adjustments and any other QA/QC 

activity required by the monitoring plan or part 60 Appendix B. The Agency should be 

encouraging proper CEMS and COMS QA/QC rather than discouraging it. 

Recommendation: Remove the language making CEMS and COMS QA/QC outages deviations. 

Response: See response to EPA-HQ-OAR-2002-0058-2967.1, Comment Excerpt Number 13.

Regarding costs, the annual RATA costs for CO CEMS are included in the estimated monitoring 

costs, according to appendix J of the docketed memorandum Revised Methodology for 

Estimating Cost and Emissions Impacts for Industrial, Commercial, Institutional Boilers and 

Process Heaters National Emission Standards for Hazardous Air Pollutants – Major Source. 

Commenter Name: Robert D. Bessette

Commenter Affiliation: Council of Industrial Boiler Owners (CIBO)

Document Control Number: EPA-HQ-OAR-2002-0058-2702.1

Comment Excerpt Number: 160

Comment: Recordkeeping 

Continuous emission monitoring systems (CEMS) in lieu of performance testing and continuous 

parametric monitoring (CPMS). 

While the Proposed Rule mandates use of a PM CEMS for units over 250 MMBtu/hr rated heat 

input, it does not allow the option to use CEMS in lieu of performance testing, COMS, and 

CPMS. The NSPS for Hospital/Medical/Infectious Waste Incinerators (see FR 51368, Oct. 6, 

2009) includes such a provision (see §60.56c(b)) for PM, D/Fs, HCl, and mercury. This rule also 

allows CEMS to be used in lieu of CPMS (see §60.57c(a)). Likewise, the proposed CISWI rule 

(page 31961) allows units using PM CEMS to be exempt from annual performance tests and 

opacity monitoring. Similar provisions should be included in the Boiler and Process Heater 

MACT. 

SO2 CEMS data demonstrating removal of SO2 should be allowed to demonstrate compliance 

with HCl standard. 

CIBO represents members that operates coal-fired boilers equipped with spray dryer absorbers 

(SDAs) to comply with SO2 emission rates. Since HCl is easier to absorb than SO2, if a unit is 

achieving significant SO2 removal, it can be concluded that HCl is being removed at an even 

higher efficiency. The results of the 2009 ICR Phase II performance test conducted on one of 

these boilers illustrate this relationship between SO2 removal and HCl removal very well. The 

SO2 removal during this test was 77 percent whereas no HCl was detected and an HCl removal 

efficiency is estimated at 99.4 percent assuming HCl was present at detection limits. In a case 

like this, a SO2 CEMS is a very good indicator of HCl removal and should be allowed to be used 
52

in lieu of scrubber parameter monitoring. EPA’s proposal to require sorbent input rates to an 

SDA to meet or exceed the rates demonstrated in the performance test will be problematic and 

could result in a waste of sorbent. 

Response: See the response to EPA-HQ-OAR-2002-0058-2751.1, Comment Excerpt Number 6. 

For the HCL issue, see the response to EPA-HQ-OAR-2002-0058-3137.1, Comment Excerpt 

Number 59.

Commenter Name: Robert D. Bessette

Commenter Affiliation: Council of Industrial Boiler Owners (CIBO)

Document Control Number: EPA-HQ-OAR-2002-0058-2702.1

Comment Excerpt Number: 161

Comment: CEMS, COMS, or CPMS Regarding Deviations. 

The provision that any period of CEMS, COMS, or CPMS out of control or loss of data is a 

deviation is unreasonable and inconsistent with other monitoring requirements typical for CEMS. 

The Proposed Rule provides that "[a]ny period for which the monitoring system is out of control 

and data are not available for required calculations constitutes a deviation from the monitoring 

requirements." 75 FR 32055. There is a similar provision for COMS. 75 FR 32055. With the 

understanding that any well maintained CEMS or COMS will inevitably have periods where it is 

out of control or out of operation, we believe this provision is unreasonable. Many other 

regulations recognize this and build in some reasonable tolerance for missing data. 

Typical state permit conditions require data availability for a minimum percentage of operating 

hours in a calendar month or quarter. The minimum percentage depends on the CEMS 

technology. Some monitors such as opacity can reasonably obtain a 95 percent availability. 

Regarding CPMS, the HON (40 CFR 63 Subpart G), for example, only defines a deviation 

(excursion) as an operating day where less than 75 percent of the parametric data is captured. We 

note that the proposed CISWI regulation provides for minimum data availability (see proposed 

§60.2735It would be capricious of EPA to set a monitoring requirement that cannot possibly be 

complied with 100 percent of the time. EPA should revise the rule to allow for reasonable 

amounts of missing data. 

Response: See response to EPA-HQ-OAR-2002-0058-2967.1, Comment Excerpt Number 13.

Commenter Name: Steve Smith

Commenter Affiliation: LyondellBasell Industries

Document Control Number: EPA-HQ-OAR-2002-0058-3118.1

Comment Excerpt Number: 2

Comment: Remove the requirement to do performance test on units to which no emission limits 

apply. 
53

Response: EPA does not believe that the rule text requires any tests where no emission limit 

applies.

Commenter Name: Debra J. Jezouit

Commenter Affiliation: Class of '85 Regulatory Response Group

Document Control Number: EPA-HQ-OAR-2002-0058-2802.1

Comment Excerpt Number: 13

Comment: Proposed 63.7525(a)(4) requires CO CEMS data to be reduced as specified in 

63.8(g)(2). Following the June 1, 2006 revision of 40 C.F.R. 0.13(h) (i.e., harmonization of Part 

60 with Part 75), 40 C.F.R. 63.8(g)(2) is no longer consistent with 60.13(h). The Group 

recommends harmonization of the data reduction requirements in 40 C.F.R. Part 63 with 40 

C.F.R. Parts 60 and 75. 

Response: EPA will not require CO CEMS in the final rule. See the preamble for revisions to 

the CO limitations and compliance demonstration methods.

Commenter Name: Debra J. Jezouit

Commenter Affiliation: Class of '85 Regulatory Response Group

Document Control Number: EPA-HQ-OAR-2002-0058-2802.1

Comment Excerpt Number: 14

Comment: Proposed 63.7525(a)(2) requires a performance evaluation of each CEMS to be 

conducted in accordance with 40 C.F.R. 63.8 and PS 4A of 40 C.F.R. Part 60, Appendix B. The 

Proposed Rule, 40 C.F.R. 63.8, and PS 4A of 40 C.F.R. Part 60, Appendix B, do not specify the 

frequency at which the performance evaluation of the CEMS must be conducted. The Group 

recommends following the frequency specified in Procedure 1 of 40 C.F.R. Part 60, Appendix F 

- Quality Assurance Procedures. 

Response: EPA will not require CO CEMS in the final rule. See the preamble for revisions to 

the CO limitations and compliance demonstration methods.

Commenter Name: David Bonistall

Commenter Affiliation: NewPage Corp

Document Control Number: EPA-HQ-OAR-2002-0058-2920.1

Comment Excerpt Number: 30
54

Comment: As a result of cost reduction measures imposed in order to remain competitive with 

global competition, NewPage has undergone reductions in staff. As a result, our facilities do not 

have the same level of staffing resources we had back when we were working on the previous 

Boiler MACT rule. Opportunities for monitoring flexibility need to be explored to ensure that 

our financial resources and our limited staff resources are utilized wisely. 

In other rules, EPA has provided flexibility with regards to requirements for the installation of 

continuous monitoring equipment. We request EPA consider these alternative approaches in 

order to minimize the cost of compliance for the proposed Boiler MACT rule. An example of 

these flexibilities can be found in 40 CFR 60.45(b)(3) and allows sources whose emissions of 

NOx are less than 70% of the applicable standard to not have to install a CEMs for monitoring 

NOx. In addition there is also a phase in period of one year after the initial performance test for 

sources that do need to install the CEMs. This type of an approach could be easily adopted for 

the continuous monitoring provisions of the Boiler MACT rule. 

Response: EPA has included a number of flexibilities in the rule for demonstrating compliance, 

and has eliminated the CO CEMS requirement. For the operations and facilities subject to the 

rule, we believe that the combination of periodic compliance emissions testing and continuous 

monitoring of operational and parametric control measure conditions is appropriate for assuring 

ongoing compliance.

Commenter Name: Pamela F. Faggert

Commenter Affiliation: Dominion

Document Control Number: EPA-HQ-OAR-2002-0058-2908.1

Comment Excerpt Number: 33

Comment: Proposed Section 63.7535(b) requires monitoring at all times the source is operating 

except for "monitor malfunctions, associated repairs, and required quality assurance or control 

activities (including, as applicable, calibration checks and required zero and span adjustments)." 

Yet, for CO CEMS, and COMS, EPA proposes in Sections 63.7525(a)(6) and 63.7525(c)(6) to 

define each period in which the monitoring system is "out of control," and not providing data for 

calculations, as a "deviation" from monitoring requirements that could result in enforcement. 

While "deviation" is defined in proposed Section 63.7575, the rule does not define "out of 

control". 

The proposed definition of these periods as a deviation is unreasonable and inconsistent with the 

40 CFR Part 63 general provisions. Section 63.8(c)(3) specifically includes "out-ofcontrol" 

periods as one of the exceptions to continuous operation. All monitoring systems will have outof-control periods that could result in some failures of applicable performance specifications. 

Rather than subject source owners/operators to potential enforcement for routine and 

unavoidable failures of performance specifications, EPA should (consistent with its general 

provisions) revise the list of occurrences in proposed Section 63.7535(b) to specifically exempt 

"out of control" periods from the requirement for monitoring operation. An out-of-control 

monitor may need to be taken off-line for evaluation and corrective action, or be calibrated in 
55

order to bring it back into control. EPA’s proposed language also does not explicitly include 

"maintenance periods" even though such periods also are excluded under the monitoring 

provisions in Section 63.8(c)(3). To avoid confusion, EPA should include maintenance in 

Section 63.7525(b) since maintenance is a process that is essential to avoiding breakdowns or 

malfunctions, and generally requires the monitoring systems to be taken off-line. 

Response: See response to EPA-HQ-OAR-2002-0058-2967.1, Comment Excerpt Number 13.

Commenter Name: David Foerter

Commenter Affiliation: Institute of Clean Air Companies

Document Control Number: EPA-HQ-OAR-2002-0058-2937.1

Comment Excerpt Number: 42

Comment: There are circumstances where the use of electronic, or “real-time” Hg CEMS are 

beneficial. These include, among others: 

1. Benchmarking of plant emissions as part of parametric studies (e.g. fuel switching, 

combustion modifications, etc.) to determine variability of emissions and feasibility of emissions 

compliance, 

2. Assessment of abatement system performance (e.g., Activated Carbon Injection - ACI) and 

development of abatement systems design and operational characteristics, 

3. Quantification and documentation of the impact of Start-Up, Shutdown and Malfunction 

(SSM) situations on Hg Emissions, 

4. Monitoring and optimization of Hg Abatement System (e.g., ACI) performance with the goal 

of achieving compliance and optimizing abatement system operating costs, and 

5. Controlling activated carbon injection rates over varying load ranges that are tied to the stack 

outlet emission rate as part of a feed forward/feed-back control logic. 

Both field and laboratory testing support the notion that properly designed and operated Hg 

CEMS can achieve desired accuracies and lower limits of detection (e.g., 0.1 μg/m3). If

Electronic Hg CEMS are employed, on Industrial or Commercial Boilers, for continuous 

monitoring of Hg emissions, for any of the above purposes, EPA should consider waiving 

regular compliance (e.g. sorbent trap) testing of sources. Further, owner/operators should be 

provided the latitude to take actions such as fuel switching, process changes, etc. without the 

requirement for additional testing, data gathering or reporting. In this scenario, is assumed the 

Electronic Hg CEMS would be National Institute of Standards and Technology ( NIST) 

traceable, would undergo regular service, maintenance and calibrations, and would meet agreedupon data recovery thresholds. 

Response: For the operations and facilities subject to the rule, we believe that the combination of 

periodic compliance emissions testing and continuous monitoring of operational and parametric 

control measure conditions is appropriate for assuring ongoing compliance. Using the alternative 

monitoring procedures of the general provisions, the rule allows for the source owner or operator 

to install and operate continuous emissions monitoring systems in lieu of some testing and 
56

parametric monitoring. This process requires source owners to propose site-specific monitoring 

plans for approval. These plans would include CEMS performance specifications and periodic 

quality assurance and quality control steps to assure the quality of the alternative monitoring 

data. Currently, EPA has the requisite CEMS performance specifications for mercury monitoring 

systems and not for multiple metals CEMS. 

Commenter Name: David Foerter

Commenter Affiliation: Institute of Clean Air Companies

Document Control Number: EPA-HQ-OAR-2002-0058-2937.1

Comment Excerpt Number: 43

Comment: In the Clean Air Mercury Rule, EPA recognized the importance of continuously 

monitoring the mercury emissions of electric utility boilers that had the potential to emit above a 

specified annual mass emission threshold, and in that rule required all such mercury emitters 

subject to the rule to continuously monitor mercury emissions using continuous analyzers or 

sorbent traps. We believe that this is a sound approach that EPA should consider for this rule for 

the following reasons: 

* Emissions during startup, shutdown and malfunction are of even greater concern for larger 

emitters of mercury than lower emitters of mercury. Periodic stack testing will not adequately 

address emissions during startup, shutdown and malfunction. Continuous monitoring of mercury 

emissions will provide the best means of knowing mercury emissions during startup, shutdown 

and malfunction for these sources. 

* Different industries should be treated in consistent manners when dealing with monitoring 

requirements for any given pollutant. For this reason, industrial boilers with similar annual 

mercury mass emissions as a utility boiler should be subject to similar monitoring requirements 

as the utility boiler. 

* By having a common total mass emission threshold over which continuous monitoring of 

mercury is necessary for all industries, there would be consistency in the monitoring requirement 

for sources in different industries. 

* Continuous monitoring of mercury emissions is now proven. Numerous electric utility plants 

have successfully implemented mercury continuous emission monitoring systems 

* per a report issued by the Northeast States for Coordinated Air Use Management (NESCAUM) 

titled, “Technologies for Control and Measurement of Mercury Emissions from Coal-Fired 

Power Plants in the United States: A 2010 Status Report”, released in July 2010. There is no 

reason to believe that the same technology that is successfully deployed on electric utility boilers 

could not be successfully deployed at industrial boiler sites. 

Response: See response to Document Control Number: EPA-HQ-OAR-2002-0058-2937.1, 

Comment Excerpt Number: 42. 

Commenter Name: Russ A. Wozniak
57

Commenter Affiliation: Dow Chemical Company

Document Control Number: EPA-HQ-OAR-2002-0058-2632.1

Comment Excerpt Number: 47

Comment: EPA Should Establish a 95% On-line Monitoring System Requirement vs. 

Concluding that Each Instance of Data Unavailability is a Deviation. EPA proposes in 

63.7525(a)(6) that "any period for which the monitoring system is out of control and data are not 

available for required calculations constitutes a deviation from the monitoring requirements." 

Minor problems with the monitoring system (e.g., Continuous Emission Monitoring System or 

Continuous Parameter Monitoring Systems) should not automatically be classified as a deviation 

from the MACT rule. EPA should instead require that the monitoring system be in service and 

recording data for at least 95% of the operating time of the boiler/heater. This type of regulatory 

requirements is consistent with other Part 63 rules and would prevent small instances of 

monitoring system outages from being treated as a deviation versus the rule requirements. 

For example, in the companion proposal for CISWI, EPA has proposed for CEMS a minimum of 

85% of the hours per day, 90% of the hours per quarter, and 95% of the hours per year. In that 

proposal Dow is requesting a similar approach for CPMS, since monitoring systems are not 

perfect, and EPA has not supplied information to show that best performers are perfect. 

Proposed revisions to 40 CFR 63.7525(a)(6) are as follows: 

"... if the monitoring system is out of control and data are not available for greater than 5% of 

the operating time of the boiler or process heater then this constitutes a deviation from the 

monitoring requirements. 

Response: See response to EPA-HQ-OAR-2002-0058-2967.1, Comment Excerpt Number 13.

Commenter Name: Chris M. Hobson

Commenter Affiliation: Southern Company

Document Control Number: EPA-HQ-OAR-2002-0058-2741.1

Comment Excerpt Number: 70

Comment: In general, Section 63.7525(a) (for CO CEMS) and Section 63.7525(b) (for PM 

CEMS) are inconsistent in their level of detail. For example, Section 63.7525(b)(2) specifies a 

timeline for completing the initial performance evaluation for PM CEMS but this is not specified 

for CO CEMS certification. 

Response: CO CEMS will not be required in the final rule. See the preamble for revisions to the 

CO limitations and compliance demonstration methods.
58

Commenter Name: Russ A. Wozniak

Commenter Affiliation: Dow Chemical Company

Document Control Number: EPA-HQ-OAR-2002-0058-2632.1

Comment Excerpt Number: 75

Comment: Continuous and Parameter Monitoring Systems - EPA’s proposed rule does not 

address times when monitoring equipment malfunctions. Even the best performing emission 

sources will experience a malfunction of either emission monitoring or parameter monitoring 

equipment over a multiple year period. Thus, EPA’s final rule should recognize and address 

these situations or clarify that 95% of the operating data is sufficient. 

EPA proposes in section 63.7525(a)(6) that "any period for which the monitoring system is out 

of control and data are not available for required calculations constitutes a deviation from the 

monitoring requirements". 

Minor problems/malfunctions with Continuous Emission Monitoring systems or parameter 

monitoring systems should not automatically be classified as a deviation from the MACT rule. 

EPA should instead require that the monitoring system be in service and recording data for at 

least 95% of the operating time of the boiler/heater. This type of regulatory requirement is 

consistent with other Part 63 rules and would prevent small instances of monitoring system 

outages from being treated as a deviation and perhaps non-compliance versus the rule 

requirements. 

Dow proposes that EPA revise 40 CFR 63.7525(a)(6) as follows: 

"... if the monitoring system is out of control and data are not available for greater than 5% of 

the operating time of the boiler or process heater then this constitutes a deviation from the 

monitoring requirements. 

Response: See response to EPA-HQ-OAR-2002-0058-2967.1, Comment Excerpt Number 13.

Commenter Name: Jim Weeks

Commenter Affiliation: Michigan Municipal Electric Association

Document Control Number: EPA-HQ-OAR-2002-0058-2795.1

Comment Excerpt Number: 8

Comment: CEMS Flexibility: EPA’s rule should provide flexibility for monitoring requirements 

at electric units where the stacks would not permit the installation of CEMS, or there is no need 

or justilication for the burden and expense of a new CEMS system. Both Holland and Marquette 

believe that the stacks at their DeYoung Units 3&,4 and Shims Unit 2 respectively are too small 

and outdated to permit the installation of CEMS equipment to be able to comply with 18 IvIACT 

monitoring requirements. This technical challenge would mc-an that installation of CEMS could 

require the removal and re-construction of new stacks. Such costs are not economic or feasible. 

Moreover, as Marquette explained in its separately-filed comments, Shiras 2 is already meeting 
59

the emissions limitations and standards proposed by EPA in this rule for FiNi due to the unit’s 

baghouse. Vet, the requirement to install CEMS to monitor a unit like this, already in 

compliance, would be sufficiently costly as to divert resources from keeping the unit’s bagliouse 

pollution controls in optimal shape and performance. 

For these reasons, MMEAtHollandill arquette request that EPA change the rule to allow electric 

utility units to be able to take advantage of monitoring flexibility if it can be demonstrated to 

State permitting authorities that the installation of new CEMS units are technically or 

economically infeasible. Instead, such units should be permitted to conduct annual stack tests or 

other feasible approaches to be able to demonstrate compliance. 

Response: The rule allows alternative performance test or monitoring procedures per the 

requirements in Sections 63.7(f) and 63.8(f).

Commenter Name: Rachel Smolker

Commenter Affiliation: Biofuelwatch

Document Control Number: EPA-HQ-OAR-2002-0058-2805.1

Comment Excerpt Number: 10

Comment: EPA Should Require Continuous Emissions Monitoring for Mercury from All 

Biomass Boilers. 

The EPA should require biomass plants to use Continuous Emissions Monitoring Systems 

(CEMS) for toxic air pollutants, and to have the data released real time on websites that can be 

accessed by the public. Yearly stack tests do not give an accurate estimate of emissions during 

start-up, shut -down or upset conditions – which, for some pollutants, most notably dioxins – can 

be hundreds of times higher than during steady-state operation (which is when stack testing is 

typically done). [DeVries, C. RauchgasemissionenundVerfahrensoptimierungen wa¬hrend der 

ausserordentlichen Betriebssituation An- und Abfahren der Mu¬llverbrennungsanlage in 

Amsterdam. In VDI Handbuch BAT- und preisorientierte Dioxin-

/Gesamtemissionsminimierungstechniken; VDI Verlag: Du¬sseldorf, 1999]. [Neuer-Etscheidt, 

K., H. O. Nordsieck, et al. (2006). "PCDD/F and other micropollutants in MSWI crude gas and 

ashes during plant start-up and shut-down processes." Environ Sci Technol 40(1): 342-9 

http://www.ejnet.org/toxics/cems/2006_NeuerEtscheidt_dioxins_MSWI_gas_ashes_startup_shutdown.pdf] CEMS equipment for many of 

these pollutants has been tested and verified by EPA’s Environmental Technology Verification 

Program. [[U.S. Environmental Protection Agency, Advanced Monitoring Systems Center -

Verified Technologies. http://www.epa.gov/etv/vt-ams.html] 

Response: See the response to EPA-HQ-OAR-2002-0058-2937.1, Comment Excerpt Number 

42.
60

Commenter Name: Rachel Smolker

Commenter Affiliation: Biofuelwatch

Document Control Number: EPA-HQ-OAR-2002-0058-2805.1

Comment Excerpt Number: 11

Comment: An additional reason that annual and/or quarterly testing for mercury emissions will 

not provide accurate data about the actual day-to-day emissions is because emissions can vary by 

type of fuel used. According to the EPA, the formation of fuel -dependent HAPs, including 

mercury, is dependent upon the composition of the fuel. [Federal Register /Vol. 75, No. 107 / 

Friday, June 4, 2010 / Proposed Rules, pg 32017.] Biomass plants mix fuels day-to-day and over 

time, particularly those burning C&D and disaster debris and those co-firing different types of 

biomass fuels or wastes, where the fuel mix may vary depending on market conditions. The fact 

that biomass facilities do not necessarily burn the same materials on a day -to-day basis is 

reflected in the EPA’s definition of biomass that includes many types of materials.16 [Federal 

Register /Vol. 75, No. 107 / Friday, June 4, 2010 / Proposed Rules, pg 32063] Each fuel source 

(i.e. animal litter, trees, etc.) has different constituents. Some biomass plants burn poultry litter, 

which is included in the EPA’s definition of bi omass, and which contains mercury. [Gupta, 

Giman and Kelly, Pete, “Poultry litter toxicity comparison from various bioassays,” Journal of 

Environmental Science and Health, Part A, Volume 27, Issue 4, May 1992.] Mercury is expected 

to be present in wood in trace amounts attributable to root uptake from soil and deposition of 

airborne mercury to leaves, buds and bark. [Massachusetts Department of Environmental 

Protection. Mercury in Massachusetts: Emission Monitoring and Source Release Estimates. 

Retrieved from http://www.mass.gov/dep/toxics/stypes/hgch3c.htm#table3x14] Some waste 

wood may contain mercury or other metals in paints applied to their surfaces. Id. The same fuel 

can also vary by the treatment it has been given. For example, if pesticides and herbicides are 

used on the agricultural wastes, the emissions will be different than for agricultural wastes 

without herbicides and pesticides. 

In addition to mercury contamination, contamination from toxic and hazardous air pollutants 

found in C&D debris such as copper, iron and zinc need to be addressed through increased 

monitoring. These metals are strongly correlated with dioxin formation and can serve as catalysts 

for dioxin formation.19, 20 [Hinton, W.S., Lane, A.M., "Characteristics of municipal solid waste 

incinerator fly ash promoting the formation of polychlorinated dioxins," Chemosphere, Vol. 22, 

p. 473-483, 1991.] [Gullett, B., Bruce, K., Beach, L., Drago, A., "Mechanistic steps in the 

production of PCDD and PCDF during waste comb ustion ," Chemosphere, Vol. 25, p. 1387, 

1992.] 

Response: See response to Document Control Number: EPA-HQ-OAR-2002-0058-2805.1, 

Comment Excerpt Number: 10. 

Commenter Name: Jim Eubank

Commenter Affiliation: Kentucky Division of Air Quality
61

Document Control Number: EPA-HQ-OAR-2002-0058-3176.2

Comment Excerpt Number: 12

Comment: Provisions to 40 CFR 63.7505(c) should be made to allow compliance 

demonstrations by HCl or Hg CEMS after accuracy has been established, especially considering 

that fuel constituents will heavily influence the emissions of both HAPs. 

Response: See the response to EPA-HQ-OAR-2002-0058-2751.1, Comment Excerpt Number 6.

Commenter Name: David W. Peightal

Commenter Affiliation: Dakota Gasification Company

Document Control Number: EPA-HQ-OAR-2002-0058-3179

Comment Excerpt Number: 19

Comment: DGC supports annual stack testing to verify compliance with the proposed standards 

as opposed to installing CEMS. 

Response: For the operations and facilities subject to the rule, we believe that the combination 

of periodic compliance emissions testing and continuous monitoring of operational and 

parametric control measure conditions is appropriate for assuring ongoing compliance.

Commenter Name: Brad James

Commenter Affiliation: Trinity Consultants

Document Control Number: EPA-HQ-OAR-2002-0058-2853.1

Comment Excerpt Number: 22

Comment: Periodic measurements taken at regular intervals will adequately capture the 

emission profile of the source. Because the proposed regulation is in the form of a daily or 

monthly average, continuous monitoring is not needed. Any fluctuations in the emission profile 

will be accounted for by the regular readings that will occur over days, months, and years. 

CEMS will not reveal any new information or assist a facility in complying with its emission 

limitations. 

Response: For the operations and facilities subject to the rule, we believe that the combination 

of periodic compliance emissions testing and continuous monitoring of operational and 

parametric control measure conditions is appropriate for assuring ongoing compliance.

Commenter Name: Lee B. Zeugin

Commenter Affiliation: Utility Air Regulatory Group

Document Control Number: EPA-HQ-OAR-2002-0058-2880.1
62

Comment Excerpt Number: 60

Comment: EPA proposes to require monitoring at all times the source is operating except for 

“monitor malfunctions, associated repairs, and required quality assurance or control 

activities(including, as applicable, calibration checks and required zero and span adjustments).” 

Proposed § 63.7535(b). In addition for CO CEMS, and COMS, EPA proposes to define each 

period in which the monitoring system is “out of control,” and not providing data for 

calculations, as a “deviation” of monitoring requirements that could result in enforcement. 

Proposed §§ 63.7525(a)(6), 63.7525(c)(6), 63.7575. Although EPA does not define “out of 

control” in proposed § 63.7575, EPA provides the following examples for COMS -- “including 

any periods that the COMS fails to pass a daily calibration drift assessment, a quarterly 

performance audit, or an annual zero alignment audit.” Proposed § 63.7525(c)(6). Section § 

63.8(c) generally defines “out-of-control” to include failure of a calibration or performance audit. 

EPA’s proposed definition of these periods as a deviation is unreasonable and inconsistent with 

the Part 63 general provisions. Section 63.8(c)(3) specifically includes “out-ofcontrol” periods as 

one of the exceptions to continuous operation. All monitoring systems will have out-of-control 

periods and EPA has provided no data to suggest that it has proposed use of technology or 

applicable performance standards that would not result in some failures of applicable 

performance specifications. Rather than subject source owners/operators to potential 

enforcement (and citizen suits) for routine and unavoidable failures of performance 

specifications, EPA should (consistent with its general provisions) revise the list of occurrences 

in proposed § 63.7535(b) to specifically exempt “out of control” periods from the requirement 

for monitoring operation.[ EPA’s proposed language also does not explicitly include 

“maintenance periods” even though such periods also are excluded under the monitoring 

provisions in § 63.8(c)(3). To avoid confusion, EPA should include maintenance in § 63.7525(b). 

Maintenance is a process that is essential to avoiding breakdowns or malfunctions, and generally 

requires the monitoring systems to be taken off-line.] An out-of-control monitor may need to be 

taken off-line for evaluation and corrective action, or be calibrated in order to bring it back into 

control. 

Response: See response to EPA-HQ-OAR-2002-0058-2967.1, Comment Excerpt Number 13.

CO CEMS 

Commenter Name: Brian Swanson

Commenter Affiliation: CMC Solutions and CMC Support

Document Control Number: EPA-HQ-OAR-2002-0058-0841.1

Comment Excerpt Number: 1

Comment: Paragraph 63.7525 of the proposed rule states the following: “What are my 

monitoring, installation, operation, and maintenance requirements? 
63

(a) If your boiler or process heater has a heat input capacity of 100 MMBtu per hour or greater, 

you must install, operate, and maintain a continuous emission monitoring system (CEMS) for 

CO and oxygen according to the procedures in paragraphs (a)(1) through (6) of this section by 

the compliance date specified in §63.7495. The CO and oxygen shall be monitored at the same 

location at the outlet of the boiler or process heater.” 

We are proposing that this rule be modified to allow the use of an alternative monitoring system 

such as a predictive emissions monitoring system (PEMS). The above paragraph could be 

revised to read as follows: “What are my monitoring, installation, operation, and maintenance 

requirements? 

(a) If your boiler or process heater has a heat input capacity of 100 MMBtu per hour or greater, 

you must install, operate, and maintain a continuous emission monitoring system (CEMS) or an 

approved alternative emission monitoring system for CO and oxygen according to the procedures 

in paragraphs (a)(1) through (6) of this section by the compliance date specified in 63.7495. The 

CO and oxygen shall be monitored at the same location at the outlet of the boiler or process 

heater.” 

PEMS are a very cost effective and robust alternative to a CEMS and has proven itself in many 

40 CFR Part 60 and 40 CFR Part 75 applications. The following information provides detailed 

information and justification for PEMS as an alternative to CEMS. 

PEMS as an Alternative to CEMS 

U.S. regulations require continuous emissions monitoring systems (CEMS) and allow for the use 

of predictive approaches as an alternative providing the installed predictive emissions monitoring 

system (PEMS) meets rigorous performance specification criteria and the site performs ongoing 

quality assurance tasks such as periodic audits with portable analyzers and annual accuracy 

testing. PEMS have been used in the U.S. for gas turbine compliance monitoring under 40 CFR 

Part 60 for more than 20 years. 

Prior to the promulgation of CEMS requirements in the U.S., process emissions were verified 

using simple parametric equations or manual stack test procedures (U.S. EPA Reference 

Methods). Modern empirical PEMS have also evolved to meet the need for continuous 

monitoring of process emissions at the lowest possible cost. There are performance specification 

tests and periodic audits such as the annual relative accuracy test audit that are equivalent in cost 

as those required of compliance CEMS, however, PEMS can provide years of service with little 

or no ongoing operational or maintenance cost with a robust model developed and in place. 

PEMS used for compliance are certified according to the rigorous standards specified using PS16 (Part 60) or Subpart E (Part 75). These certifications require the PEMS to pass a relative 

accuracy test audit (RATA). In addition to these tests, SmartCEMTM provides additional quality 

assurance through EPA mandated performance tests. These include online input validation, drift 

analysis, input failure analysis, statistical analysis, model operating envelope analysis, and other 

automated procedures and tests as specified in 40 CFR Part 75, Subpart E and in 40 CFR Part 60, 

Appendix B, PS-16. The test results are used to evaluate a SmartCEMTM PEMS model prior to 

deployment and are presented to regulatory agents as part of the certification process. All 

performance tests are completed prior to RATA testing, such that the reference method RATA 

test witnessed by the regulatory agency is the final step in the procedure to achieve certification 

of a 40 CFR Part 60 compliance PEMS or for a 40 CFR Part 75 Subpart E application with the 

exception of the required report submittal and petition to U.S. EPA Administrator. 
64

Background 

CMC Solutions, L.L.C. (CMC) is a leading supplier of predictive emissions monitoring systems 

for compliance with Subpart E of 40 CFR Part 75. CMC Solutions, L.L.C. has been developing 

PEMS for compliance monitoring purposes for 18 years and has extensive experience with 

continuous and predictive emissions monitoring systems, quality assurance, NSPS regulations 

under 40 CFR Part 60, 40 CFR Part 75, and other regulatory programs administered by U.S. 

EPA. CMC Solutions, L.L.C. participated in the recently completed U.S. EPA PEMS 

demonstration program and has certified many statistical hybrid predictive emissions monitoring 

systems (PEMS) to date for compliance with both 40 CFR Part 60 and 40 CFR Part 75. 

CMC’s statistical hybrid model is an empirical system that is used for predictive monitoring and 

compliance reporting of gas turbine, boiler, and other process emissions. Typically process and 

emission data is collected and a master dataset of historical emissions is compiled. This historical 

training dataset is used to generate a prediction in real-time from the current process state. The 

model was enhanced recently such that configuration is done automatically once the historical 

training data is added. The resulting prediction is entirely dependent on the quality and quantity 

of historical training data collected, and is fundamentally deterministic – each process vector 

yields a singular prediction for the various pollutants and diluents that were measured and 

recorded in the historical training dataset. 

CMC has focused on developing a PEMS that is robust and accurate across the full range of 

operations of the regulated unit including startups and shutdowns and can meet the requirements 

of 40 CFR Part 60 and 40 CFR Part 75 Subpart E. CMC’s product is a statistical hybrid model 

that has been optimized to utilize a great variety of potential process inputs to accurately and 

reliably predict pollutant and diluent content of the stack gas exhaust and mass emission rates for 

use in regulatory compliance reporting. This statistical hybrid PEMS has been certified to the 

requirements of 40 CFR Part 75, Subpart E and demonstrated the same or better accuracy, 

reliability, timeliness, and is currently being used and quality assured per the regulations at 15 

sources in the U.S. 

The product has been designed to meet the quality assurance requirements of 40 CFR Part 60, 

Appendix F and 40 CFR Part 75, Appendix B. CMC provides a quality control regimen that is 

designed to provide a similar level of assurance that the system is functioning normally as those 

required by CEMS under the same regulations. This includes ongoing periodic quality control 

checks such as the daily calibration error and quarterly linearity error testing required for CEMS. 

SmartCEMTM PEMS Quality Assurance 

The calibration error test is conducted by first sending the SmartCEMTM Analyzer a nonoperating or low-pollutant level process vector representing the average values of all process 

inputs recorded during a non-operating or low-pollutant level period. The SmartCEMTM 

Analyzer will provide predictions that should reflect either zero emissions or low-pollutant levels 

that can evaluated against a zero emission or low-pollutant level as measured by reference 

method testing. Subsequently, a process vector representing a base load (span) or high-pollutant 

level is presented to the analyzer. This process condition is documented during previous annual 

reference method testing. This RM test data is used to determine a base load (span) or highpollutant level that should be equivalent to the predicted emission for this high-pollutant level 

process condition. 
65

The calibration error test can be conducted every day as is done for a CEMS or it can be 

conducted every hour or even every minute if required. This PEMS calibration error test is a 

valid test of the entire system if the inputs are properly simulated upstream of all PEMS 

processing such that the entire system is evaluated for normal functionality and response. If the 

historical training dataset is corrupted, has been biased, or has lost its connectivity with the 

PEMS Analyzer, the resulting calibration record (zero and span) would not be consistent with the 

values provided during RM testing. This would cause a calibration failure and an alarm would be 

raised that would be resolved by PEMS support staff onsite or the PEMS supplier would be 

contacted to resolve the issue. 

Similarly, a linearity error test can be performed on any PEMS model. The annual three-load 

RATA tests can be used to determine three process calibration records representing the average 

measured value for each process parameter during the RATA tests. These three process vectors 

designated low, mid, and high-level audit points can be presented to the PEMS Analyzer for 

predictions. The resulting predictions can be evaluated against the average RM test value 

obtained during that year’s RATA. The deviation can be recorded and submitted on a quarterly 

basis for the linearity error test. This test is valid for a PEMS just as with a CEMS, in that it 

validates a low, mid, and high-level predicted emission level against a reference method or 

standard. The test ensures proper functionality of the entire PEMS across the emission range of 

the combustion unit. 

In addition to these tests, SmartCEMTM provides additional quality assurance through EPA 

mandated performance tests. These include online input validation, drift analysis, input failure 

analysis, statistical analysis, model operating envelope analysis, and other automated procedures 

and tests as specified in 40 CFR Part 75, Subpart E and in 40 CFR Part 60, Appendix B, PS-16. 

The test results are used to evaluate a SmartCEMTM PEMS model prior to deployment and are 

presented to regulatory agents as part of the certification process. All performance tests are 

completed prior to RATA testing, such that the reference method RATA test witnessed by the 

regulatory agency is the final step in the procedure to achieve certification of a 40 CFR Part 75 

Subpart E application with the exception of the required report submittal and petition to U.S. 

EPA Administrator. 

Sample CO PEMS Installations 

CO monitoring using PEMS is a proven technology that has been used for years with 

installations being certified under 40 CFR Part 60, 40 CFR Part 75, and PS-16. Pavilion 

Technologies one of the leading suppliers of PEMS has a number of CO monitors in place some 

of which are summarized in the following list. 

? Mead Coated Board January 28, 2003 

? White Star RATA Sept 26, 1999 GT#1 

? White Star RATA Oct 2-3, 1999 GT#2 

? White Star RATA Sept 28, 1999 GT#1 

? TASC Environmental Services November 22,2000 THW-33 

? TASC Environmental Services November 21, 2000 THW-34 

? TASC Environmental Services November 21, 2000 THW-43 

? RMB Consulting & Research Inc Oct 30, 1997 THW-31 

? Air Techniques Inc. Boiler #1 

? Air Techniques Inc. Boiler #2 

? Mobley-Degussa 8/30/2000 Boiler #3 
66

? TASC Env Services Oct 21, 1999 GT-30 

? TASC Env Services Oct 28, 1999 GT-32 

? TASC Env Services Oct 22, 1999 GT-33 

? TASC Env Services Oct 28, 1999 GT-45 

? TASC Env Services Sept 28, 1999 GT-62 

? TASC Env Services Oct 8, 1999 GT-63 

? TASC Env Services Oct 21, 1999 GT-66 

? TASC Env Services Oct 15, 1999 GT-67 

In addition CMC Solutions has a number of PEMS in place which monitor CO emissions which 

include. 

? Dearborn Industrial Generation, Dearborn, Michigan – three 170 MW gas turbines (Part 75). ? 

Dearborn Industrial Generation, Dearborn, Michigan – three 750 mmBtu natural gas and blast 

furnace gas fired boilers (Part 75). ? T. H. Wharton, Houston, Texas – eight 60 MW gas turbines 

(Part 75). 

? The Ohio State University, Columbus, Ohio – four 206 mmBtu gas/oil fired boilers 

(Part 60). ? SABIC, Saudi Arabia – three 126 MW gas boilers. ? SABIC, Saudi Arabia – two 63 

MW natural gas and waste heat alcohol fired 

boilers. ? SABIC, Saudi Arabia – two 126 MW natural gas and waste heat alcohol fired boilers. 

Response: See the preamble for revisions to the CO limitations and compliance demonstration 

methods. A PEMS approach for compliance with the standards would require an alternative 

monitoring request under the Part 63 general provisions.

Commenter Name: Houston Public Hearing Transcript

Commenter Affiliation: See transcript for detailed list of commenters

Document Control Number: EPA-HQ-OAR-2002-0058-1876

Comment Excerpt Number: 8

Comment: Eliminate carbon monoxide limits for biomass 

boilers under the area source rule, and its -- and 

instead regulating these small sources using the tune-up 

work practice requirements. 

Response: See the preamble for revisions to the CO limitations and compliance demonstration 

methods.

Commenter Name: William C. Herz

Commenter Affiliation: The Fertilizer Institute

Document Control Number: EPA-HQ-OAR-2002-0058-1910.1

Comment Excerpt Number: 4
67

Comment: In the proposed rule, EPA states that operators of boilers or process heater units 

having a heat input capacity of less than 10 million MMBtu/h, or boilers or process heaters of 

any size which combust natural gas or refinery gas as discussed in section IV.D.3 of the 

preamble, are not subject to testing and initial compliance requirements. Rather, owners or 

operators of such boilers and process heater units must submit to the delegated authority or EPA, 

as appropriate, if requested, documentation that a tune-up meeting the requirements of the 

proposed rule was conducted. 75 Fed. Reg. at 32,014. 

However, under section III.G of the Major Source Boiler rule preamble, for boilers and process 

heater units in any of the subcategories with heat input capacities greater than 100 MMBtu/h, 

EPA proposes continuous CO monitoring and maintenance of the average CO emissions at or 

below the applicable limits.. 75 Fed. Reg. at 32,015. 

TFI requests clarification on whether natural gas-fired boilers and process heater units with heat 

input capacities greater than 100 MMBtu/h are required to install, operate and maintain 

continuous CO monitors. 

Response: See the preamble for revisions to the CO limitations and compliance demonstration 

methods.

Commenter Name: Robin Mills Ridgway

Commenter Affiliation: Purdue University

Document Control Number: EPA-HQ-OAR-2002-0058-2782.1

Comment Excerpt Number: 3

Comment: Though we commend EPA for attempting to allow for variability by averaging the 

CO concentration over a 30-period and for using CO as a surrogate for organic HAPs, the 

proposed limits are too low to comply with over any averaging period. Purdue suggests that in 

lieu of a single set ppm limit for CO all coal fired boilers and using a CO CEMS to demonstrate 

continuous compliance, EPA consider the following alternate path for achieving emissions 

reductions. In the preamble of the proposed rule and throughout the proposed rule itself, EPA 

makes clear its desire to encourage energy efficiency in all operations as a key component of any 

emission reduction program. 

As an alternative to the proposed CO compliance requirements for solid fuel fired boilers having 

a heat input > 250 MMBTU/hr, Purdue asks that EPA borrow from the work practice standards 

by requiring the source to annually perform an ASME PTC 4-2008 performance test at several 

boiler load levels; combustion tuning for optimal combustion performance at various load points 

can establish an arithmetic CO ppm or lb/mmBtu compliance level for the specific source at a 

specific load level. The “bins” are the loads at which a boiler is most frequently operated and can 

be determined easily from historical operating data using the protocols outlined in 40 CFR Part 

75 Appendix A 6.5.2.1, paying particular attention to tuning at the “normal” load according to 

Part 75 Appendix A. To ensure continuous compliance with the “good tuning”, the source would 

then use the CO CEMS to “police” the boiler combustion performance in real time to 
68

performance obtained during ASME PTC 4-2008 performance testing using a bin methodology 

for load range of CO established during testing. Compliance would be demonstrated by not 

exceeding bin level emissions for some period of time or quantity level over time. Purdue 

welcomes further discussion with EPA regarding this approach. 

Response: See the preamble for revisions to the CO limitations and compliance demonstration 

methods.

Commenter Name: Sharene Shealey

Commenter Affiliation: RRI Energy

Document Control Number: EPA-HQ-OAR-2002-0058-2759.1

Comment Excerpt Number: 4

Comment: EPA should clarify that only boilers rated at 100 MMBtu per hour or greater and 

subject to the emissions standards of Table 1 or Table 2 of subpart DDDDD are required to 

install, operate, and maintain continuous emission monitoring systems for CO and oxygen. 

Section 63.7525(a) does not specify that gas-fired units are exempted from the CEMS 

installation requirements. We interpret § 63.7525 as not applicable to gas fired units as there are 

no emission standards for these boilers. We suggest EPA revise § 63.7525(a) as follows, 

emphasis added: 

§ 63.7525 What are my monitoring, installation, operation, and maintenance requirements? 

(a) If your boiler or process heater has a heat input capacity of 100 MMBtu per hour or greater 

and is subject to a CO emission limit under table 1 or table 2 of this subpart, you must install, 

operate, and maintain a continuous emission monitoring system (CEMS) for CO and oxygen 

according to the procedures in paragraphs (a)(1) through (6) of this section by the compliance 

date specified in § 63.7495. The CO and oxygen shall be monitored at the same location at the 

outlet of the boiler or process heater. 

Response: See the preamble for revisions to the CO limitations and compliance demonstration 

methods.

Commenter Name: Robin Mills Ridgway

Commenter Affiliation: Purdue University

Document Control Number: EPA-HQ-OAR-2002-0058-2782.1

Comment Excerpt Number: 4

Comment: Alternative Monitoring for CO 
69

Purdue requests that EPA consider allowing CO in a lb/MMBTU unit instead of ppm adjusted to 

allow sources an alternative to installing an O2 CEMS. Purdue’s units are affected units in the 

CAIR summer NOx trading program so the boilers are already monitored for heat input and CO2. 

The lb/MMBTU would allow use of existing CO2 CEMS as CO2 CEMS are required for the 

greenhouse gas reporting rule and for the NOx Budget Trading Program. 

Response: See the preamble for revisions to the CO limitations and compliance demonstration 

methods.

Commenter Name: Lisa Beal

Commenter Affiliation: Interstate Natural Gas Association of America

Document Control Number: EPA-HQ-OAR-2002-0058-2756.1

Comment Excerpt Number: 4

Comment: Section 63.7525(a) should be revised to clearly indicate that CO CEMS are not 

required 

for natural gas-fired units and other units that comply with work practice standards. 

Section 63.7525(a) indicates that CO CEMS are required for units with a heat input capacity of 

100 MMBtu/hr or larger. A similar statement in the preamble at 75 FR 32015 indicates a CO 

CEMS is required for any unit 100 MBtu/hr or larger. INGAA’s understanding is that this 

requirement does not apply to natural gas-fired units that comply with work practice standards 

rather than emission standards. This should be clarified in the final rule. 

When the proposed rule is considered in its entirety, it appears that CO CEMS are not required 

for natural gas-fired units because these units comply with a work practice standard rather than 

an emission standard. However, experience indicates that rule implementation can be confusing 

if rule text is not concise. Thus, INGAA recommends revising §63.7525(a) to provide clear 

context for CO CEMS applicability. 

CO CEMS should not be required for natural gas-fired units or other units with work practice 

standards per §63.7540(a)(10). To avoid confusion regarding CO CEMS applicability, 

§63.7525(a) should be revised to clearly indicate that natural gas-fired units do not require CO 

CEMS. INGAA recommends the following revision, with “new text” shown as bold and 

underlined: 

“(a) If your boiler or process heater has a heat input capacity of 100 MMBtu per hour or greater 

and is not in either the Gas 1 or Metal Process Furnace subcategory, you must install, operate, 

and maintain a continuous emission monitoring system (CEMS) for CO and oxygen...” 

Response: See the preamble for revisions to the CO limitations and compliance demonstration 

methods.
70

Commenter Name: Robert R. Scott

Commenter Affiliation: New Hampshire Department of Environmental Services, Air Resources 

Division

Document Control Number: EPA-HQ-OAR-2002-0058-2734.1

Comment Excerpt Number: 16

Comment: The regulations list emission limitations for CO corrected to two different percent 

oxygen (3% and 7%). NHDES requests that the regulations specify the emission limitations in 

lb/MMBtu heat input as well as ppm consistently in the final rules so that emission limitations 

can be compared for the various types of fuel combusted. 

Response: See the preamble for revisions to the CO limitations and compliance demonstration 

methods.

Commenter Name: Britt S. Fleming

Commenter Affiliation: Auto Group

Document Control Number: EPA-HQ-OAR-2002-0058-2775.1

Comment Excerpt Number: 24

Comment: (13) Proposed § 63.7525(a), which requires continuous emission monitoring systems 

(CEMs) for CO and oxygen for boilers ? 100 mmBtu/hr, does not specify that it is only 

applicable to units subject to emission limits. This requirement is not appropriate for natural gasfired boilers/process heaters that do not have emission limits. The text of this provision should be 

reworded to state: “If a boiler is subject to a CO emission limit and is greater than 100 

mmBtu/hr, then you must install, operate, and ....” 

Response: See the preamble for revisions to the CO limitations and compliance demonstration 

methods.

Commenter Name: Stephen R. Gossett

Commenter Affiliation: Eastman Chemical Company

Document Control Number: EPA-HQ-OAR-2002-0058-3137.1

Comment Excerpt Number: 38

Comment: Revisions are needed to clarify that CO CEMS are not required for units burning 

only gaseous fuels. 
71

§63.7525(a) states that each boiler or process heater with a heat input capacity of 100 MM Btu/hr 

or greater must have CO and O2 CEMS. However, there are no applicable numerical CO 

emission standards for units burning gaseous fuels (Gas 1). Therefore, we suggest the following 

revision to clarify: 

§63.7525(a): If your boiler or process heater has a heat input capacity of 100 MM Btu/hr or 

greater and has an applicable CO emission limitation in Table 1, you must install... 

Response: See the preamble for revisions to the CO limitations and compliance demonstration 

methods.

Commenter Name: Stephen R. Gossett

Commenter Affiliation: Eastman Chemical Company

Document Control Number: EPA-HQ-OAR-2002-0058-3137.1

Comment Excerpt Number: 62

Comment: EPA should allow use of an alternate carbon monoxide emission standard expressed 

in lb/mmBtu to cost effectively utilize existing CO CEMS. 

EPA’s proposed carbon monoxide (CO) emission limits are expressed in units of parts per 

million (ppm) corrected to 3% Oxygen (O2). Some sources have existing continuous emissions 

monitoring systems (CEMS) that already monitor O2 as the diluent gas to demonstrate 

compliance with other emission standards, and would require upgrades or expansions to the 

CEMS to monitor CO for compliance with this rule. However, many sources covered under this 

rule already have existing CEMS that measure carbon dioxide (CO2), either as the diluent gas or 

to demonstrate compliance with other emissions standards. Many added CO2 CEMS as a result 

of the recent Greenhouse Gas Reporting Rule. Sources which use CO2 diluent gas monitoring in 

lieu of O2 diluent gas monitoring typically utilize dilution-extraction sampling and conditioning 

systems, where compressed air is used to dilute the flue gas sample prior to being analyzed in a 

pollutant monitor. Dilution-extraction systems cannot monitor flue gas O2 due to the 

introduction of fresh air at high ratios, often of 50:1 or 100:1. Because sources with dilutionextraction sampling systems would be unable to adapt or expand their existing CEMS to monitor 

O2, those sources would be required to install a completely separate and independent CEMS 

system. A requirement to install such a redundant CEMS, when an existing CEMS is already 

present and functional, is an unreasonable cost burden to be imposed on sources. We project 

additional costs in 

Eastman Boiler MACT Comments Page 35 of 45 excess of $100,000 per boiler due to the 

infeasibility of utilizing existing dilution-extraction CEMS to measure O2 on multiple boilers at 

a single plant site. 

EPA should allow sources to comply with an alternative standard for CO, where the emission 

standard is expressed in pounds per million BTU of heat input (lb/mmBtu). This would be 

consistent with most other emission standards in this rule, and with many other emissions 
72

monitoring requirements outside this rule (e.g., NSPS). This alternative standard would require 

only moderate, reasonable modifications to dilution-extraction CEMS that monitor CO2 instead 

of O2 as the diluent gas. EPA could devise a CO lb/mmBtu standard that would provide the same 

degree of protection of human health and the environment as the currently proposed CO ppm 

standard without imposing unnecessary cost burdens on sources. 

Response: See the preamble for revisions to the CO limitations and compliance demonstration 

methods.

Commenter Name: Timothy Hunt

Commenter Affiliation: American Forest and Paper Association (AF&PA)

Document Control Number: EPA-HQ-OAR-2002-0058-3213.1

Comment Excerpt Number: 75

Comment: EPA collected a limited amount of CO CEMS data during the Phase 1 ICR. Hog 

Fuel Boiler EU1 is a biomass fuel cell unit at Weyerhaeuser Raymond, WA. This unit is among 

the top performers in the biomass fuel cell category. However, as the submitted chart shows, the 

average CO emissions reported are greater than the proposed biomass fuel cell CO limit and the 

3-run stack test average. This further serves to illustrate that 3-run stack test data does not 

provide an adequate variability assessment needed to establish achievable solid fuel boiler CO 

limits. 

Response: See the preamble for revisions to the CO limitations and compliance demonstration 

methods.

Commenter Name: Timothy Hunt

Commenter Affiliation: American Forest and Paper Association (AF&PA)

Document Control Number: EPA-HQ-OAR-2002-0058-3213.1

Comment Excerpt Number: 298

Comment: CO CEMS data obtained when operating at less than 50 percent load should be 

excluded. 

As indicated in the proposed area source industrial boiler rule(75 FR 31929) and the previous 

major source industrial boiler rule, it is appropriate to exclude CO monitoring data from periods 

where a boiler or process heater is operating at less than 50% load. We provide information 

elsewhere in these comments that demonstrates CO emissions are higher at low loads, especially 

when corrected to a standard percent oxygen. Exclusion of this data will also allow some relief 

for standby units. EPA should incentivize stand-by operation because this means that regulated 

entities have a better chance of minimizing malfunction related emissions elsewhere at their site 

if they have a boiler on stand-by, which can be ramped up on an as needed basis. 
73

Response: See the preamble for revisions to the CO limitations and compliance demonstration 

methods.

Commenter Name: Chris Greissing

Commenter Affiliation: Industrial Minerals Association

Document Control Number: EPA-HQ-OAR-2002-0058-2740.2

Comment Excerpt Number: 13

Comment: Despite EPA’s conclusion to the contrary, the capital cost, operating and 

maintenance costs, and the inevitable malfunctions of CO CEMS place a burden on the source 

that is not proportionate to the total HAP being regulated. Requiring a certified CO and oxygen 

CEMS to measure a surrogate representing only 15% of the total HAP regulated by the rule is 

excessive. The Proposed Rule should eliminate the requirement for CO CEMS and instead 

provide that units with heat input capacities greater than 100 MMBtu/hr are subject to the same 

compliance monitoring as those units < 100 MMBtu/hr. capacity – initial and annual 

performance stack tests. Sources have an incentive to operate their boilers efficiently to achieve 

complete combustion and obtain the greatest amount of energy from the fuel burned. Given this 

fact, periodic stack tests should be more than adequate to ensure compliance with CO limits. 

Response: See the preamble for revisions to the CO limitations and compliance demonstration 

methods.

Commenter Name: Randall D. Quintrell

Commenter Affiliation: Georgia Paper and Forest Products Association, GPFPA

Document Control Number: EPA-HQ-OAR-2002-0058-2905

Comment Excerpt Number: 26

Comment: One issue related to continuous monitoring provisions in the proposed Rule is the 

diluent used for correcting the CO CEMS. PS2 allows the use of either 02 or CO2 for this 

purpose. Several of our units are required to have CO2 monitors for greenhouse gas reporting and 

we believe the flexibility allowed under PS2 should be specifically included in the Boiler MACT 

Rule for CO. The proposed Rule at Table 1 to Subpart DDDDD specifies a CO concentration 

limit for a number of the boiler/process heater subcategories. For each subcategory, an 02 

correction factor is also specified for the CO limit. At Table 5, the proposed Rule specifies EPA 

Methods 3A or 3B for the determination of 02 and CO2 concentrations and EPA Method 10 is 

specified for the measurement of CO concentrations. The proposed Rule at 75 FR 63.7525(a) 

requires the use of a CEMS for both CO and 02 for boilers/process heaters with heat input rating 

of 100 MMBtu/hr or greater and 63.7540(a)(10)(vi)(A) requires records and reporting of CO and 

02 concentrations. Performance Standard (PS) 4A is specified at §63.7525(a)(1) for the CO 
74

CEMS. PS 4A references PS 2, Sections 3, 8, and 12 as being applicable to PS 4A. The purpose 

of the 02 CEMS is to serve as the diluent analyzer needed to provide the data for the required 02 

correction data for the CO concentration. PS 2, however, allows the use of either a CO2 or 02 

diluent analyzer to calculate the 02 correction. CO2 is commonly used by other CEMS (NO,, 

SO2, etc.) because CO2 analyzers are generally considered to be more reliable and stable than 02 

monitors. While the cited Performance Standards and EPA Methods would permit its use, the 

text of the proposed Rule appears to require the use of an 02 diluent gas analyzer only. Although 

the use of CO2 data to calculate the 02 correction could be accomplished via a request to EPA for 

approval of alternative monitoring, simple amendment of the proposed Rule to explicitly allow 

for its use would be a far more efficient resolution. 

Another issue with the proposed CO monitoring provisions is the specification of PS 4A for the 

required CO CEMS. PS 4A is stated as having been primarily developed for CEMS intended to 

demonstrate compliance with CO emission standards less than 200 ppmv. Because the proposed 

Rule specifies higher limits (560 ppmv, 1010 ppmv) for several boiler/process heater 

subcategories, it would seem appropriate to amend the proposed Rule to allow for monitors 

complying with PS-4 which was designed for CO span values in the 1000 ppmv range. 

We urge EPA to specifically state in the final Rule that PS-4 be allowed in addition to PS4A, and 

to allow CO2 to be used in CO diluent calculations as an option to using 02. 

Response: See the preamble for revisions to the CO limitations and compliance demonstration 

methods.

Commenter Name: Robert D. Morrison

Commenter Affiliation: Abbott Laboratories

Document Control Number: EPA-HQ-OAR-2002-0058-2764.1

Comment Excerpt Number: 27

Comment: Monitoring requirements for Gas 1 boilers need to be clarified (40 CFR 63.7525(a)). 

The proposed Boiler MACT regulation requires boilers and process heaters with a heat input 

capacity of 100 MMBtu/hr or greater to install, operate, and maintain a continuous emission 

monitoring system (CEMS) for CO and oxygen. There are no limitations or exceptions identified 

for this monitoring requirement. However, other provisions in the proposed regulation do not 

include CO emission limits for existing or new Gas 1 boilers, or for process heaters greater than 

100 MMBtu/hr. If the monitoring requirement in 40 CFR 63.7525(a) is intended to exclude units 

without emission limits, such as Gas 1 boilers, then the exclusion should be clearly stated. If the 

intention is to require CEMs for CO monitoring of Gas 1 boilers in the absence of a CO emission 

limit, then the requirement seems overly burdensome with no particular benefit. USEPA should 

make it clear that the CO monitoring requirement in 40 CFR 63.7525(a) does not apply to units 

where there is no numerical CO emission limit. 
75

Response: See the preamble for revisions to the CO limitations and compliance demonstration 

methods.

Commenter Name: David A. Buff

Commenter Affiliation: Golder Associates Inc

Document Control Number: EPA-HQ-OAR-2002-0058-2801.1

Comment Excerpt Number: 51

Comment: As in the original Industrial Boiler MACT rule, it would be appropriate to exclude 

CO data for periods when the source was operating at less than 50 percent load. The MACT 

emission limits for CO are primarily based on stack test data which is obtained at or near full 

load operation. Operation at loads less than 50 percent can be highly variable in terms of 

concentration (ppmvd), while mass emissions are low since boiler load is low. Therefore, 

excluding this data would not result in higher mass emission of organic HAPs. 

Response: See the preamble for revisions to the CO limitations and compliance demonstration 

methods.

Commenter Name: Robert D. Bessette

Commenter Affiliation: Council of Industrial Boiler Owners (CIBO)

Document Control Number: EPA-HQ-OAR-2002-0058-2702.1

Comment Excerpt Number: 57

Comment: CIBO Supports the Use of CO Monitoring as the Only New Source Work Practice 

Standard Requirement . 

Periodic operation of solid fuel boilers in a highly turned down mode is common among several 

of CIBO’s member sectors, as an efficient way to manage manufacturing process energy needs. 

For example, industrial process boilers in the wood products industry supply steam according to 

the immediate demand from processes for which they are operated. These boilers operate at 

widely varying load levels, depending on, among other things, the amount of steam the process 

equipment is demanding at the time. Because CO emissions may routinely exceed the work 

practice standard during turndown periods, these periods should be exempt from the CO 

concentration standard. Importantly, EPA will recognize that during high turndown periods the 

actual HAP emission load should be lower since the total fuel load is reduced from the normal 

operation. 

High CO emissions are a common occurrence to all solid fuel boilers during high turndown 

operation due to a combination of well-known combustion fundamentals. Because of these 

countervailing effects, boilers and process heaters should be subject to the CO concentration 

limit only when the boiler is operating at greater than 50% of its design capacity. While 

averaging time can provide some latitude for those conditions, imposition of the CO limit under 
76

low loads is not appropriate. EPA has recognized boiler, or burner, turndown ratio as a factor 

affecting performance in several contexts. See, EPA, Final Technical Support Document for 

HWC MACT Standards, Vol. IV, p. 3.6 (July 1999); EPA Region 6 Center for Combustion 

Science and Engineering, Hazardous Waste Combustion Unit Permitting Manual, Component 1 

How to Review a Test Burn Plan, p. D-5.5 (Tetra Tech Jan. 1998). EPA provided this limitation 

of CO limit applicability at or above 50% rated capacity in the prior vacated Boiler MACT rule. 

The recently proposed Boiler Area Source Rule also includes this limitation of the CO emission 

concentration limit to operation at or above 50% of rated capacity. Therefore, a similar provision 

should also be included in this rule for new and existing units. 

Response: See the preamble for revisions to the CO limitations and compliance demonstration 

methods.

Commenter Name: Robert D. Bessette

Commenter Affiliation: Council of Industrial Boiler Owners (CIBO)

Document Control Number: EPA-HQ-OAR-2002-0058-2702.1

Comment Excerpt Number: 58

Comment: CIBO also believes that continuous CO monitoring is not required in order to 

demonstrate low organic HAP emissions, especially for gas 2 (other gaseous-fired) units. The 

cost of CO CEMs is a very significant cost for small affected sources, considering that there are 

really no emissions reductions associated with installation of the CEM. A periodic test is 

adequate for smaller units, but continuous CO monitors could be justified for large units. 

Response: See the preamble for revisions to the CO limitations and compliance demonstration 

methods.

Commenter Name: Robert D. Bessette

Commenter Affiliation: Council of Industrial Boiler Owners (CIBO)

Document Control Number: EPA-HQ-OAR-2002-0058-2702.1

Comment Excerpt Number: 127

Comment: EPA proposed Carbon Monoxide limits listed in parts per million (ppm) corrected to 

3% Oxygen (O2). Some sources have existing CEMS that already monitor O2 as the diluent gas 

to demonstrate compliance with other emission standards, and would require upgrades or 

expansions to the CEMS to monitor CO for compliance with this rule. However, many sources 

covered under this rule already have existing Continuous Emissions Monitoring Systems 

(CEMS) that measure Carbon Dioxide (CO2), either as the diluent gas or to demonstrate 

compliance with other emissions standards. Sources which use CO2 diluent gas monitoring in 

lieu of O2 diluent gas monitoring typically utilize dilution-extraction sampling and conditioning 
77

systems, where compressed air is used to dilute the flue gas sample prior to being analyzed in a 

pollutant monitor. Dilution-extraction systems cannot monitor flue gas O2 due to the 

introduction of fresh air at high ratios, often of 50:1 or 100:1. Because sources with dilutionextraction sampling systems would be unable to adapt or expand their existing CEMS to monitor 

O2, those sources would be required to install a completely separate and independent CEMS 

system. A requirement to install such a redundant CEMS, when an existing CEMS is already 

present and functional, is an unreasonable cost burden to be imposed on sources. 

EPA should allow sources to comply with an alternative standard for CO, where the emission 

standard is expressed in pounds per million BTU of heat input (lb/MMBtu). This would be 

consistent with most other emission standards in this rule, and with many other emissions 

monitoring requirements outside this rule (e.g., NSPS). This alternative standard would require 

only moderate, reasonable modifications to dilution-extraction CEMS that monitor CO2 instead 

of O2 as the diluent gas. EPA could devise a CO lb/MMBtu standard that would provide the 

same degree of protection of human health and the environment as the currently proposed CO 

ppm standard without imposing unnecessary cost burdens on sources. 

Response: See the preamble for revisions to the CO limitations and compliance demonstration 

methods.

Commenter Name: Robert D. Bessette

Commenter Affiliation: Council of Industrial Boiler Owners (CIBO)

Document Control Number: EPA-HQ-OAR-2002-0058-2702.1

Comment Excerpt Number: 128

Comment: One member company projects additional costs in excess of $100,000 per boiler due 

to the infeasibility of utilizing existing dilution-extraction CEMS to measure O2 on multiple 

boilers at a single plant site. 

EPA needs to clarify in the rule the specific units for which CO CEMS are required. It needs to 

be clear that they are only required for specific sources that have CO emission limits stipulated in 

Table 1 or Table 2. 

Response: See the preamble for revisions to the CO limitations and compliance demonstration 

methods.

Commenter Name: Robert D. Bessette

Commenter Affiliation: Council of Industrial Boiler Owners (CIBO)

Document Control Number: EPA-HQ-OAR-2002-0058-2702.1

Comment Excerpt Number: 131
78

Comment: E. The CO CEMS requirement for units Less Than 100 MMBtu is unreasonable. 

The requirement for CO CEMS for units > 100 MMBtu per hour is too onerous. Many units at 

this size in the industrial and institutional sector do not operate that frequently, therefore the cost 

of installing CO CEMS is not justified for units with such limited operation. CIBO recommends 

that EPA remove this requirement and present alternatives to either install CEMS or use stack 

testing for any units with limits. EPA could also increase the threshold requirement for CO 

CEMS to 250 MMBtu per hour or provide a limited use exemption such as 10 percent use. 

Response: See the preamble for revisions to the CO limitations and compliance demonstration 

methods.

Commenter Name: Matthew Todd and David Friedman

Commenter Affiliation: American Petroleum Institute (API) and National Petrochemical and 

Refiners Association (NPRA)

Document Control Number: EPA-HQ-OAR-2002-0058-2960.1

Comment Excerpt Number: 147

Comment: Proposed 63.7525(a) states “If your boiler or process heater has a heat input capacity 

of 100 MMBtu per hour or greater, you must install, operate, and maintain a continuous emission 

monitoring system (CEMS) for CO and oxygen according to the procedures in paragraphs (a)(1) 

through (6) of this section by the compliance date specified in 63.7495. The CO and oxygen shall 

be monitored at the same location at the outlet of the boiler or process heater.” 

This paragraph appears to require CO and O2 CEMS for all boilers and process heaters with a 

heat input capacity of 100 MMBtu/hr or greater, regardless of whether the unit is subject to a CO 

emission limit. We do not believe it is reasonable to require these CEMS for units that fire Gas1 

and thus are not subject to a CO emission limitation. Thus, we believe this requirement must be 

revised as follows. 

If your boiler or process heater has a heat input capacity of 100 MMBtu per hour or greater and 

the boiler or process heater is required to meet a CO emission limit by Tables 1 or 2, you must 

install, operate, and maintain a continuous emission monitoring system (CEMS) for CO and 

oxygen according to the procedures in paragraphs (a)(1) through (6) of this section by the 

compliance date specified in 63.7495. The CO and oxygen shall be monitored at the same 

location at the outlet of the boiler or process heater. 

Proposed 63.7510(c), which deals with initial compliance testing, also indicates CO CEMS are 

required regardless of whether a CO emission limit applies. It should also be clarified on this 

point. 

Recommendation: Revise 63.7525(a) to only require a CO CEMS where there is an applicable 

CO emission limit and revise 63.7510(c) to match. 
79

Response: See the preamble for revisions to the CO limitations and compliance demonstration 

methods.

Commenter Name: Matthew Todd and David Friedman

Commenter Affiliation: American Petroleum Institute (API) and National Petrochemical and 

Refiners Association (NPRA)

Document Control Number: EPA-HQ-OAR-2002-0058-2960.1

Comment Excerpt Number: 152

Comment: Where CO CEMS are not required (e.g., boilers and process heaters between 10 and 

100 MMBTU/hr design heat input), sources should be given the option of using CEMS because 

such analyzers may be required for permit or for operating reasons and it is unreasonable to 

require sources to do performance tests in addition, while sources that install CO CEMS for the 

purpose of demonstrating compliance do not. 

Recommendation: Allow CO CEMS as an option for units where CO CEMS are not required. 

Response: See the preamble for revisions to the CO limitations and compliance demonstration 

methods.

Commenter Name: David Foerter

Commenter Affiliation: Institute of Clean Air Companies

Document Control Number: EPA-HQ-OAR-2002-0058-2937.1

Comment Excerpt Number: 39

Comment: There is a fundamental thermodynamic application for combustion that is consistent 

with all methods of burning fuel. With the operating unit minimizing the excess O2 and 

maintaining the CO between 50 to 300ppm the efficiency of the burner will be optimized. By 

optimizing the efficiency, the owner/operator reduces operating costs through fuel savings. In 

addition, by setting a low limit of CO for maximizing efficiency and an upper limit NOx value 

from permit restrictions, the relationship of NOx to CO dictates the operating range for excess 

O2. 

The simple conclusion of this relationship is shown clearly within the submittal Figure 5. By 

establishing the unit’s operating NOx curve and then applying the combustion efficiency rules a 

specific operating range for CO, O2, and NOx can be established and maintained. The benefits to 

the user are minimized operating costs and maximized operating efficiency. 
80

Response: See the preamble for revisions to the CO limitations and compliance demonstration 

methods.

Commenter Name: Tom Siegrist

Commenter Affiliation: Koch Nitrogen Company, LLC

Document Control Number: EPA-HQ-OAR-2002-0058-3127

Comment Excerpt Number: 2

Comment: EPA should further clarify its expectations regarding carbon monoxide testing during 

a boiler or process heater tune-up required by 40 CFR 63.7540(a)(10)(v). Specifically, CO 

measurement using commercially available hand-held instruments should be identified as an 

acceptable method for satisfying this requirement. 

The proposed boiler tune-up procedure for natural gas boilers and process heaters includes CO 

testing to measure the effectiveness of the tune-up. The proposed rule does not identify testing 

procedures that would be acceptable to EPA. Since test results are intended to provide an 

indication of process improvement resulting from a tune-up, rather 

than to demonstrate compliance with a specific numeric emission limit, a complete Method 10 

test should not be necessary. KNC requests that EPA provide clarifying language in the final rule 

indicating that acceptable methods for CO measurement include the use of hand-held combustion 

gas analyzers or other measurement instrumentation. 

Response: See the preamble for revisions to the CO limitations and compliance demonstration 

methods.

Commenter Name: John C. Hendricks

Commenter Affiliation: American Electric Power

Document Control Number: EPA-HQ-OAR-2002-0058-2703.1

Comment Excerpt Number: 7

Comment: EPA Should Not Require 02 CEMS 

Limiting the diluent used in the acceptable CEMS systems to oxygen is over-restrictive. Carbon 

dioxide should be included in the rule as an acceptable diluent. CO2 being an acceptable diluent 

would allow AEP to use dilution extraction monitors rather than being limited to a monitoring 

technology because only oxygen is available as a diluent. 

Response:

See the preamble for revisions to the CO limitations and compliance demonstration methods.
81

Commenter Name: Pamela F. Faggert

Commenter Affiliation: Dominion

Document Control Number: EPA-HQ-OAR-2002-0058-2908.1

Comment Excerpt Number: 7

Comment: EPA should also clarify that CO continuous emissions monitors (CEMS) are only 

required for affected units that are subject to a CO emission standard and not for natural gas-fired 

units where CO measurements are conducted during tune-ups. 

Response: See the preamble for revisions to the CO limitations and compliance demonstration 

methods.

Commenter Name: Marvis A. Lewallen

Commenter Affiliation: Clearwater Paper

Document Control Number: EPA-HQ-OAR-2002-0058-2862

Comment Excerpt Number: 8

Comment: We also request that EPA increase the threshold for having to operate continuous 

emission monitors for CO. as proposed, a boiler with a heat input of 100 MM Btu/hr or more, 

whether at an area or major source, would be required to demonstrate compliance with the CO 

limit using a CEM. This is an undue burden on biomass fired boilers. Boilers in our industry are 

frequently in the 100 MM Btu/hr to 249 MM Btu/hr range. These units are typically not 

otherwise required to operate CEMs. Installing and operating CEMs would be a significant 

additional expense without material value added. As a sector, our organic HAP emission rates 

are not high and so do not justify this monitoring requirement as opposed to periodic testing. 

Therefore, we request that EPA increase the threshold for requiring CO CEMs to those units with 

a heat input of 250 MM Btu/hr or greater. 

Response: See the preamble for revisions to the CO limitations and compliance demonstration 

methods.

Commenter Name: Debra J. Jezouit

Commenter Affiliation: Class of '85 Regulatory Response Group

Document Control Number: EPA-HQ-OAR-2002-0058-2802.1

Comment Excerpt Number: 15

Comment: Proposed 63.7525 does not specify that gas-fired units are exempt from the CEMS 

installation requirements. However, EPA is not proposing numerical emissions standards for 

these Boilers. The Group suggests that EPA clarify the applicability of the CEMS requirements. 
82

Response: See the preamble for revisions to the CO limitations and compliance demonstration 

methods.

Commenter Name: David Bonistall

Commenter Affiliation: NewPage Corp

Document Control Number: EPA-HQ-OAR-2002-0058-2920.1

Comment Excerpt Number: 23

Comment: EPA needs to further clarify the requirements to install and operate CO CEMs on 

Gas 1 units. Page 32015 of the preamble states: 

The preamble language implies that continuously monitoring of CO is only required for units 

that have an applicable CO standard to comply with as identified in Tables 1 or 2. 

We support the position taken in p. 32,015 of the preamble language that the installation and 

operation of a CO CEMs is not needed unless the subcategory has a specific CO limit. 

Response: See the preamble for revisions to the CO limitations and compliance demonstration 

methods.

Commenter Name: Pamela F. Faggert

Commenter Affiliation: Dominion

Document Control Number: EPA-HQ-OAR-2002-0058-2908.1

Comment Excerpt Number: 25

Comment: PM CEMS are not capable of providing representative measurements over the entire 

range of boiler operation, which would be required for demonstrating continuous compliance 

with emission standards that do not account for transient flue gas conditions during periods of 

startup, shutdown and 

malfunction. Because the variability effects cannot be adequately addressed, EPA should remove 

the requirement for the installation and use of PM CEMS as the continuous compliance 

determination method for coal and biomass sources with heat input ratings greater than 250 

mmBtu/hr. Alternatively, sources could demonstrate a reasonable assurance of compliance based 

on opacity, parametric monitoring or stack testing as EPA has already proposed for those units 

with heat input ratings < 250 mmBtu/hr. EPA could allow the installation and operation of a PM 

CEMS as an option for all sources, which is consistent with the approach taken in the recent 

revisions to NSPS Subpart Da. However, in this case, EPA should increase the compliance 

averaging time (e.g. 30-day rolling average) in order to mitigate some of the effects of 

startup/shutdown. To the extent a general requirement for PM CEMS is retained for these larger 
83

units in the final rule, EPA should allow the decision to require CEMS to the discretion of the 

state regulators for limited-use (low capacity factor) units. 

Response: EPA has clarified in the final rule that the averaging period for demonstarting 

compliance with a PM CEMS is a 30-day rolling average. This extended averaging period, as 

the commenter suggests,can account for emissions variability at a source.

Commenter Name: Russ A. Wozniak

Commenter Affiliation: Dow Chemical Company

Document Control Number: EPA-HQ-OAR-2002-0058-2632.1

Comment Excerpt Number: 36

Comment: Comments on Continuous Emission Monitoring Systems for CO. EPA’s proposed 

rule references EPA Performance Specification 4A for a CO CEMS. Section 1.2.1. of PS 4A 

states that this specification was developed primarily for CEMS that comply with low emission 

standards (less than 200 ppmv). Dow commented earlier that EPA should not establish a CO 

emission level of 1 ppmv for "Other Gases." At a minimum, EPA may need to make additional 

adjustments if CO emission standards are indeed set at a level of less than 10 ppmv for gas or oil 

fueled sources due to QA/QC issues as discussed below. 

A CO CEMS will have to be ranged from 0 to 10 ppmv in order to adequately measure CO 

concentrations in the 0 to 1 or 2 ppmv range. In addition, it should be noted that owner/operators 

will need a second CO CEMS ranged from 10 to 100 ppmv to accurately measure CO 

concentrations during times of start-up and other operations. The cost to install two CEMS for 

CO hasn’t been considered by EPA. For the CEMS that is measuring CO concentrations in the 0 

to 10 ppmv range, the accuracy of the device meeting the requirements of Performance 

Specification 4A is ~ 5% of the range or in this case + 0.5 ppmv (see Section 13.2 of PS4A). 

This level is troubling in that the uncertainty of the measurement is 50% of the proposed 

emission standard in this case, thus further contributing to the challenges of meeting a 1 ppmv 

standard on a consistent basis. 

In addition, such a small allowable emission level will make conducting the Relative Accuracy 

Audits and Tests very difficult to complete. Section 13.2 of PS4A requires that the RA of the 

CEMS must be no greater than 5 percent when the applicable emission standard is used to 

calculate RA. Thus, one would be comparing values that are less than 1 ppmv and looking for 

agreement between those values (~ 0.05 ppmv agreement) when the accuracy of EPA Method 10 

is itself only about 0.2 ppmv or in this case 20% of the allowable CO emission concentration. 

The final rule would need to allow for an absolute difference of less than 1 ppmv for example vs. 

a fraction of the allowable ppmv value to be used for QA/QC purposes. 
84

Response: See the preamble for revisions to the CO limitations and compliance demonstration 

methods.

Commenter Name: Russ A. Wozniak

Commenter Affiliation: Dow Chemical Company

Document Control Number: EPA-HQ-OAR-2002-0058-2632.1

Comment Excerpt Number: 38

Comment: EPA Should Remove the Requirements to Install CEMS for CO and Oxygen as 

required in 63.7525 for Medium Sized Boilers and Heaters and Equipment using Natural Gas 

Fuels. EPA’s proposal to require all units with > 100 MMBtu per hour heat input capacity to 

install, operate, and maintain continuous emission monitoring system (CEMS) for Carbon 

Monoxide (CO) and Oxygen (O2) is not warranted for smaller units and especially for units that 

use Natural Gas fuels. Since there are no emission standards for Natural Gas and Refinery gas 

burning units, the CEMS requirement should be deleted from the rule. 

Response: See the preamble for revisions to the CO limitations and compliance demonstration 

methods.

Commenter Name: David Foerter

Commenter Affiliation: Institute of Clean Air Companies

Document Control Number: EPA-HQ-OAR-2002-0058-2937.1

Comment Excerpt Number: 38

Comment: Carbon Monoxide (CO) Monitoring for Fossil Fuel Combustion Sources 

In the event EPA retains the use of CO as a surrogate to measure organic HAPs instead of 

directly measuring THC, ICAC suggests it is technically feasible and economical for smaller 

boilers and process heaters to monitor their CO emissions at a minimum quarterly if not on a 

continuous basis. EPA’s proposed Boiler rule requires boilers and process heaters in any 

subcategory with heat inputs greater than 100MMBtu/hr to continuously monitor CO emissions 

and requires smaller boilers and process heaters, 10-100MMBtu/hr to conduct an annual stack 

test. 

ICAC believes that a continuous CO monitor should be considered part of the control system for 

all sources larger than 50 to 100MMBtu/hr. Additionally, use of such monitors at sources whose 

CO emissions are variable and potentially large, such as sources that combust wet wood. Use of 

a continuous CO monitor over a period of time will assist the operator and permitting authority 

in understanding those combustion practices that lead to excessive CO emissions and in 

identifying those specific measures that will reduce CO emissions in the most cost-effective 

manner. CO continuous emission monitoring systems (CEMs) monitors typically cost in the 

range of $10,000 to $15,000. 
85

“Tune up” the unit for CO purposes, including cleaning the system, servicing or replacing filters 

and maintaining induced draft fans, to insure that the air flow to the boilers is optimized. 

Consider adding process parametric monitoring devices such as oxygen, flow, moisture, and 

mass air sensors. CO monitors range in sophistication from hand-held portables up to full system 

CEMs. Other options include parametric monitoring and Predictive Emissions Monitoring 

Systems (PEMs). These devices typically cost range from $1,000 for a portable CO monitor 

(non-continuous), up to $35,000 for a PEMS, and $35,000 to over $65,000 for a CEMS. 

The use of a CO CEMS have historically been used to maximize the efficiency of the burner 

operation. Monitoring O2 and CO as a process application for burner/boiler control has been 

widely accepted in the utility and industrial source market and has played a strong role in 

optimization of burner/boiler efficiency. See submittal for Figure 4 which presents a graphic 

representation of the relationship of O2 and CO with efficiency. 

Response: See the preamble for revisions to the CO limitations and compliance demonstration 

methods.

Commenter Name: Russ A. Wozniak

Commenter Affiliation: Dow Chemical Company

Document Control Number: EPA-HQ-OAR-2002-0058-2632.1

Comment Excerpt Number: 39

Comment: Dow comments that EPA should require CO and O2 CEMS only for units with > 

250 MMBtu/Hr capacity since these are the units typically located at large industrial sites and 

have experienced personnel and support staff to manage complicated CEMS systems. 

Response: See the preamble for revisions to the CO limitations and compliance demonstration 

methods.

Commenter Name: David Foerter

Commenter Affiliation: Institute of Clean Air Companies

Document Control Number: EPA-HQ-OAR-2002-0058-2937.1

Comment Excerpt Number: 40

Comment: Below we offer criteria for setting CO monitoring limits: 

1) Base the monitoring methods on the cost to operate, not the cost of equipment. Set a standard 

cost protocol. 

2) Establish regulatory criteria for reporting, i.e., ICI Boiler MACT, Parametric, 40CFR60, etc. 

3) Options with practical payback of (1) one year. 

Using the guidelines set above, following is a recommended listing: 

1) Yearly operating costs of < $250,000 (or >10MMBtu/hr): 
86

i. practical fuel cost savings of 5-10% criteria 

ii. hardware cost to be at $25,000 maximum (Portables) 

iii. use Compliance Assurance Monitoring (CAM) as guidance for monitoring 

iv. practical payback target is one (1) year 

2) Yearly operating costs of < $500,000 (or >20MMBtu/hr): 

i.practical fuel cost savings of 5-10% criteria hardware cost with installation to be at $50,000 

maximum 

ii. (process CO/O2 continuous monitoring with recorder/data-logger) 

iii. PEMS; continuous real-time software monitoring system 

iv. use continuous parametric process monitoring as guidance 

v. practical payback target is one (1) year 

3) Yearly operating costs of < $750,000 (or >30MMBtu/hr): 

i. practical fuel cost savings of 5-10% criteria 

ii. hardware cost with installation to be at $75,000 maximum 

iii. (continuous NOx/ CO/O2 monitoring for 40CFR60 Appendix B, PS-3 &PS- 4 with 

recorder/data-logger) 

iv. PEMS; continuous real-time software monitoring system 

v. use USEPA 40CFR60 CEMs as guidance 

vi. practical payback target is one (1) year 

4) Yearly operating costs of > $750,000 (or >40MMBtu/hr): 

i. practical fuel cost savings of 5-10% criteria 

ii. hardware CEMS as a minimum to be continuous NOx/CO/O2/Opacity with 40CFR60 Data 

Acquisition System (DAS) requirements 

iii. PEMS; continuous real-time software monitoring system with 40CFR60 DAS monitoring and 

reporting) 

iv. use 40CFR60 CEMs as guidance 

v. practical payback target is one (1) year 

Response: See the preamble for revisions to the CO limitations and compliance demonstration 

methods.

Commenter Name: Russ A. Wozniak

Commenter Affiliation: Dow Chemical Company

Document Control Number: EPA-HQ-OAR-2002-0058-2632.1

Comment Excerpt Number: 62

Comment: Regarding CO CEMS data, Dow comments that EPA needs to exclude CO emissions 

requirements during periods when affected units are at less than 50% load as EPA had finalized 

in the original Boiler MACT standards as well as in the GACT rule. This exclusion will allow 

some relief for standby units. EPA should incentivize stand-by operation because this means that 

regulated entities have a better chance of minimizing malfunction related emissions elsewhere at 

their site if they have a boiler on stand-by, which can be ramped up on an as needed basis. 
87

Response: See the preamble for revisions to the CO limitations and compliance demonstration 

methods.

Commenter Name: Chris M. Hobson

Commenter Affiliation: Southern Company

Document Control Number: EPA-HQ-OAR-2002-0058-2741.1

Comment Excerpt Number: 69

Comment: Section 63.7525(a) states: “If your boiler or process heater has a heat input capacity 

of 100 MMBtu per hour or greater, you must install, operate and maintain a continuous emission 

monitoring system (CEMS) for CO and oxygen ...” This requirement would exclude the use of 

dilution-extractive CEMS which monitor carbon dioxide (CO2) as the diluent for calculating 

emission rates in mmBtu. Many sources may already have dilution-extractive CEMS operating 

on affected boilers. This section should be revised to allow the use of O2 or CO2 monitors. 

Response: See the preamble for revisions to the CO limitations and compliance demonstration 

methods.

Commenter Name: Chris M. Hobson

Commenter Affiliation: Southern Company

Document Control Number: EPA-HQ-OAR-2002-0058-2741.1

Comment Excerpt Number: 71

Comment: It is recommended that Section 63.7525(a)(i) and (ii) be revised to clarify that (1) the 

CO CEMS initial performance evaluation (i.e., certification) shall be conducted in accordance 

with Performance Specifications 3 and 4A of 40 CFR part 60, appendix B and (2) the CO CEMS 

will be operated and maintained in accordance with the requirements specified in Procedure 1 of 

Appendix F, 40 CFR Part 60. 

Response: See the preamble for revisions to the CO limitations and compliance demonstration 

methods.

Commenter Name: Chris M. Hobson

Commenter Affiliation: Southern Company

Document Control Number: EPA-HQ-OAR-2002-0058-2741.1

Comment Excerpt Number: 76

Comment: In Table 2, all the CO emission limits are listed in units of “ppm on a dry basis 

corrected to 3 percent O2.” There should be an equivalent emission limit (e.g., lb/mmBtu) listed 

for units which install and operate dilution-extractive CEMS which measure emissions on a wetbasis. 
88

Response: See the preamble for revisions to the CO limitations and compliance demonstration 

methods.

Commenter Name: William O'Sullivan

Commenter Affiliation: New Jersey Department of Environmental Protection

Document Control Number: EPA-HQ-OAR-2002-0058-2969.1

Comment Excerpt Number: 1

Comment: We support use of carbon monoxide (CO) CEMS for boilers and process heaters. 

Response: See the preamble for revisions to the CO limitations and compliance demonstration 

methods.

Commenter Name: Ben C. Trammell, Jr

Commenter Affiliation: Dynegy, Inc

Document Control Number: EPA-HQ-OAR-2002-0058-2859.1

Comment Excerpt Number: 2

Comment: The proposed requirement to install, certify, operate, and maintain carbon monoxide 

(CO) CEM systems on such small, very low-utilization boilers will impose unduly burdensome 

capital and O&M costs on their owners or operators. Many (if not most) small boilers designed 

and installed for intermittent use are not equipped with exhaust stacks designed to accommodate 

stack testing or installation of certified CEM systems. In order to perform stack testing and 

install CEM systems, owners or operators of many such boilers will be required to retrofit new or 

extensively modify existing exhaust stacks, making installation and operation of CEMS an 

extremely costly proposition in comparison to the few hours of emission data such CEMS might 

provide on an annual basis. 

Response: See the preamble for revisions to the CO limitations and compliance demonstration 

methods.

Commenter Name: Frederick W. Lash

Commenter Affiliation: Air Products and Chemicals, Inc

Document Control Number: EPA-HQ-OAR-2002-0058-3178

Comment Excerpt Number: 2

Comment: On pages 32012 and 32014 of the preamble, EPA indicates that boilers and process 

heaters of any size in the Gas 1 (NG/RF fuel) facility category would not have any proposed 
89

emission limits per this rule. This is evident given the absence of numeric limitations for Gas 1 

facilities within Tables 1 and 2 of the rule. Since there are no proposed emission limits, the 

logical conclusion is that EPA is not requiring Gas 1 facilities to install CO and oxygen (02) 

continuous emissions monitoring systems (CEMs). However, the language as proposed in 

§63.7525(a) does not make this distinction clearly and may be interpreted that all boilers and 

process heaters with a heat capacity of 100 MMBtu per hour or greater be equipped with CO and 

02 CEMs. 

Recommendation: Air Products suggests that the apparent CEMs exemption for Gas 1 facilities 

be clearly stated within the rule itself. 

Response: See the preamble for revisions to the CO limitations and compliance demonstration 

methods.

Commenter Name: Bethany J. Johnson

Commenter Affiliation: The Boeing Company

Document Control Number: EPA-HQ-OAR-2002-0058-2894.1

Comment Excerpt Number: 3

Comment: Carbon Monoxide (CO) CEMs should not be required for units not subject to a CO 

emission limitation standard. The language of proposed 40 CFR 63.7525(a) specifying 

monitoring, installation, operation and maintenance requirements for boilers and process heaters 

at major source facilities appears to require all boilers and process heaters with heat input 

capacity of 100 MMBtu/hr or greater to install CEMS for carbon monoxide and oxygen even if 

those boilers fall under the subcategory of "unitisl designed to burn natural gas 1 (NG/RG)," 

Units in this subcategory are not subject to a CO emission limit or any other emission limit in 

Table 1 or 2 of the proposed rule or operational limit in Table 4 of the proposed rule. The 

preamble to the proposed rule states that the purpose of the CO CEMS is to demonstrate 

compliance with the CO emission limit (see 75 Fed. Reg. at 32014, columns 2-3.) 

Where no such CO emission limitation exists, a CO CEMS should not be required. Requiring 

CO CEMS for these units would impose substantial costs without yielding substantial 

environmental benefits. We ask that the EPA modify the language in proposed section 

63.7525(a) to clearly exclude boilers and process heaters that are not subject to a CO emission 

limit in Table 1 or 2 of the rule from the requirement to install a CO and 02 CEMS. We suggest 

the following modification to proposed section 63.7525: 

"(a) If your boiler or process heater has a heat input capacity of 100 MMBtu per hour or greater, 

and is subject to a CO emission limit in Tables 1 or 2 to Subpart DDDDD of Part 63, you must 

install, operate, and maintain a continuous emission monitoring system (CEMS) for CO and 

oxygen according to the procedures in paragraphs (a)(1) through (6) of this section by the 

compliance date specified in § 63.7495." 

One of our CEM suppliers estimates the cost of installing C0/02 Continuous Emissions 

Monitoring Systems and Data Acquisition Systems for our existing natural gas boilers to be 

$100,000 to $130,000 per boiler. Even with shared data handling to minimize equipment 
90

duplication, the cost of CO monitoring cannot be justified by general interest alone. We request 

the above clarification to assure that the CO monitoring requirement appropriate for boilers with 

a numerical CO emission limit is not also imposed on boilers without any CO emission limit. 

Response: See the preamble for revisions to the CO limitations and compliance demonstration 

methods.

Commenter Name: William C. Herz

Commenter Affiliation: The Fertilizer Institute

Document Control Number: EPA-HQ-OAR-2002-0058-2874.1

Comment Excerpt Number: 3

Comment: TFI requests confirmation that natural gas-fired boilers and process heater units with 

heat input capacities greater than 100 MMBtu/h are not required to install, operate and maintain 

continuous CO monitors. 

Response: See the preamble for revisions to the CO limitations and compliance demonstration 

methods.

Commenter Name: Kathryn M. Cunningham

Commenter Affiliation: Consumers Energy Company

Document Control Number: EPA-HQ-OAR-2002-0058-2904.1

Comment Excerpt Number: 4

Comment: Consumers questions the intent of the requirement for CO CEMs for all units over 

100 mmBTU. Is this meant to include gas fired units that do not have an emission limit? (p. 

32015 — G(8)). This seems and unnecessary monitoring cost for units that do not have a CO 

limit; Consumers estimates over $150,000 initial capital investment for only two units. The tune 

up requirements for the gas fired boilers establishes the mechanism for ensuring proper 

combustion and minimizing CO emissions. Consumers seeks further definition and clarity in this 

area, as well as a reasonable CO limit. 

Response: See the preamble for revisions to the CO limitations and compliance demonstration 

methods.

Commenter Name: Michele E. Pugh

Commenter Affiliation: Flint Hills Resources, LP

Document Control Number: EPA-HQ-OAR-2002-0058-2910.1

Comment Excerpt Number: 4
91

Comment: The manner in which the rule is currently written makes it appear that CO CEMS are 

required on any boiler or heater greater than 100 MMBtu/hr. FHR disagrees with requirements 

that CO CEM be installed on any boiler or heater greater than 100 MMBTU/hr, since boilers and 

heaters classified as Gas 1 units are not subject to CO limits. Therefore, Gas 1 units should not 

be required to install CO CEMS, and the rule should clearly exempt such boilers and heaters that 

are not subject to specific CO limits. 

FHR recommends rewording 40 CFR 63.7525(a) to read “If your boiler or process heater has a 

heat input capacity of 100 MMBtu per hour or greater and is required to meet a CO limit in 

Table 1 or 2, you must install, operate, and maintain a continuous emissions monitoring system 

(CEMS) for CO and oxygen...” 

Response: See the preamble for revisions to the CO limitations and compliance demonstration 

methods.

Commenter Name: Jeffrey O'Hearn

Commenter Affiliation: Panolam Industries International Inc

Document Control Number: EPA-HQ-OAR-2002-0058-2749.1

Comment Excerpt Number: 4

Comment: 63.7525(a): The requirement to install a CEMS for CO for existing units with a heat 

input capacity of greater than 100 MMBTU per hour will add excessive costs both for 

installation and upkeep to a facility. This requirement should either be restricted to the larger 

units greater than 250 MMBTU per hour or to new units. 

Response: See the preamble for revisions to the CO limitations and compliance demonstration 

methods.

Commenter Name: Gregory A. Wilkins

Commenter Affiliation: Marathon Petroleum Company

Document Control Number: EPA-HQ-OAR-2002-0058-3119.1

Comment Excerpt Number: 5

Comment: It is recommended that deviations resulting from EPA’s proposed 30-day rolling 

averages be determined from the daily number of events causing a deviation instead of each 

value above a standard on the 30-day rolling average. While these rolling averages make it more 

likely that a given standard be feasible, just one event (with a large peak concentration) can 

cause a series of rolling daily deviations. This is a misleading metric. It is more appropriate to 

report one deviation for the event that resulted in possibly several days of rolling average 

emissions to be over the standard. 
92

Response: See the preamble for revisions to the CO limitations and compliance demonstration 

methods.

Commenter Name: Robert R. Perry

Commenter Affiliation: FirstEnergy Generation Corp

Document Control Number: EPA-HQ-OAR-2002-0058-2772.1

Comment Excerpt Number: 6

Comment: EPA should limit continuous monitoring requirement for CO to boilers greater than 

250 mmBtu/hr having capacity factors greater than 10 percent.. FGCO ICI Boilers operate on a 

very infrequent basis. In addition to the unwarranted additional expense of continuous CO 

monitors, the lack of run time could seriously hamper compliance with the extremely low CO 

limits. Longer averaging times would be of little value in achieving compliance due to low 

capacity factors. Hence, EPA should limit continuous monitoring requirement for CO to boilers 

greater than 250 mmBtu/hr having capacity factors greater than 10 percent. 

Response: See the preamble for revisions to the CO limitations and compliance demonstration 

methods.

Commenter Name: Gary Melow

Commenter Affiliation: Michigan Biomass

Document Control Number: EPA-HQ-OAR-2002-0058-2776.1

Comment Excerpt Number: 7

Comment: For CO there should be an allowance for emission limits corrected to CO2 as an 

alternative to O2. Some facility’s CEMs are now using CO2 as the diluent instead of O2. The 

trend is that more and more sources are converting to CO2 diluent when upgrading their CEMs 

due to other regulations, such as the Greenhouse Gas Reporting Rule. 

Response: See the preamble for revisions to the CO limitations and compliance demonstration 

methods.

Commenter Name: Stephen V. Capone

Commenter Affiliation: SABIC Innovative Plastics US LLC

Document Control Number: EPA-HQ-OAR-2002-0058-2861.1

Comment Excerpt Number: 7

Comment: C. The requirement in 63.7522(j)(2) should be clarified. 

Proposed 63.7522(j)(2) states: 
93

(2) Conduct performance tests according to procedures specified in 63.7520 in the common 

stack. if affected units from nonaffected units vent to the common stack, the units from 

nonaffected units must be shut down or vented to a different stack during the performance test); 

and 

It is unclear what "If affected units from nonaffected units vent to the common stack, the units 

from nonaffected units must be shut down or vented to a different stack..." means. EPA should 

clarify this requirement in a manner that is consistent with conducting tests to demonstrate 

compliance with an emission average. If EPA means "If emissions from units that are not part of 

the same emission average vent to the common stack, the emissions from such units must cease 

or be vented to a different stack...", then EPA should revise the requirement as follows: 

(3) Conduct performance tests according to procedures specified in § 63.7520 in the common 

stack. If emissions from units that are not part of the same emission average vent to the common 

stack, the emissions from nonaffected such units must cease or be vented to a different stack 

during the performance test; and.... 

Response: EPA clarified this language in the final rule.

Commenter Name: Paul J. Allen

Commenter Affiliation: Constellation Energy

Document Control Number: EPA-HQ-OAR-2002-0058-3164

Comment Excerpt Number: 8

Comment: Constellation generally supports CO monitoring. Requiring a CO Continuous 

Emission Monitor Systems (CEMS) is typical for most newer power plants. As such, the 

proposed requirement for a CO CEMS on newer and larger units is acceptable to Constellation 

Energy, even though our Chinese Station Power Plant, constructed in 1983, does not currently 

have a CO CEMS. However, we suggest that a capacity factor threshold be included in the 

proposal so that infrequently operated units are not included in the mandate to require a CO 

CEM. The proposal should exempt natural gas or distillate fired heating or auxiliary boilers with 

an annual capacity factor of 10% or less. In place of the CEM, the application of work practice 

standards, required in the proposal for smaller units, should also be required for these low 

capacity factor heating boilers. 

Response: See the preamble for revisions to the CO limitations and compliance demonstration 

methods.

Commenter Name: Catherine W. McCuthen

Commenter Affiliation: Blue Heron Paper Company

Document Control Number: EPA-HQ-OAR-2002-0058-2892.1

Comment Excerpt Number: 10
94

Comment: We also request that EPA increase the threshold for having to operate continuous 

emission monitors for CO. as proposed, a boiler with a heat input of 100 MMBtu/hr or more, 

whether at an area or major source, would be required to demonstrate compliance with the CO 

limit using a CEM. This is an undue burden on biomass fired boilers. Boilers in our industry are 

frequently in the 100 MMBtu/hr to 249 MMBtu/hr range. These units are typically not otherwise 

required to operate CEMs. Installing and operating CEMs would be a significant additional 

expense without material value added. As a sector, our organic HAP emission rates are not high 

and so do not justify this monitoring requirement as opposed to periodic testing. Therefore, we 

request that EPA increase the threshold for requiring CO CEMs to those units with a heat input 

of 250 MMBtu/hr or greater. 

Response: See the preamble for revisions to the CO limitations and compliance demonstration 

methods.

Commenter Name: David W. Peightal

Commenter Affiliation: Dakota Gasification Company

Document Control Number: EPA-HQ-OAR-2002-0058-3179

Comment Excerpt Number: 10

Comment: The requirement for a CEMS for units larger than 100 MMBtu/hr for CO monitoring 

should be replaced with annual EPA stack testing. 

Response: See the preamble for revisions to the CO limitations and compliance 

demonstration methods.

Commenter Name: Mick Baranko

Commenter Affiliation: Douglas County Forest Products

Document Control Number: EPA-HQ-OAR-2002-0058-2856.1

Comment Excerpt Number: 12

Comment: We also request that EPA increase the threshold for having to operate continuous 

emission monitors for CO. as proposed, a boiler with a heat input of 100 MMBtu/hr or more, 

whether at an area or major source, would be required to demonstrate compliance with the CO 

limit using a CEM. This is an undue burden on biomass fired boilers. Boilers in our industry are 

frequently in the 100 MMBtu/hr to 249 MMBtu/hr range These units are typically not otherwise 

required to operate CEMs. Installing and operating CEMs would be a significant additional 

expense without material value added. As a sector, our organic HAP emission rates are not high 

and so do not justify this monitoring requirement as opposed to periodic testing. Therefore, we 

request that EPA increase the threshold for requiring CO CEMs to those units with a heat input 

of 250 MXIBtu/hr or greater. 
95

Response: See the preamble for revisions to the CO limitations and compliance demonstration 

methods.

Commenter Name: Richard Rosvold

Commenter Affiliation: Xcel Energy Services, Inc

Document Control Number: EPA-HQ-OAR-2002-0058-2955.1

Comment Excerpt Number: 12

Comment: For units that are required to install CO CEMs, the regulation should allow either 

carbon dioxide (CO2) or oxygen (02) to be used as the diluent. Allowing a facility to use CO2 as 

the diluent would allow the direct measurement of CO2 to be used for the recently promulgated 

Mandatory Greenhouse Gas Reporting Rule. We suggest that facilities be allowed to use either 

an 02 or CO2 monitor as the diluent monitor. 

It is unclear why the EPA is requiring that CO measurements for many units be corrected to 3% 

02 instead of a more typical 7% 02, Please explain the basis for the 3% 02 correction as opposed 

to 7% 02 as is used in other EPA regulations. Absent valid justification, we suggest that a 7% 02 

basis be used throughout this rule. 

Response: See the preamble for revisions to the CO limitations and compliance demonstration 

methods.

Commenter Name: Dan F. Hunter

Commenter Affiliation: ConocoPhillips Company

Document Control Number: EPA-HQ-OAR-2002-0058-2867.1

Comment Excerpt Number: 12

Comment: Revise the proposed regulatory text to reflect EPA’s intent, expressed in the

preamble, that CEMS are only required for equipment subject to emission limits and are not 

required for equipment subject to work practice standards. 

Response: See the preamble for revisions to the CO limitations and compliance demonstration 

methods.

Commenter Name: Ann W. McIver

Commenter Affiliation: Citizens Energy Group

Document Control Number: EPA-HQ-OAR-2002-0058-2875.1
96

Comment Excerpt Number: 13

Comment: Citizens requests that EPA consider allowing compliance with the CO emission limit 

in lb/MMBTU in lieu of ppm corrected to 3% O2, allowing sources an alternative to installation 

of an 02 CEMS. Like many other potentially affected units under the Boiler MACT, Citizens 

operates boilers that are affected units in the CAIR Ozone Season NOx trading program. As a 

result, Citizens has a CEM system installed to measure emissions of NOx, using CO2 as the 

diluent gas and for the calculation of heat input. The existing CEMs system is a dilutionextraction system, which will not accommodate an O2 CEM, necessary for the correction of the 

proposed ppm standard to 3% 02. In addition, the coal-fired boilers are required to use CEMs to 

determine emissions of carbon dioxide under the final Greenhouse Gas MMR program, so the 

CO2 analyzer is necessary for that program. Allowing the demonstration of CO compliance using 

lb/MMBTU would allow use of existing CO2 CEMS and avoid the costly installation of a 

separate 02 monitoring system and the necessary calibration gas system to support the on-going 

operation and maintenance of the 02 CEM. 

Response: See the preamble for revisions to the CO limitations and compliance demonstration 

methods. The O2 monitoring in the final rule is used to document compliance with an O2

operating limit established as part of demonstrating good combustion practices to minimize CO 

emissions, and is not used as a diluent gas monitor. EPA notes that adjustments for CO2 can be 

accommodated using EPA Method 19 F-factors. The Fc Factors can be used to convert from ppm 

@ X% CO2 to lb/mmBtu, and then the Fd or Fw factors can be used to convert from lb/mmBtu 

to a ppm @ X% O2 value.

Commenter Name: Deb Hastings

Commenter Affiliation: Texas Oil and Gas Association

Document Control Number: EPA-HQ-OAR-2002-0058-2857.1

Comment Excerpt Number: 14

Comment: EPA should revise the proposed regulatory text to reflect the agency’s intent, 

expressed in the preamble, that continuous emission monitoring systems (CEMS) are only 

required for equipment subject to emission limits and are not required for equipment subject to 

work practice standards. 

Response: See the preamble for revisions to the CO limitations and compliance demonstration 

methods.

Commenter Name: Jim Eubank

Commenter Affiliation: Kentucky Division of Air Quality

Document Control Number: EPA-HQ-OAR-2002-0058-3176.2

Comment Excerpt Number: 16
97

Comment: 40 CFR 63.7510(c) requires that boilers or process heaters that have a heat input 

capacity less than 100 MMBtu/hr to demonstrate initial compliance by conducting a CO 

performance stack test. The Division recommends that sources less than 100 MMBtu/hr should 

be allowed to demonstrate compliance using CO CEMS if they choose. Further it should be 

made clear that this requirement is not applicable to units that have no emission limit 

requirement (i.e., existing units under 10 MMBtu/hr). 

Response: See the preamble for revisions to the CO limitations and compliance demonstration 

methods.

Commenter Name: Richard Rosvold

Commenter Affiliation: Xcel Energy Services, Inc

Document Control Number: EPA-HQ-OAR-2002-0058-2955.1

Comment Excerpt Number: 22

Comment: The relative accuracy test audit (RATA) requirements for CO CEMs, based on the 

proposed limits, would be very difficult to meet in practice. Performance Specification 4A for 

low emission standard CO CEMs requires the relative accuracy (RA) of the monitors to be no 

more than five percent. At the proposed limit, this would require two instruments, calibrated with 

two separate EPA Protocol One cylinder gases, to differ by less than 0.08 ppmv over the course 

of nine RATA runs. The performance specification allows an alternative RA demonstration if the 

two CEMs are within 5 ppm, but this alternative is meaningless when the standard is set at 1 

ppm. 

Response: See the preamble for revisions to the CO limitations and compliance demonstration 

methods.

Commenter Name: Bill Wemhoff

Commenter Affiliation: National Rural Electric Cooperative Association

Document Control Number: EPA-HQ-OAR-2002-0058-2835.1

Comment Excerpt Number: 24

Comment: Concerns regarding the use of carbon monoxide (“CO”) CEMS to make compliance 

determinations at some of the proposed emission limits, and has objections to EPA’s proposed 

use of PM CEMS. 

Response: See the preamble for revisions to the CO limitations and compliance demonstration 

methods.
98

Commenter Name: David O'Keefe

Commenter Affiliation: USEC, Inc

Document Control Number: EPA-HQ-OAR-2002-0058-3122

Comment Excerpt Number: 26

Comment: CO CEMS. The proposal requires a CO CEMS for units with heat input greater or 

equal to 100 MMBtu/hr. This threshold is too low and costly. Cost of installation and operation 

is likely similar to a PM CEMS. Using the cost reasoning as provided for the PM CEMS the 

threshold should be raised to greater or equal to 250 MMBtu/hr heat input. 

Response: See the preamble for revisions to the CO limitations and compliance demonstration 

methods.

Commenter Name: Bruce A. Steiner

Commenter Affiliation: American Coke and Coal Chemicals Institute

Document Control Number: EPA-HQ-OAR-2002-0058-2849.1

Comment Excerpt Number: 29

Comment: The Proposed Rule requires boilers or process heaters with a heat input capacity less 

than 100 MMBTU per hour to conduct a stack test for CO, but no CO standard is established in 

proposed 63.7500(a). Similarly, proposed §63.7510(c) requires a CO CEMS for boilers and 

process heaters with a heat input capacity equal to or greater than 100 MMBTU per hour, but no 

CO standard is established in proposed §63.7500. It makes no sense for testing to be conducted 

for a parameter for which no limit or 

surrogate is in place. ACCCI recommends that §63.7510(c) be amended to specify which 

subcategories are covered or limited to those units that are subject to the CO standard, by adding, 

for example: “If your boiler or process heater is subject to a CO limit and has a heat input 

capacity ...." 

Similarly, Tables 1 through 3 do not establish a CO limit for gas subcategory 1 units. It is 

therefore not appropriate to require a CEMS for these units. The requirements for operation in 

accordance with good air pollution control practice (§63.7505(b)) and periodic burner tune-ups 

(§63.7540) is more than sufficient. The periodic tune-up gives an excellent assurance of 

compliance and burners in boilers and process heaters should vary very little over time. The 

requirement for good air pollution control practice minimizes this variation. There is an adequate 

assurance of compliance without the need for a CEMS. 

Response: See the preamble for revisions to the CO limitations and compliance demonstration 

methods.
99

Commenter Name: Kevin M. Dempsey

Commenter Affiliation: American Iron and Steel Institute

Document Control Number: EPA-HQ-OAR-2002-0058-2998.1

Comment Excerpt Number: 44

Comment: CO Monitoring Should be Limited to Those Subcategories Subject to CO Limits 

The Proposed Rule requires boilers or process heaters with a heat input capacity less than 100 

MMBTU per hour to conduct a stack test for CO, but no CO standard is established in proposed 

63.7500(a). Similarly, proposed section 63.7510(c) requires a CO CEMS for boilers and process 

heaters with a heat input capacity equal to or greater than 100 MMBTU per hour, but no CO 

standard is established in proposed section 63.7500. It makes no sense for testing to be 

conducted for a parameter for which no limit or surrogate is in place. AISI recommends that 

section 63.7510(c) be amended to specify which subcategories are covered or limited to those 

units that are subject to the CO standard, by adding, for example: “If your boiler or process 

heater is subject to a CO limit and has a heat input capacity . ..." 

Similarly, Tables 1 through 3 do not establish a CO limit for gas subcategory 1 units. It is 

therefore not appropriate to require a CEMS for these units. The requirements for operation in 

accordance with good air pollution control practice (section 63.7505(b)) and periodic burner 

tune-ups (section 63.7540) is more than sufficient. The periodic tune-up gives an excellent 

assurance of compliance and burners in boilers and process heaters should vary very little over 

time. The requirement for good air pollution control practice minimizes this variation. There is 

an adequate assurance of compliance without the need for a CEMS. 

Response: See the preamble for revisions to the CO limitations and compliance demonstration 

methods.

Commenter Name: Lee B. Zeugin

Commenter Affiliation: Utility Air Regulatory Group

Document Control Number: EPA-HQ-OAR-2002-0058-2880.1

Comment Excerpt Number: 46

Comment: EPA proposes to require all units with heat input capacity ?100 lb/mmBtu to install 

and operate a CO CEMS and to determine compliance on a 30-day rolling average. EPA 

proposes to require installation and evaluation of the CEMS under Performance Specification 

(“PS”) 4A and the site-specific monitoring plan developed under § 63.7505(d). Proposed § 

63.7525(a)(1) and (2). In the preamble, EPA simply states that it has determined that requiring 

CO CEMS is “reasonable,” and does not specifically solicit comment on that aspect of the 

proposal. EPA’s proposal is flawed in several respects. 
100

PS 4A was developed primarily for CEMS that comply with emission standards “less than 200 

ppmv.” 40 C.F.R. Part 60, Appendix B, PS 4A § 1.2.1. In contrast, EPA proposes standards 

ranging from a high of 1,010 ppmv to a low of 1 ppmv (both corrected to 3 percent O2). While 

one could certainly question the reasoning behind applying a specification written for low 

emission standards to some of the proposed standards, UARG’s primary concern is with the 1 

ppmv standard. Applying PS 4A (or any specification) to a limit that low presents many 

problems. The first issue is a simple matter of the technology. Experience with CO analyzers 

suggests that a typical 24-hour drift can be on the order of 1 ppmv. [See submittal for COCEMS 

issues discussion]. Depending upon the span of the instrument, the allowed drift could be much 

greater. PS 4A allows and anticipates drift of up to 5 percent of the established span value for 6 

out of 7 days. PS 4A § 13.1. If a CEMS can be expected to drift on a daily basis an amount equal 

to the emission limit, compliance with that limit would certainly be impossible. 

Response: See the preamble for revisions to the CO limitations and compliance demonstration 

methods.

Commenter Name: Lee B. Zeugin

Commenter Affiliation: Utility Air Regulatory Group

Document Control Number: EPA-HQ-OAR-2002-0058-2880.1

Comment Excerpt Number: 47

Comment: Perhaps more significant, however, are EPA’s expectations for accuracy under the 

“relative accuracy specification.” When EPA developed PS 4A, the Agency recognized the 

potential difficulty in meeting the relative accuracy specification at low levels and included an 

alternative specification. At the time, EPA determined that the lowest achievable relative 

accuracy standard was 5 ppm. PS 4A, § 13.2. Again, expecting sources to determine compliance 

with a 1 ppm standard with a CO CEMS that has allowable error of 5 ppm is not reasonable. In 

short, while the PS 4A drift specification and relative accuracy standard may be achievable, they 

have little relevance in assuring the accuracy of the 1 ppmv measurement EPA’s proposed 

standard requires the CO CEMS to make. And EPA has presented no data to determine the 

achievability of any more stringent performance specifications. 

Response: See the preamble for revisions to the CO limitations and compliance demonstration 

methods.

Commenter Name: Lee B. Zeugin

Commenter Affiliation: Utility Air Regulatory Group

Document Control Number: EPA-HQ-OAR-2002-0058-2880.1

Comment Excerpt Number: 48
101

Comment: UARG also is concerned about several other requirements for CO CEMS that may 

not be achievable. PS 4A specifies a response time test protocol (to measure the time it takes to 

achieve 95 percent of a stable value) and requires that the response time not exceed 1.5 minutes. 

When measuring low levels of any emission, a common strategy used is to use a longer 

averaging time in the analyzer itself to reduce signal noise. Making CO measurements at 5-10 

ppm may require an analyzer averaging time in the 3-5 minute range. While the 1.5 minute 

response time may have been achievable for the source categories for which EPA wrote PS 4A, 

it may not be achievable for CO CEMS installed on the tall stacks typical of units owned and 

operated by UARG members due to long sample lines and long sample acquisition time (even 

with increased sample gas pressure and flow rate over those typically used). Nor does UARG 

understand the purpose of this requirement, given that the CEMS are provided a full 15-minutes 

to complete a measurement cycle. Proposed § 63.7525(a)(3). 

Response: See the preamble for revisions to the CO limitations and compliance demonstration 

methods.

Commenter Name: Lee B. Zeugin

Commenter Affiliation: Utility Air Regulatory Group

Document Control Number: EPA-HQ-OAR-2002-0058-2880.1

Comment Excerpt Number: 49

Comment: Moreover, although EPA does not propose any ongoing quality assurance 

requirements for CO CEMS, other than those established under § 63.8 and the unit’s site-specific 

monitoring plan at § 63.7505(d), UARG expects EPA and states to require that those plans 

include the same types of tests found in 40 C.F.R. Part 60, Appendix F, Procedure 1. To ensure 

that a monitor is measuring accurately in the range that includes the emission limit, the CEMS 

span is usually set at 1.5 to 2 times the emission limit. See, e.g., PS 4A, § 6.1.2 (addressing dual 

range analyzers); Attachment B at 2. Procedure 1 requires a quarterly cylinder gas audit 

(“CGA”) to be performed at two audit points based on a percent of span (20-30 and 50-60 

percent). A CGA also must be performed using an audit gas that has been certified by 

comparison to the National Institute of Standards and Technology (“NIST”) or EPA Traceability 

Protocol 1. Procedure 1, § 5.1.2. The lowest NIST-traceable CO audit gas UARG has been able 

to locate is 5 ppmv. However, a unit that sets its CO span at 2 ppm as recommended in PS 4A 

would need NIST traceable gases of approximately 0.5 ppmv and 1 ppmv to meet the CGA 

requirement. Although EPA presumably could waive both the span recommendation and CGA 

requirement, UARG questions what confidence its members could have in the ability of a CO 

CEMS that does not satisfy those criteria to accurately monitor compliance with a 1 ppm 

standard. EPA must reconsider its proposed emission standards and performance evaluation 

requirements in light of these problems. It simply is not possible to comply with EPA’s proposed 

CO monitoring requirements. [See submittal for COCEMS issues discussion]. 
102

Response: See the preamble for revisions to the CO limitations and compliance demonstration 

methods.

Commenter Name: Christopher S. Colman

Commenter Affiliation: Hovensa LLC

Document Control Number: EPA-HQ-OAR-2002-0058-2863.1

Comment Excerpt Number: 50

Comment: Proposed Rule Language §63.7525(a): 

“If your boiler or process heater has a heat input capacity of 100 MMBtu per hour or greater, you 

must install, operate and maintain a continuous emission monitoring system (CEMS) for CO and 

oxygen......” 

Comments: 

The proposed rule language does not specify applicability for installation of the CO continuous 

monitoring system, other than the size of a unit. The language should be revised to specify 

CEMS are only required for units with applicable CO limits listed in Table 1 or 2 of the proposed 

rule. 

Response: See the preamble for revisions to the CO limitations and compliance demonstration 

methods.

Commenter Name: Lee B. Zeugin

Commenter Affiliation: Utility Air Regulatory Group

Document Control Number: EPA-HQ-OAR-2002-0058-2880.1

Comment Excerpt Number: 50

Comment: Proposed § 63.7525(a) requires sources that must have a CO CEMS to also install 

and operate an O2 CEMS in order to correct data to the units of the proposed standard (ppm by 

volume, dry basis corrected to 3 percent O2). By choosing O2 as the basis for the correction 

(instead of CO2), EPA has precluded the use of dilution-based monitoring systems, which have 

become the systems of choice for UARG members under EPA’s Acid Rain Program because of 

their proven accuracy and reliability.[ 29 Dilution systems are often the only reasonable choice 

for units with wet scrubbers because they eliminate plugging and other issues associated with 

corrosive flue gas conditions. ] Dilution-based systems measure on a wet basis and can 

accurately measure CO2, but cannot be used to measure O2 because the dilution air contains O2. 

To allow source owners/operators to choose the most accurate and reliable system, and the 

system with which they have the most experience (and can use for compliance with other rules), 

EPA should promulgate alternative standards in lb/mmBtu. Attachment B at 5. In addition, any 

emission limit expressed at any O2 concentration can be directly converted to an equivalent 

lb/mmBtu limit. EPA should promulgate the standards in this fashion to allow sources to choose 

their preferred sampling system and diluent. UARG has previously discussed these conversions 
103

and the advantages of such standards for boilers in its Petition for Reconsideration of EPA’s 

2006 Standards of Performance for Stationary Combustion Turbines, EPA-HQ-OAR-2004-0490-

0325 at 11-13 (Sept.7,2006) (incorporated by reference).[ EPA granted that petition on 

December7,2006.] 

Response: See the response to EPA-HQ-OAR-2002-0058-2875.1, Comment Excerpt Number 

13.

Commenter Name: Lee B. Zeugin

Commenter Affiliation: Utility Air Regulatory Group

Document Control Number: EPA-HQ-OAR-2002-0058-2880.1

Comment Excerpt Number: 51

Comment: Finally, in the preamble, EPA states that its proposal would require units to conduct 

an initial and annual test to determine compliance with the CO standard using “either EPA 

Method 10 or a CO CEMS.” Proposed § 63.7510(c) does state that for units required to use CO 

CEMS the “initial compliance demonstration . . . is conducting a performance evaluation” of the 

CEMS.” 75 Fed. Reg. at 32,051(emphasis added). And, proposed § 63.7540(a) (8) requires units 

with CO CEMS to maintain CO below or at the applicable standard. However, proposed § 

64.7530 (addressing demonstration of initial compliance) contains no exception from the 

requirement to conduct “initial performance tests (performance stack tests and fuel analyses)”and 

proposed § 63.7515 contains no exception for subsequent performance tests for units with 

CEMS. If EPA resolves the above issues and promulgates a rule requiring use of CO CEMS to 

demonstrate compliance, EPA must revise the other provisions to make clear that units required 

to use CO CEMS are not also subject to performance testing. 

Response: See the preamble for revisions to the CO limitations and compliance demonstration 

methods.

Commenter Name: Traylor Champion

Commenter Affiliation: Georgia-Pacific LLC

Document Control Number: EPA-HQ-OAR-2002-0058-2745.1

Comment Excerpt Number: 59

Comment: In the proposed rule at 40 CFR 63.7525(a), EPA specifies that a carbon monoxide 

continuous emission monitoring system ( CO CEMS) must be installed on all boilers and process 

heaters that are more than 100 MM Btu/hr. This language would require that a CO CEMS be 

installed on all existing and new Gas 1-fired units. However, EPA did not establish CO limits for 

these units, so it should not be necessary to install a CO CEMS. 
104

GP urges EPA to eliminate this confusion by re-writing the first sentence of 63.7525(a) to read: 

“If your boiler or process heater has a CO limitation and has a heat input of 100 MMBtu per hour 

or greater...”. 

Response: See the preamble for revisions to the CO limitations and compliance demonstration 

methods.

Commenter Name: Traylor Champion

Commenter Affiliation: Georgia-Pacific LLC

Document Control Number: EPA-HQ-OAR-2002-0058-2745.1

Comment Excerpt Number: 60

Comment: The specification of PS 4A for the required CO CEMS. PS 4A is stated as 

having been primarily developed for CEMS intended to demonstrate compliance with CO 

emission standards less than 200 ppmv. Because the proposed rule specifies significantly higher 

limits (560 ppmv, 1010 ppmv) for several boiler/process heater subcategories, it would seem 

appropriate to amend the proposed rule to allow for monitors complying with PS 4 which were 

designed for CO span values in the 1000 ppmv range. 

Response: See the preamble for revisions to the CO limitations and compliance demonstration 

methods.

Commenter Name: Traylor Champion

Commenter Affiliation: Georgia-Pacific LLC

Document Control Number: EPA-HQ-OAR-2002-0058-2745.1

Comment Excerpt Number: 61

Comment: The purpose of the O2 CEMS is to serve as the diluent analyzer needed to provide 

the data for the required O2 correction data for the CO concentration. PS 2, however, allows the 

use of either a CO2 or O2 diluent analyzer to calculate the O2 correction. CO2 is commonly used 

by other CEMS (NOx, SO2, etc.) because CO2 analyzers are generally considered to be more 

reliable and stable than O2 monitors. Many existing boilers/process heaters with existing CEMS 

will already have a CO2 CEMS in-place which could also be used for correction of the CO data. 

While the cited Performance Standards and EPA Methods would permit its use, the text of the 

proposed rule appears to require the use of an O2 diluent gas analyzer only. While the use of 

CO2 data to calculate the O2 correction could be accomplished via a request to EPA for approval 

of alternative monitoring, amendment of the proposed rule to explicitly allow for its use would 

be a far more efficient resolution. 
105

Response: See the response to EPA-HQ-OAR-2002-0058-2875.1, Comment Excerpt Number 

13.

Commenter Name: Lee B. Zeugin

Commenter Affiliation: Utility Air Regulatory Group

Document Control Number: EPA-HQ-OAR-2002-0058-2880.1

Comment Excerpt Number: 98

Comment: The proposed IB rule requires units wit a heat imput capacity greater than 100 x 

10exp06 BTU/hr to install operate and mainitain CO and O2 continuous emission monitoring 

systems (CEMS). The O2 analyzer must comply with Performance Specficiation 3 (PS-3), and 

the CO analyzer with Performance Specification 4A (PS-4A). Unfortunately, PS-4A does not 

appear adequate for many of the proposed CO emission limits. Quoting from PS-4A, [t]his 

performance specification was developed primarlily for CEMS that comply with low emission 

standards (less than 200 ppmv)[40C.F.R. part 60, Appendix B, Performance Specification 4A, 

section 1,21.] 

For six of the nine subcategories for new units, EPA has proposed CO limits < 90 ppmv, and for 

five of the nine subcategories for existing units, EPA has proposed CO limits < 90 ppmv. Four 

subcategories (two for new units and two existing for existing units) have proposed CO limits 

equal to 1 ppmv. The proposed 1 ppmv limits present problems from multiple perspectives, not 

the least of which are measurement concerns. Anyone with much experience with a CO analyzer 

knows that the typical 24-hour drift of a CO analyzer is on the order of 1 ppmv. Thus, the 

expected daily drift of the analyzer is about equal to the proposed emission limit. When EPA 

developed PS-4A, the Agency recognized the potential difficulty in meeting the relative accuracy 

specification at low levels because the stack concentration, as measured by the appropriate 

reference method, is in the denominator of the relative accuracy equation. Thus, as the stack 

concentration approaches zero, the computed relative accuracy approaches infinity. EPA 

recognized this problem and included an alternate specification of 5 ppmv when relative 

accuracy is calculated as the absolute average difference between the reference method and 

GEMS plus the 2.5 percent confidence coefficient.[ Ibid, section 13.2.] 5 The problem is that 

EPA’s current CO performance specification permits the analyzer error (relative accuracy) to be 

a factor equal to 5 times four of the proposed CO emission limits. 

Response: See the preamble for revisions to the CO limitations and compliance demonstration 

methods.

Commenter Name: Lee B. Zeugin

Commenter Affiliation: Utility Air Regulatory Group

Document Control Number: EPA-HQ-OAR-2002-0058-2880.1

Comment Excerpt Number: 99
106

Comment: Although no specific quality assurance requirements are contained in the proposed 

rule, RMB is concerned that EPA might be tempted to simply insert some of the requirements 

contained in 40 C.F.R. Part 60, Appendix F in the final lB MACT rule. A number of significant 

CO monitoring issues would occur if EPA were to include the quality assurance requirements in 

Procedure 1 of Appendix F in the final rule. The span of a compliance monitor is typically 

selected to be 1.5 to 2 times the emission limit. Procedure 1 requires a quarterly cylinder gas 

audit (CGA) be performed at two audit points: (1) 20 to 30 percent of the span value and (2) 50 

to 60 percent of the span values. A CGA must be conducted with audit gases that have been 

certified by comparison to National Institute of Standards and Technology (NIST) or EPA 

Traceability Protocol No. 1. Assume for an lB boiler with a 1 ppmv CO limit, we have selected a 

span equal to 2 ppmv. To conduct the quarterly CGA we need NIST-traceable audit gases equal 

to about (1) 0.25 x 2 = 0.5 ppmv and (2) 0.5 x 2 = 1 ppmv. The lowest NIST-traceable CO 

calibration gas that RMB has been able to locate is 5 ppmv. Thus, it would not be possible to 

comply with the proposed CO monitoring requirements. 

Response: See the preamble for revisions to the CO limitations and compliance demonstration 

methods.

Commenter Name: Lee B. Zeugin

Commenter Affiliation: Utility Air Regulatory Group

Document Control Number: EPA-HQ-OAR-2002-0058-2880.1

Comment Excerpt Number: 100

Comment: Another non-trivial issue posed by Procedure 1 is the definition of an "out-ofcontrol" period when a calibration drift (CD) is failed. Procedure 1 states the "out-of-control" 

period is the time corresponding to completion of the daily CD check preceding the daily CD 

check that results in a CD in excess of four times the allowable limit.[ 40 C.F.R. Part 60, 

Appendix F, Procedure 1, Section 4.3.1.] In other words, this provision in Procedure 1 results in 

data being invalidated retrospectively. The retrospective invalidation of CO data places the 

owner/operator in an untenable situation given the requirement to report any period for which the 

monitoring system is out-of-control as a deviation from the monitoring requirements.[ 

§63.7525(a)(6) of the proposed rule - 75 Fed. Reg. 32055 (June 4, 2010).] Hopefully, EPA’s 

omission of Procedure 1 from the proposed lB MACT rule was not an oversight, but rather a 

recognition of many of the issues discussed above. RMB encourages EPA to continue to allow 

owner/operators the flexibility in developing site-specific monitoring plans that is currently 

provided for in the proposed rule. 

Response: See the preamble for revisions to the CO limitations and compliance demonstration 

methods.

Commenter Name: Lee B. Zeugin
107

Commenter Affiliation: Utility Air Regulatory Group

Document Control Number: EPA-HQ-OAR-2002-0058-2880.1

Comment Excerpt Number: 105

Comment: For units with heat input greater than 100 lb/10exp6 Btu/hr, EPA’s proposed section 

63.7525(a) requires the continuous measurement of CO and 02. This requirement is the direct 

and unfortunate result of EPA’s choice of units for the CO emission limit (i.e., x ppm by volume, 

dry basis corrected to 3% 02). By choosing 02 as the basis for correction (instead of CO2), EPA 

has precluded the use of dilution-based monitoring systems, which have proved to be so reliable 

and accurate in other regulatory programs such as EPA’s Acid Rain Program. Dilution-based 

systems measure on a wet basis and can accurately measure CO2. Dilution-based systems cannot 

be used to measure 02 and generally do not measure on a dry basis. The monitoring and 

compliance determination procedures for CO would be much more straightforward, if the units 

of the emission limit were lb/10exp6 Btu instead of ppm by volume, dry basis corrected to 3% 

02. 

Response: See the response to EPA-HQ-OAR-2002-0058-2875.1, Comment Excerpt Number

13.

Commenter Name: Jim Griffin

Commenter Affiliation: American Chemistry Council

Document Control Number: EPA-HQ-OAR-2002-0058-2792.1

Comment Excerpt Number: 175

Comment: EMS DATA OBTAINED WHEN OPERATING AT LESS THAN 50% LOAD 

SHOULD BE EXCLUDED. As indicated in the proposed area source industrial boiler rule [75 

Fed. Reg. at 31929.] and the 2004 boiler rule, it is appropriate to exclude CO monitoring data 

from periods where a boiler or process heater is operating at less than 50% load. We provide 

information elsewhere in these comments that demonstrates CO emissions are higher at low 

loads, especially when corrected to a standard percent oxygen. Exclusion of this data will also 

allow some relief for standby units. EPA should incentivize stand-by operation because this 

means that regulated entities have a better chance of minimizing malfunction related emissions 

elsewhere at their site if they have a boiler on standby, which can be used on an as needed basis. 

Response: Compliance with the CO emission limits will be tested at representative operating 

conditions through performance stack tests.

PM CEMS

Commenter Name: MSI - Mechanical Systems, Inc
108

Commenter Affiliation: MSI - Mechanical Systems, Inc

Document Control Number: EPA-HQ-OAR-2002-0058-0848.1

Comment Excerpt Number: 1

Comment: PM CEMS are commercially available and have been installed, certified, and 

operated according to PS-11 on sources in the United States. As of this date, at least sixty seven 

(67) PM CEMS are operating on coal-fired boilers in the United States. Many more are currently 

on order or are in the process of startup and certification. These sources include both wet and dry 

stack gas streams. These sources combust a variety of fuels and some use fuel blends. These 

sources use various combinations of air pollution control systems. In addition to PM CEMS 

operating at coal-fired boilers, a few PM CEMS are installed and operating on other source types 

in the United States. The experiences gained by PM CEMS vendors in their current applications 

are directly relatable to ICI boilers with heat input of 250 mmBtu/hr or greater that burn coal, 

biomass or residual oil. 

We are aware that several of these existing PM CEMS are being used to monitor compliance 

with a PM standard. These compliance particulate monitors are operating in the following states: 

Indiana, Kentucky, North Carolina, Ohio, and Maryland. The successful use of PM CEMS for 

compliance monitoring in those applications can give the Agency confidence that PM CEMS can 

be used for compliance determination under this proposed rule. 

Response: Thank you for the information on PM CEMS applications.

Commenter Name: Thomas J. Christofk

Commenter Affiliation: Placer County Air Pollution Control District

Document Control Number: EPA-HQ-OAR-2002-0058-1598.1

Comment Excerpt Number: 6

Comment: PCAPCD supports the requirement for the use of PM Continuous Emissions 

Monitoring Systems, provided that EPA sponsor and conduct a demonstration program of such 

systems on biomass boilers that comprehensively determines that the monitors work and are 

cost-effective. PCAPCD also supports a subsequent allowance for a phase in period for use as a 

compliance and enforcement tool. 

Response: PM CEMS have been demonstrated for a variety of applications. PM CEMS 

performance specifications and QA procedures have been around quite a while with PS-11 and 

Procedure 2 promulgated January 2004. There have been at least 65 successful installations in 

the United States and in other countries. A successful installation is obtained when a PM CEMS 

passes the PS-11 statistical criteria, thereby demonstrating that an acceptable level of accuracy is 

achieved. PS-11 provides the steps in obtaining a reliable successful correlation with reference 

methods, thereby ensuring compliance data that is sufficient to determine compliance with PM 

emission limits. Procedure 2 describes the required audits to insure that subsequent 

measurements are stable and within acceptable limits, thereby ensuring reliable compliance data.
109

Applying a technology suitable for a particular application would naturally take some planning. 

Section 2.4(1) of PS-11 states that you should select a PM CEMS that is appropriate for your 

source. EPA is aware of PM CEMS technologies that the measurement of mass concentration is 

not affected by changes in the particulate composition that may occur with multiple types of 

fuels and wastes. Manufacturers of beta gauge instruments have demonstrated that the calibration 

curve does not change as the fuel mix changes. Vendors have guaranteed that their PM CEMS 

will meet the PS-11 criteria for multi-fuel boilers. PS-11 provides for situations where multiple 

correlations may be needed for a PM CEMS technology (see Section 2.3 of PS-11).

Commenter Name: Michael L. Steele

Commenter Affiliation: CraftMaster Manufacturing, Inc

Document Control Number: EPA-HQ-OAR-2002-0058-1907.1

Comment Excerpt Number: 5

Comment: We object to the requirement to install PM CEMJs on biomass units >250 MMBtu 

per hour. Units controlled by an electrostatic precipitator or other applicable control device are 

already required to have opacity monitors and limits under §63.7500 and should not have the 

additional burden of PM monitoring as well. Biomass-fired units should be encouraged and not

burdened with additional monitoring requirements due to their low Greenhouse Gas (GHG) 

emissions with respect to fossil-fueled units. ptease reference Clean Air Act § 112{ d)(3)(A) & 

(8),non-airquality health and environmental impacts. 

PM is a surrogate for non-mercury metal HAP’s emissions. Per the preamble Table 10, biomass 

units emit an average of about 20 Lbs of non-mercury metals per ton of PM while coal-fired 

units emit about 91 Lbs per ton of PM. The PM limits for existing biomass and coal 

subcategories are the same at 0.02 Lbs per MMBtu. Then a 251 MMBtu per hour coal-fired unit 

could emit over four (4) times the non-mercury metals as a 251 MMBtu per hour biomass unit 

with the same PM mass emissions. Similarly, a 251 MMBtu per hour liquid-fired unit could also 

emit over four (4) times the non-mercury metals as the same size biomass unit The lower PM 

limit for liquid-fired units is offset by the much higher HAP’s emissions per ton of PM. Then to 

require a PM CEM’s on the biomass unit and not the liquid-fired unit fails to monitor the 

significantly larger HAP’s source while increasing the monitoring burden on the lower emitting 

biomass source. It would seem appropriate from a HAP’s standpoint to monitor the larger coalfired and liquid-fired units and not the inherently low non-mercury metal HApts emitting 

biomass units. 

Response: All solid and liquid fuel boilers over 250 mmBtu/hour are treated the same, and 

require use of a PM CEMS.

Commenter Name: David W. Peightal

Commenter Affiliation: Dakota Gasification Company
110

Document Control Number: EPA-HQ-OAR-2002-0058-3179

Comment Excerpt Number: 7

Comment: For particulate matter (PM), DGC views annual stack testing as a more viable option 

than installing a Continuous Emission Monitoring System (CEMS) because the MACT limits 

have been formed based on stack tests and not CEMS data. 

Response: EPA disagrees, and has established the level of monitoring that EPA believes will 

best ensure continuous compliance with the emission limits established in the rule. EPA does 

not agree with the implication in this comment that use of a CEM renders the standard more 

stringent and so results in floors and standards) more stringent than those achieved by average of 

the best performing sources. First, the continuous collection of data used to assess compliance 

with this standard does not create a limit more stringent that otherwise allowed. Further, a 

statistically-based adjustment to account for emissions variability, and which, in this case, 

increases the numerical value of the standard (and its longer averaging period), does not make 

the standard more stringent. Finally, increasing the averaging period beyond the duration 

associated with conducting a performance test normally makes a standard more lenient because 

there is more opportunity to average out individual results.

Commenter Name: Michael L. Corvese

Commenter Affiliation: Thermo Fisher Scientific, Inc

Document Control Number: EPA-HQ-OAR-2002-0058-2997.1

Comment Excerpt Number: 7

Comment: Recommend that EPA allow an optional procedure for initial certification of the 

Thermo Scientific “self validating” Hybrid PM CEMS. 

The Thermo Scientific Hybrid PM CEMS includes two light scattering sensing devices, and 

internal TEOM reference PM mass measurement, and many other components not included in 

other PM CEMS. Some of the requirements in PS11 such as zero and upscale calibration drift 

tests for the light scattering sensors are appropriate. However, as also described in Comment 1, 

the internal TEOM can be used to calibrate the light scattering devices initially, periodically, 

whenever a change in PM characteristics is indicated by the ratio of the light scattering outputs, 

and/or whenever a new PM concentration is encountered. Thus, establishing the correlation 

described by PS11 by forcing source emissions over an extended range and conducting a 

minimum of 15 pairs of Method 5 measurements to acquire data for the regression analysis is not 

needed and creates problems and adverse effects as previously described. We asserts that 

comparing six EPA Method 5, Method 17 or ASTM D6831-02 test runs (three runs at each of 

two distinct PM concentrations) to the internal TEOM in the Hybrid PM CEMS is sufficient to 

establish the relationship of the internal TEOM output to the external PM reference 

measurements. Thereafter, the light scattering devices can be directly calibrated by the internal 

TEOM at whatever conditions are actually encountered at the particular source. We are willing 

to demonstrate the viability of this approach, or other approaches that are acceptable to EPA, by 

conducting field tests at representative sources. 
111

Response: Continuation of Document Control Number: EPA-HQ-OAR-2002-0058-2997.1. See 

response to Comment Excerpt Number: 3.

Commenter Name: Nilaksh Kothari

Commenter Affiliation: Manitowoc Public Utilities

Document Control Number: EPA-HQ-OAR-2002-0058-2810.1

Comment Excerpt Number: 7

Comment: MPU recommends that EPA increase the level for when a PM CEMS is required 

from 250 mmBtu/hour to 300 mmBtu/hour. We believe that the bag leak detection system 

requirement should be applicable up to 300 mmBtu/hour, as there are electric utility boilers of 

less than 25MW in the 250-300 mmBtu/hour range. MPU formally investigated bag leak 

detection systems and PM CEMS equipment for monitoring baghouse performance. The 

conclusion, for a variety of reasons, favored the bag leak detection system over PM CEMS. 

Attached please find a copy of the MPU report titled “Engineering Study Of Potential For 

Monitoring Particulate Matter (PM) Emissions With Continuous Emissions Monitoring Systems 

(CEMS) Or Bag Leak Detection Systems (BLDS) For Boilers B28 And B09” dated September 

24, 2009. Therefore, we believe more flexibility in the selection of bag house monitoring 

equipment be provided as both systems can adequately monitor the control system. 

Response: EPA has used the 250 mmBtu/hour threshold as it is a typical cut-off used in boiler 

rules and maintains a degree of standardization. 

Commenter Name: Michael L. Corvese

Commenter Affiliation: Thermo Fisher Scientific, Inc

Document Control Number: EPA-HQ-OAR-2002-0058-2997.1

Comment Excerpt Number: 8

Comment: The frequency specified in the proposed regulations at section 63.7540 (a)(9)(iii) for 

conducting PM CEMS Relative Response Audits and Response Correlation Audits and the 

procedures for these QA checks should be modified for the Thermo Scientific Hybrid PM CEMS 

which can automatically detect and correct for changes in particle size, refractive index, and 

other PM matrix parameters. 

Procedure 2 of Appendix F prescribes that the Relative Response Audit (RRA) includes a 

comparison of at least three independent PM test runs with the PM CEMS at the “as found” 

source operating conditions. Procedure 2 specifies that Response Correlation Audit consist of a 

comparison of at least 12 independent PM test runs (paired PM tests recommended) with the PM 

CEMS, and requires that the PM concentrations must be distributed over three PM concentration 
112

ranges. None of the reference test results may exceed the original PM concentration range 

established for the previous certification of the PM CEMS by PS11. The RRA acceptance 

criterion is that two thirds of the test results must fall within ± 25 of the emission standard 

relative to the original correlation curve. The RCA acceptance criterion is that 75% of the test 

results must fall within ± 25 of the emission standard relative to the original correlation curve. 

The proposed regulation at section 63.7540 (a)(9)(iii) specifies that the RRA be conducted 

annually and the RCA be conducted every three years. Failure of either audit may require 

repeating the audit, recalculating a new correlation function, and in some cases, repeating the 

initial certification correlation. 

We believe that the infrequent RRA and RCA audits and lax acceptance criteria provide little 

real assurance of the PM CEMS data quality between such tests. However, in view of the 

difficulty of conducting such tests, requiring even more testing would be unacceptable. The 

Thermo Scientific Hybrid PM CEMS provides for frequent validation and calibration of the 

output of the two light scattering devices by comparison to the internal TEOM reference, and 

these calibrations can be scheduled to occur automatically on a periodic basis, when a change is 

detected in PM characteristics based on the ratio of the two light scattering device outputs, or any 

time a new PM concentration occurs, or other occasions when desired by the plant operator. We 

asserts that the Hybrid PM CEMS provides far better quality assurance, more reliable PM 

monitoring data, and less expense due to external problems that will adversely affect other PM 

CEMS and render the PS 11/Procedure 2 approach very cumbersome. 

We will develop and submit an alternative QA approach to EPA based on representative field 

tests of the final Hybrid PM CEMS design. 

Response: Continuation of Document Control Number: EPA-HQ-OAR-2002-0058-2997.1. See 

response to Comment Excerpt Number: 3.

Commenter Name: Ann W. McIver

Commenter Affiliation: Citizens Energy Group

Document Control Number: EPA-HQ-OAR-2002-0058-2875.1

Comment Excerpt Number: 8

Comment: Citizens encourages EPA to consider the use of parametric monitoring, including 

opacity and bag-leak detection equipment, in lieu of the PM CEMs as the compliance monitoring 

tools for this rule. 

Response: EPA has included such flexibility across the full range of boilers subject to this rule. 

Only the largest boilers firing solid and liquid fuels must use a PM CEMS under the rule.
113

Commenter Name: Paul J. Allen

Commenter Affiliation: Constellation Energy

Document Control Number: EPA-HQ-OAR-2002-0058-3164

Comment Excerpt Number: 9

Comment: Allow stack testing in lieu of continuous PM monitoring. In our opinion, PM testing 

is more reliable than continuous monitoring. Constellation Energy does not support the 

requirement of a PM CEMS because they have not been demonstrated on biomass boilers. We 

are not confident the monitors will work adequately and doubt that they will be cost-effective. 

Annual source testing can meet the required need at a lower cost with reliable data 

Response: EPA disagrees. See the response to EPA-HQ-OAR-2002-0058-2913.1, Comment 

Excerpt Number 17.

Commenter Name: Michael L. Corvese

Commenter Affiliation: Thermo Fisher Scientific, Inc

Document Control Number: EPA-HQ-OAR-2002-0058-2997.1

Comment Excerpt Number: 9

Comment: The requirements at section 63.7525 (b)(6) appears to require redundant PM CEMS 

to acquire data for all source operating hours and is overly restrictive and unnecessary. 

Section section 63.7525 (b)(6) states, 

“(6) When PM emissions data are not obtained because of CEMS breakdowns, repairs, 

calibration checks, and zero and span adjustments, emissions data shall be obtained by using 

other monitoring systems as approved by the Administrator or EPA Reference Method19 of 

appendix A of 40 CFR part 60 to provide, as necessary, valid emissions data for all operating 

hours per 30-day rolling average.” 

We expect that the severity of this language is unintended. The language also appears to be 

inconsistent with the language of section 63.7535(a) through (c). The language cited above 

should be modified and clarified. PM CEMS will require periodic maintenance and repairs. Data 

will be lost during routine preventive maintenance and certain required QA activities. PM CEMS 

may be found to be “out of control” with respect to the Appendix F, Procedure 2 criteria, 

especially the Relative Response Audits and Relative Correlation Audits based on periodic 

comparisons with stack testing results. At the very low emissions levels required by the proposed 

standards, some such failures are expected due to the limitations of the EPA PM test methods 

and are not in any way the fault of the monitoring equipment. In other cases, failures for some 

types of monitors may be due to changes in particle size distribution, refractive index, density or 

other factors that the source operator cannot know or predict. Regardless of the cause, the PM 

CEMS is determined to be “out of control” beginning with the last test run of a failed RRA or 

RCA and is not returned to “in control” status which is defined as completion of the last test run 

for a successful RRA, RCA or new initial correlation after corrective action is completed. 
114

Regardless of the specifics, these audits require having very experienced source testers perform 

at expert competence levels conducting paired sampling runs to attempt to acquire the necessary 

precise emission measurements. After completing the field tests, additional time is required for 

transport of samples to the laboratory, desiccation of filters to constant weights, evaporation of 

acetone from PM rinsing of test equipment, calculation of results, and quality assurance. 

Reasonable time must be allowed for these activities and provisional monitoring data should be 

allowed during the interim with reasonable adjustments applied based on the circumstances. 

Method 19 includes no provisions for generating alternative data to replace missing data. It does 

include statistical procedures for use by the Administrator for determining compliance when less 

than the required data is obtained. Subparts Da and Db which specifies the use of SO2 and NOx 

CEMS to determine compliance with 30-day rolling averages for utility and industrial boilers 

respectively, requires a minimum of 18 hours per day of and 22 out of 30 days of valid data. In 

contrast to PM CEMS, SO2 and NOx CEMS are a fully mature technology which has achieved 

very high levels of data availability for many years under Part 60 and Part 75 regulations. 

Furthermore, SO2 and NOx CEMS are directly calibrated on a daily basis with high quality 

NIST traceable gas standards, rather than through occasional comparisons with manual test 

methods conducted near there measurement limits and using regression analysis to establish an 

empirical correlation. PM CEMS cannot acquire data complying with EPAs certification and QA 

requirements for all source operating hours in a 30-day rolling average basis. 

We recognize the limitations of the conventional PM CEMS and the problematic comparisons 

with manual reference methods and has undertaken the development of a “self-validating” 

Hybrid PM CEMS to address these problems in a constructive manner. 

Response: The specific language cited in the comment has been removed from the final rule as 

unnecessary given the limited reasons for monitor downtime in this rule, as opposed to the 

relatively low monitor availability allowed under subpart Da, which has comparable language to 

ensure enough data are collected to meet the specific availability requirement in that rule. 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 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. 

Commenter Name: Mark W. Kowlzan

Commenter Affiliation: Packaging Corp. of America
115

Document Control Number: EPA-HQ-OAR-2002-0058-2913.1

Comment Excerpt Number: 17

Comment: The Boiler MACT proposal requires the installation and use of particulate matter 

continuous emissions monitoring systems (PM CEMs) to assure continual compliance with the 

emission standard for boilers cornbusting coal, biomass or residual oil with a heat input capacity 

of 250 MMBtu/hr or greater. Under the rule proposal, five of our thirteen boilers will be required 

to install PM CEMs. NCASI indicates that they are not aware of any PM CEMs in operation in 

the pulp and paper industry. 

Our research identified six types of PM monitoring technologies; light scattering, beta 

attenuation, probe electrification, light extinction, optical scintillation and harmonic oscillation. 

The only technology that is not dependent upon particle characteristics is harmonic oscillation; 

however, that technology is designed for short-term use (e.g., less than a week). 

Light scattering and beta attenuation technologies both have longer use histories than the other 

technologies but have notable limitations. Both are dependent upon particle characteristics and 

light scattering cannot be employed for wet-scrubber-controlled sources. As our industry uses a 

wide variety of fuel types, we have serious reservations about the accuracy of data generated by 

PM CEMs systems that are dependent upon particle characteristics since variation in the types of 

fuels combusted will impact the deviceis). 

Response: We agree that not all technologies that can satisfy PS 11 will be suitable for all 

applications. We disagree that there are no PM CEMS technologies for monitoring emissions 

from multi-fuel and other industrial boilers, and PM CEMS have been demonstrated for a variety 

of applications. First, PM CEMS performance specifications and QA procedures have been 

around quite a while with PS-11 and Procedure 2 promulgated January 2004. There have been at 

least 65 successful installations in the United States and in other countries. A successful 

installation is obtained when a PM CEMS passes the PS-11 statistical criteria, thereby 

demonstrating that an acceptable level of accuracy is achieved. PS-11 provides the steps in 

obtaining a reliable successful correlation with reference methods, thereby ensuring compliance 

data that is sufficient to determine compliance with PM emission limits. Procedure 2 describes 

the required audits to insure that subsequent measurements are stable and within acceptable 

limits, thereby ensuring reliable compliance data.

Applying a technology suitable for a particular application would naturally take some planning. 

Section 2.4(1) of PS-11 states that you should select a PM CEMS that is appropriate for your 

source. EPA encourages you to discuss your specific operations with your vendor and obtain a 

guarantee from the vendor. EPA is aware of PM CEMS technologies that the measurement of 

mass concentration is not affected by changes in the particulate composition that may occur with 

multiple types of fuels and wastes. Manufacturers of beta gauge instruments have demonstrated 

that the calibration curve does not change as the fuel mix changes. Vendors have guaranteed that 

their PM CEMS will meet the PS-11 criteria for multi-fuel boilers. PS-11 provides for situations 

where multiple correlations may be needed for a PM CEMS technology (see Section 2.3 of PS11).
116

Section 2.4 of PS-11 stresses the importance of planning for subsequent changes in effluent 

matrix and/or PM that might influence the correlation and describes the process required to 

enhance the probability of obtaining a successful correlation and the selection of the most 

appropriate CEMS for the installation. 

Commenter Name: Mark W. Kowlzan

Commenter Affiliation: Packaging Corp. of America

Document Control Number: EPA-HQ-OAR-2002-0058-2913.1

Comment Excerpt Number: 18

Comment: The PM CEMs calibration protocol requires twenty-one l-hour runs at three PM 

emission levels: low, medium [i.e., near limit] and high [i.e., over limit]. Presuming that a fourhour stack test is required to collect sufficient PM to reach the practical quantitation limit, the 

one-hour calibration runs at low and medium emission rates are essentially useless. Further, the 

calibration protocol presumes that a source can readily and reliably "dial in" a low, medium or 

high PM emission rate at will. Finally, different calibration curves may need to be established as 

a function of various fuel blends. Collectively, the challenges associated with the use of PM 

CEMs in our industry leads us to question the reliability of the data the units generate, 

particularly at the extremely low PM limits proposed in the rule. 

Response: On the sensitivity issue, related to precision and accuracy, we disagree that 

measurements made near the emissions limits are indistinguishable from zero. Modern light 

scatter devices (e.g., the Durag D-R 300-40 at http://www.ppmsystems.fi/files/d-r-300-40.pdf

and the Sigrist StackGuard monitor at 

http://www.photometer.com/en/products/details/features.html?productid=249

) can detect very low concentrations including in the microgram/m3 range. These devices can 

also satisfy the relative accuracy requirements in PS11 at those levels (e.g., with longer PM test 

runs for reference method PM mass sampling).

On the accuracy issue, we understand and appreciate the effect of measurement uncertainty, 

including the effects of uncertainty inherent in the PM CEMS calibration output, in establishing 

the applicable limits and in determining compliance.. As discussed in responses to other 

comments about establishing the applicable emissions limits, we considered and accounted for 

these uncertainties in applying statistically based confidence factors (i.e., the UPL calculations) 

using the emissions data developed in support of the rule. Once those emissions limits are 

established, it is agency policy that determinations of compliance are to be based on 

measurements conducted with the prescribed procedures including meeting all of the control 

quality assurance and quality control requirements without further adjustment.
117

Commenter Name: Mark W. Kowlzan

Commenter Affiliation: Packaging Corp. of America

Document Control Number: EPA-HQ-OAR-2002-0058-2913.1

Comment Excerpt Number: 19

Comment: We believe that there are other valid indicators aside from PM CEMS, to determine 

if control equipment is operating properly. Examples include; power consumption by 

electrostatic precipitators, scrubber flow I differential pressure or opacity. These parameters are 

effective compliance indicators particularly since, under the rule, PM serves as a surrogate of 

HAP-metals. HAP-metals can lack high correlation with PM depending on the nuances 

associated with the source of PM emissions. By requiring the use of PM CEMs, the agency is, in 

effect, mandating the most problematic«surrogate of a surrogate" to verify compliance. 

Response: EPA disagrees. The rule establishes a specific PM emission limit and the PM CEMS 

is a direct compliance measure with that limit, and is not used to document only good operating 

practices for a control device. The CEMS is used in place of annual testing for large boilers. For 

smaller boilers, the rule requires direct emission testing plus control device parameter monitoring 

with operational limits to ensure continuous compliance. 

Commenter Name: Gary Melow

Commenter Affiliation: Michigan Biomass

Document Control Number: EPA-HQ-OAR-2002-0058-2776.1

Comment Excerpt Number: 20

Comment: We have traditionally monitored opacity continuously from our sources, and also 

have malfunction abatement plans and compliance assurance monitoring (CAM) requirements 

for particulate matter. The capital cost of PM CEM equipment, which EPA estimates at $88,000, 

plus annual operating cost of $33,000 is very high given the number of units affected. These 

costs are not justified given the existing 

monitoring requirements and the consistent operation of particulate removal devices. (For 

biomass units these are predominantly high efficiency ESPs). This cost is substantial and 

provides no reduction in emissions. 

Response: For the operations and facilities subject to the rule, we believe that the combination 

of periodic compliance emissions testing and continuous monitoring of operational and 

parametric control measure conditions is appropriate for assuring ongoing compliance for most 

units. For large boilers, we have required use of a PM CEMS. The costs and burdens of these 

requirements are included in the impact assessments conducted for this rule, and are part of 

compliance costs that EPA has found to be reasonable for the affected sources.

Commenter Name: Brad James
118

Commenter Affiliation: Trinity Consultants

Document Control Number: EPA-HQ-OAR-2002-0058-2853.1

Comment Excerpt Number: 24

Comment: EPA has established MACT floors for PM based on emissions testing data. This 

information is collected over a series of three, one-hour runs in accordance with EPA Method 5. 

These data do not account for variability in PM emissions during start-up, shutdown, swings in 

operation, as well as unit and/or control device malfunctions. U.S. Sugar feels it is inappropriate 

to demonstrate compliance with this MACT limit continuously with a CEMS. U.S. Sugar 

proposes that PM CEMS data from existing units be analyzed to establish MACT Floors for PM 

that account for variability and enable continuous compliance. It is incongruous to require PM 

CEMS to be added on to existing units for demonstrating compliance with a MACT Floor 

developed using one-time, short-term stack test data during normal operations. 

Response: See the preamble for revised treatment of SSM conditions. For the CEMS issue, see 

the response to EPA-HQ-OAR-2002-0058-3179, Comment Excerpt Number 7.

Commenter Name: Brad James

Commenter Affiliation: Trinity Consultants

Document Control Number: EPA-HQ-OAR-2002-0058-2853.1

Comment Excerpt Number: 25

Comment: U.S. Sugar reviewed the current air permits for facilities located in Florida utilizing 

biomass combustion units. These units (a majority include maximum heat input capacities of 

greater than 250 MMBtu/hr) utilized in different industries do not currently have PM CEMS 

requirements associated with SIP emission limits, Prevention of Significant Deterioration (PSD) 

permitting, or other applicable federal limitation [New Source Performance Standard (NSPS) or 

NESHAP]. Not one of these biomass combustion sources currently permitted in Florida is 

required to monitor PM continuously via CEMS. Instead, compliance testing is required to 

demonstrate compliance with PM emission limits or opacity is used as a surrogate for PM and a 

continuous opacity monitoring system (COMS) is required to demonstrate compliance with the 

surrogate opacity limit. 

U.S. Sugar believes that PM CEMS technology is not an applied technology for biomass boilers 

that has been “achieved” by the best performing 12% of similar sources, and specifically not for 

bagasse boilers. EPA should further investigate the ability of a PM CEMS to monitor emissions 

at the order of magnitude identified in this proposed rule without significant error and significant 

cost that has not already been demonstrated in practice for the industry. Use of PM CEMS has 

generally been limited to utility boilers which typically operate at a fairly stable load and with 

one primary source of fuel, typically coal. U.S. Sugar is concerned about the viability of 

operating such a monitor on a boiler that utilizes bagasse with varying moisture content (which 

effects combustion) as well as industry-specific load-swinging for the existing boilers. Due to 
119

these factors, U.S. Sugar requests further investigation by EPA prior to issuing a mandate for use 

of PM CEMS on such a wide-scale. 

U.S. Sugar requests that the EPA readdress the PM CEMS requirement specifically for existing 

biomass combustion sources. U.S. Sugar proposes that the EPA consider alternative compliance 

options for demonstrating compliance with the applicable PM emission limits for existing 

biomass combustion sources, such as utilizing established add-on monitoring technology 

(COMS) for these types of units or the compliance data used for establishing the MACT Floor 

(emissions testing). 

Response: See the response to EPA-HQ-OAR-2002-0058-2913.1, Comment Excerpt Number 

17.

Commenter Name: Steven G. Hanson

Commenter Affiliation: Graphic Packaging International

Document Control Number: EPA-HQ-OAR-2002-0058-2723.1

Comment Excerpt Number: 27

Comment: EPA has established MACT floors for PM based on emission test data. This 

information is collected over a series of three, one-hour runs. These data do not account for 

variability in PM emissions during start-up, shutdown and unit and/or control device 

malfunctions. Therefore, GPI — Macon Mill believes it is inappropriate to demonstrate 

compliance with this MACT limit continuously with a CEMS. GPI — Macon Mill proposes that 

PM CEMS data from existing units be analyzed to establish MACT floors that account for 

variability and enable continuous compliance. 

Response: See the response to EPA-HQ-OAR-2002-0058-3179, Comment Excerpt Number 7.

Commenter Name: Steven G. Hanson

Commenter Affiliation: Graphic Packaging International

Document Control Number: EPA-HQ-OAR-2002-0058-2723.1

Comment Excerpt Number: 28

Comment: GPI — Macon Mill believes that PM CEMS technology is a relatively new 

technology and EPA should further investigate the ability of a PM CEMS to monitor emissions 

at the order of magnitude proposed in this rule without a significant error. Use of PM CEMS has 

generally been limited to utility boilers which typically operate at a fairly stable load and with 

one primary source of fuel, typically coal. GPI — Macon Mill is concerned about the viability of 

operating such a monitor on a multi-fuel, load-swinging boiler; particularly boilers combusting 
120

biomass and encourages further investigation by EPA prior to issuing a mandate for their use on 

such a wide-scale. 

Response: See the response to EPA-HQ-OAR-2002-0058-2913.1, Comment Excerpt Number 

17.

Commenter Name: Steven G. Hanson

Commenter Affiliation: Graphic Packaging International

Document Control Number: EPA-HQ-OAR-2002-0058-2723.1

Comment Excerpt Number: 29

Comment: GPI — Macon Mill expresses concern regarding sufficient availability of PM CEM 

monitoring devices should EPA promulgate this requirement. One vendor GPI — Macon Mill 

typically contracts with has indicated that their PM CEM are still in the research and 

development phase and they are concerned about the ability to meet the proposed requirements. 

Beyond this one vendor, availability of PM CEM for wet stacks is known to be limited to only a 

feequipment vendors. It is unlikely that these few vendors would be able to handle the 

manufacturing and installation requirements for all the necessary wet-stack installations that 

would be required as a result of this proposed rule. 

Response: Currently, there are seven PM CEMS vendors that would be able to manufacture and 

install PM CEMS for wet or dry stack installations. Two of the larger companies would be able 

to manufacture and install the needed PM CEMS alone. Given the 3 year implementation 

schedule for this rule, we fully expect that vendors and sources will have time sufficient for 

contracting for, installing, and certifying the instruments prior to compliance dates. 

Commenter Name: David M. Kiser

Commenter Affiliation: International Paper Company

Document Control Number: EPA-HQ-OAR-2002-0058-2777.1

Comment Excerpt Number: 37

Comment: EPA should not require boilers and process heaters that burn coal, biomass or oil 

which have a heat input capacity greater or equal to 250 MMBTU/hr to install Particulate Matter 

(PM) Continuous Emission Monitors (CEMS) to assure compliance with PM emission limits. 

EPA should remove the requirement to install a PM CEMS and modify the proposed rule 

language to require opacity monitoring on units greater than 10 MMBtu per hour that do not use 

a wet scrubber. New units greater than 10 MMBtu per hour should be required to demonstrate 

continuous compliance by maintaining opacity levels to less than or equal to 10 percent (daily 

block average). Existing units greater than 10 MMBtu per hour should be required to 

demonstrate continuous compliance by maintaining opacity levels to less than or equal to 20 

percent (6-minute average) except for one 6-minute period per hour of not more than 27 percent. 
121

[NSPS Standard – 40 CFR 60, Subparts D, Db, Dc.] PM CEMS should not be required. Rather, 

Continuous Opacity Monitors (COMS) should be required as a surrogate for PM emissions. 

Opacity monitors provide qualitative information on the operation and maintenance of 

particulate control equipment and have been in use since Performance Specification 1 (PS-1) was 

promulgated back in 1975. 

EPA’s New Source Performance Standards (NSPS) and National Emission Standards for 

Hazardous Air Pollutants (NESHAP) require continuous monitoring of opacity from various 

source categories that impact our industry, specifically 40 CFR 60, Subparts D, Db, Dc; 40 CFR 

60, Subpart BB; and 40 CFR 63, Subpart MM. Opacity monitoring is also incorporated into State 

Implementation Plans, State regulations and Title V permits. Opacity monitoring has been well 

ingrained in many EPA and State regulations for a number of years and opacity has proven to be 

an effective indicator of compliance with a particulate standard. Opacity monitors have proven to 

be highly reliable, and easy to install and maintain, at an affordable cost. Opacity monitors are 

required to meet rigorous performance standards; in 2000, EPA amended PS-1 by incorporating 

ASTM D6216-98 design and monitor manufacturer performance specifications (65 FR 48914, 

August 10, 2000). 

PM CEMS are still a new technology and do not have the field test history of opacity monitors 

that go back over three decades. Installing and maintaining PM CEMS are quite complex and 

costly (with no environmental benefit). In EPA’s Final Report, Current Knowledge of Particulate 

Matter (PM) Continuous Emission Monitoring, [EPA-454/R-00039, September 8, 2000.] EPA 

estimated the total first costs (equipment, installation, initial testing correlation) [[A breakdown 

of PM CEMS cost are found in Appendix A of EPA’s Final Report, Current Knowledge of 

Particulate Matter (PM) Continuous Emission Monitoring, EPA-454/R-00-039, September 8, 

2000.] to range from $102,600 to $170,000. The cost to conduct a Response Correlation Audit 

(RCA) was estimated at $51,800 - $88,800 (if conducted annually) or $29,600 to $66,600 (if 

conducted every three years). Since these costs were developed, EPA believes the cost to be low 

“because of the potential need for more Reference Method particulate testing than originally 

anticipated. Additional test runs may be needed during the Correlation Test Planning Period in 

order to assess the proper measurement range for the PM CEMS”. [EPA-454/R-00039, 

September 8, 2000.] These costs also do not include the additional auditing requirements 

specified by Procedure 2 of 40 CFR 60, Appendix F, for PM CEMS, specifically, Sample 

Volume Audits (SVA) and Relative Response Audits (RRA). 

Based on just the cost and complexity of installing and maintaining a PM CEMS and the fact 

there is no environmental benefit to having a PM CEMS, EPA should remove the PM CEMS 

requirement. Opacity monitors are presently installed on our units to meet current Federal and 

State requirements. Opacity should continue to be an indicator of particulate emissions which has 

been the case for the past 35 years. 

Response: See the response to EPA-HQ-OAR-2002-0058-2913.1, Comment Excerpt Number 

17.

Commenter Name: Lee B. Zeugin
122

Commenter Affiliation: Utility Air Regulatory Group

Document Control Number: EPA-HQ-OAR-2002-0058-2880.1

Comment Excerpt Number: 52

Comment: EPA’s proposal to use PM CEMS is seriously flawed. First, EPA provides no PM 

CEMS data to support any of its proposed requirements or averaging times. In fact UARG 

doubts that there is any PM CEMS installed and operating on a single unit that is subject to this 

proposed rule. EPA also fails to provide any analysis to justify use of stack test data to set a 

proposed PM CEMS standard. While averaging time can be used to compensate for variability 

not seen in individual stack tests, that adjustment cannot be made by simply arbitrarily selecting 

a longer period (e.g., daily or monthly). Nor is that adjustment sufficient to compensate for the 

differences between the methods themselves (Method 5 and PM CEMS). 

Response: See the response to EPA-HQ-OAR-2002-0058-3179, Comment Excerpt Number 7. 

We also disagree that there are no PM CEMS technologies for monitoring emissions from 

industrial boilers, and PM CEMS have been demonstrated for a variety of applications. First, PM 

CEMS performance specifications and QA procedures have been around quite a while with PS11 and Procedure 2 promulgated January 2004. There have been at least 65 successful 

installations in the United States and in other countries. A successful installation is obtained 

when a PM CEMS passes the PS-11 statistical criteria, thereby demonstrating that an acceptable 

level of accuracy is achieved. PS-11 provides the steps in obtaining a reliable successful 

correlation with reference methods, thereby ensuring compliance data that is sufficient to 

determine compliance with PM emission limits. Procedure 2 describes the required audits to 

insure that subsequent measurements are stable and within acceptable limits, thereby ensuring 

reliable compliance data.

Commenter Name: Lee B. Zeugin

Commenter Affiliation: Utility Air Regulatory Group

Document Control Number: EPA-HQ-OAR-2002-0058-2880.1

Comment Excerpt Number: 54

Comment: EPA has failed to consider whether PM CEMS can be correlated under PS 11 at the 

levels of EPA’s proposed standards (or whether PM CEMS can even measure such low levels). 

Response: On the accuracy issue, we understand and appreciate the effect of measurement 

uncertainty, including the effects of uncertainty inherent in the PM CEMS calibration output, in 

establishing the applicable limits and in determining compliance.. As discussed in responses to 

other comments about establishing the applicable emissions limits, we considered and accounted 

for these uncertainties in applying statistically based confidence factors (i.e., the UPL 

calculations) using the emissions data developed in support of the rule. Once those emissions 

limits are established, it is agency policy that determinations of compliance are to be based on 
123

measurements conducted with the prescribed procedures including meeting all of the control 

quality assurance and quality control requirements without further adjustment. 

On the sensitivity issue, related to precision and accuracy, we disagree that measurements made 

near the emissions limits are indistinguishable from zero. Modern light scatter devices (e.g., the 

Durag D-R 300-40 at http://www.ppmsystems.fi/files/d-r-300-40.pdf and the Sigrist StackGuard 

monitor at

http://www.photometer.com/en/products/details/features.html?productid=249)

can detect very low concentrations including in the microgram/m3 range.

These devices can also satisfy the relative accuracy requirements in

PS11 at those levels (e.g., with longer PM test runs for reference method PM mass sampling).

Commenter Name: Lee B. Zeugin

Commenter Affiliation: Utility Air Regulatory Group

Document Control Number: EPA-HQ-OAR-2002-0058-2880.1

Comment Excerpt Number: 55

Comment: One of the primary challenges in developing PM CEMS standards is the nature of 

the technology itself, which differs significantly from the technology EPA used to establish the 

numerical portion of the PM emission limits. Unlike Method 5, PM CEMS do not provide a 

direct measure of mass PM. Instead, they provide an indirect measure by “correlating” the 

monitor’s response to short term stack tests (e.g., Method 5 tests) conducted over a range of 

concentrations that must be sufficient to include the level of the applicable emission standard. 

Even at the point of initial certification, however, a PM CEMS meeting the criteria in PS 11 can

produce responses that differ significantly (on the order of 25 percent) from what would be 

obtained with Method 5. Attachment B at 3-4.[ See also UARG Comments, EPA-HQ-OAR-HQOAR-2005-0031-0246, at 3-10.] An additional point of concern is the lack of information on the 

long term stability of the PS 11 correlations to Method 5 as conditions in the stack gas change 

over time. Unlike SO2 and NOx CEMS, which are challenged on a frequent basis with gases of a 

known concentration, there are no PM calibration gases. See, e.g., PS 11 § 2.2. As a result, PM 

CEMS responses are reevaluated at much less frequent intervals due to the burdens of Method 5 

testing (e.g., annually under proposed § 63.7540(a)(9)(iii)). And, unlike Method 5, PM CEMS 

sample at a single point, which may not be representative of concentrations across the stack of a 

stratified gas stream. 

Response: Applying a technology suitable for a particular application would naturally take some 

planning. Section 2.4(1) of PS-11 states that you should select a PM CEMS that is appropriate 

for your source. EPA encourages you to discuss your specific operations with your vendor and 

obtain a guarantee from the vendor. EPA is aware of PM CEMS technologies that the 

measurement of mass concentration is not affected by changes in the particulate composition that 

may occur with multiple types of fuels and wastes. Manufacturers of beta gauge instruments 

have demonstrated that the calibration curve does not change as the fuel mix changes. Vendors 

have guaranteed that their PM CEMS will meet the PS-11 criteria for multi-fuel boilers. PS-11 
124

provides for situations where multiple correlations may be needed for a PM CEMS technology 

(see Section 2.3 of PS-11).

Section 2.4 of PS-11 stresses the importance of planning for subsequent changes in effluent 

matrix and/or PM that might influence the correlation and describes the process required to 

enhance the probability of obtaining a successful correlation and the selection of the most 

appropriate CEMS for the installation.

Commenter Name: Lee B. Zeugin

Commenter Affiliation: Utility Air Regulatory Group

Document Control Number: EPA-HQ-OAR-2002-0058-2880.1

Comment Excerpt Number: 56

Comment: Some of the issues with PM CEMS technology might be addressed in the standard

setting process by setting limits based on PM CEMS data collected at sources representative of 

the range of units subject to the standard, and over a sufficient period of time to ensure that any 

lack of stability in the calibration is taken into account. As EPA previously concluded 

When a PM CEMS is used for compliance monitoring, the PM emission limit that is used as a 

compliance set point should be based on PM CEMS data collected from many representative 

sources over an extended period (e.g., at least 6 months). The 

accuracy limitations of a PM CEMS must also be considered when setting an emission limit. 

UARG Comments on Proposed Standards of Performance for Electric Steam Generating Units 

(Apr. 29, 2005), EPA-HQ-OAR-2005-0031-0129, at 43 (quoting EPA “Current Knowledge of 

Particulate Matter (PM) Continuous Emission Monitoring” (September 2000), A-2001-10-II-A2, 

at 7-2 (emphasis added). UARG has found no evidence that EPA has considered how the 

permissible PM CEMS measurement error might impact compliance determinations under this 

proposed rule. [See submittal for discussion of PM CEMS]. 

Response: See response to EPA-HQ-OAR-2002-0058-2880.1, Comment Except Number: 52.

Commenter Name: Traylor Champion

Commenter Affiliation: Georgia-Pacific LLC

Document Control Number: EPA-HQ-OAR-2002-0058-2745.1

Comment Excerpt Number: 57

Comment: PM CEMS and COMS 

In the proposed rule at 40 CFR 63.7525(b), EPA specifies that a particulate matter continuous 

emission monitoring system ( PM CEMS) must be installed on all coal, biomass and residual oil 

boilers and process heaters that are more than 250 MM Btu/hr. The Agency also requires in 40 

CFR 63.7525(c) that a continuous opacity monitoring system ( COMS) must be installed on all 

boilers and process heaters with an opacity requirement. Table 4 of Subpart DDDDD of Part 63 
125

requires that 10% opacity must be met by any unit using a dry electrostatic precipitator (ESP). 

Requiring these two monitors on units > 250 MM Btu/hr and using an ESP is redundant since 

they all measure the same pollutant – particulate matter - it makes no sense to require both 

monitors on the same unit. 

Response: We agree that a PM CEMS installed and operated in accordance with Performance 

Specification 11 and the associated quality assurance procedures can provide assurance of 

ongoing compliance without the need for additional continuous or periodic compliance testing. 

The final rule reflects this provision, applying only PM CEMS to large units.

Commenter Name: Lee B. Zeugin

Commenter Affiliation: Utility Air Regulatory Group

Document Control Number: EPA-HQ-OAR-2002-0058-2880.1

Comment Excerpt Number: 58

Comment: EPA also has failed to consider the ability of PM CEMS to meet the PS 11 criteria at 

the levels of EPA’s proposed standards, or even the ability of PM CEMS to measure at that level 

at all. For example, although a number of PM CEMS have been installed and operated at coalfired boilers in recent years, UARG is not aware of any instance in which a PM CEMS has been 

correlated at the level of EPA’s proposed standard for new coal-fired boilers (0.001 lb/mmBtu). 

A PM concentration equivalent to that standard -- 1 mg/m3 -- is indistinguishable from zero 

when measured by a PM CEMS. . [See submittal for discussion of PM CEMS]. This raises 

significant issues with respect to PS 11 correlation. PS 11 requires the owner/operator to attempt 

to obtain three different PM concentrations during correlation testing, and allows use of a zero 

point in place of one concentration if three cannot be achieved. Although PS 11 expresses these 

concentrations as a percent of the “maximum PM concentration,” without an explicit waiver 

from all applicable emission standards no owner/operator can test at a level above the applicable 

PM emission limit (or any other limit that might be exceeded during such testing if related 

controls, e.g., a wet SO2 scrubber, must be bypassed or turned off). UARG questions whether it 

is even conceivable to create, much less measure, two PM levels between zero and 1 mg/m3. 

And, EPA has provided no data or discussion to suggest that it is possible.[See submittal for 

discussion of PM CEMS]. 

Response: On the sensitivity issue, related to precision and accuracy, we disagree that 

measurements made near the emissions limits are indistinguishable from zero. Modern light 

scatter devices (e.g., the Durag D-R 300-40 at http://www.ppmsystems.fi/files/d-r-300-40.pdf 

and the Sigrist StackGuard monitor at

http://www.photometer.com/en/products/details/features.html?productid=249)

can detect very low concentrations including in the microgram/m3 range.

These devices can also satisfy the relative accuracy requirements in

PS11 at those levels (e.g., with longer PM test runs for reference method PM mass sampling).
126

See also the response to EPA-HQ-OAR-2002-0058-2913.1, Comment Excerpt Number 17.

Commenter Name: Traylor Champion

Commenter Affiliation: Georgia-Pacific LLC

Document Control Number: EPA-HQ-OAR-2002-0058-2745.1

Comment Excerpt Number: 58

Comment: PM CEMS, COMS and Bag Leak Detection Systems 

In the proposed rule at 40 CFR 63.7525(b), EPA specifies that a PM CEMS must be installed on 

all coal, biomass and residual oil boilers and process heaters that 

are more than 250 MM Btu/hr. The Agency also requires in section 2.a and 2.b of Table 4 to 

Subpart DDDDD of Part 63 that units using a fabric filter as a control install either a bag leak 

detection system or COMS. Again, it is redundant to require both a PM CEMS and COMS for 

large units. 

Response: We agree that a PM CEMS installed and operated in accordance with Performance 

Specification 11 and the associated quality assurance procedures can provide assurance of 

ongoing compliance without the need for additional continuous or periodic compliance testing. 

The final rule reflects this provision, applying only PM CEMS to large units.

Commenter Name: Lee B. Zeugin

Commenter Affiliation: Utility Air Regulatory Group

Document Control Number: EPA-HQ-OAR-2002-0058-2880.1

Comment Excerpt Number: 61

Comment: For PM CEMS, EPA does not define such periods as “deviations,” but instead 

proposes to require the source owner/operator to obtain data “by using other monitoring systems 

as approved by the Administrator or EPA Reference Method 19 of appendix A to 40 CFR part 

60” to provide data for all operating hours during which data are not obtained from the PM 

CEMS because of “breakdowns, repairs, calibration checks, and zero and span adjustments.” 

Proposed § 63.7525(b)(6). This proposal is even more unreasonable in that EPA has neither 

established that PM CEMS are capable of operating without missing any data -- they cannot --

nor provided any other method capable of providing continuous PM data during such periods. 

PM CEMS downtime will occur both frequently (in the case of calibration checks, and zero and 

span adjustments) and unexpectedly (in the case of breakdowns and repairs). EPA has identified 

no EPA-approved “system” that could provide data during such periods (and UARG is aware of 

none) and the cited reference method -- Method 19 -- “does not include any sample collection or 

analysis procedures” (it only provides data reduction procedures). Method 19, § 1.1. 

Although EPA has previously adopted a provision with some similar language, that provision 

was in the context of an “option” for PM CEMS (not a requirement) and it limited the need for 

data collection to those instances when data were not collected for a minimum of “90 percent 
127

(only 75 percent is required prior to January 1, 2010) of all operating hours” in the 30- day 

rolling average period. 40 C.F.R. § 60.48Da(p)(8). When UARG objected to the proposed 

requirement in Subpart Da, EPA provided the following response: EPA concluded that the data 

availability requirements are appropriate. While EPA encourages the optional use of PM CEMS, 

we are aware that no PM CEMS is presently being used for compliance purposes in the United 

States. EPA, therefore, encourages steam generating unit owners or operators who elect to apply 

PM CEMS to notify EPA as soon as data are collected so that EPA can evaluate the data and, if 

the data supports doing so, propose revisions to the data availability requirements.EPA 

“Summary of Public Comments on Reconsideration and Amendments Proposed February 9, 

2007 (72 FR 6320)” (Apr. 13, 2007), EPA-HQ-OAR-2005-0031-0260 at 13. 

In short, EPA acknowledged it lacked data to support even a 75 percent availability requirement, 

but asserted it did not need to because use of CEMS was optional. EPA also agreed to examine 

data when they became available. EPA has provided no data in this rulemaking to support the 

proposed requirement. If EPA wants to impose a minimum data availability requirement for PM 

CEMS that are required under this rule, EPA must examine available PM CEMS data and 

propose a data availability requirement that is achievable. EPA has never considered one 

hundred percent data availability to be reasonable or necessary under command and control 

programs like the NSPS and NESHAPS, and it should not do so here. [see submittal]. 

Response: See the response to EPA-HQ-OAR-2002-0058-2997.1, Comment Excerpt Number 9.

Commenter Name: Lee B. Zeugin

Commenter Affiliation: Utility Air Regulatory Group

Document Control Number: EPA-HQ-OAR-2002-0058-2880.1

Comment Excerpt Number: 101

Comment: EPA’s proposed IB MACT rule requires PM CEMS for compliance demonstration 

for units with heat input capacity greater than 250 x 106 Btu/hr that burn coal, biomass or 

residual oil.9 There are considerably more technical issues with using PM CEMS for compliance 

determinations than EPA apparently realizes. RMB reaches this conclusion based on its review 

of EPA’s response to comments in the recently released Portland Cement MACT rule. In that 

rulemaking, industry commenters raised a number of legitimate technical issues, which EPA 

summarily dismissed with a series of platitudes that were absent either technical support or test 

data. For example, in one response EPA states, in fact, PS-11 and Procedure 2 are working well. 

It would be helpful if EPA provided some "facts" to buttress this statement. 

Unlike conventional CEMS (SO2, NOx, CO2, etc.), PM CEMS do not measure mass directly. 

Rather, PM CEMS measure a parameter such as light scattering or beta attenuation which then 

must be correlated to PM concentration. Just by the very nature of the correlation process, there 

must be some allowable variation between the PM CEMS response and that which is accepted as 

the correct value (i.e., reference method measurement). In other words, the correlation line does 

not pass through all the data points meaning that there is deviation between the PM CEMS 

response and the corresponding reference method measurement. As explained below, the 

allowable deviation is controlled by the statistical criteria imbedded in the EPA performance 

specification. 
128

On January 12, 2004, EPA published in the Federal Register Performance Specification 11 (PS11), Specification and Test Procedures for Particulate Matter Continuous Emission Monitoring 

Systems at Stationary Sources[69 Fed. Reg. 1786 (January 12, 2004).] The principal component 

of PS-11 is the required correlation testing and subsequent correlation analysis. To comply with 

PS-11, the PM CEMS correlation must meet the following statistical criteria: 

* The correlation coefficient shall be 0.85. 

* The confidence interval (95%) half range at the median PM CEMS response value must be 

within 10% of the PM emission limit value. 

* The tolerance interval half range at the median PM CEMS response value must have 95% 

confidence that 75% of all possible values are within 25% of the PM emission limit value. 

As the third bullet item (tolerance interval) indicates, PS-11 allows considerable variation 

between the PM CEMS responses and the individual reference method test values. RMB finds no 

evidence in the rulemaking docket that EPA has considered how permissible PM CEMS 

measurement errors would impact compliance determinations. 

Response: On the accuracy issue, we understand and appreciate the effect of measurement 

uncertainty, including the effects of uncertainty inherent in the PM CEMS calibration output, in 

establishing the applicable limits and in determining compliance.. As discussed in responses to 

other comments about establishing the applicable emissions limits, we considered and accounted 

for these uncertainties in applying statistically based confidence factors (i.e., the UPL 

calculations) using the emissions data developed in support of the rule. Once those emissions 

limits are established, it is agency policy that determinations of compliance are to be based on 

measurements conducted with the prescribed procedures including meeting all of the control 

quality assurance and quality control requirements without further adjustment.

Commenter Name: Lee B. Zeugin

Commenter Affiliation: Utility Air Regulatory Group

Document Control Number: EPA-HQ-OAR-2002-0058-2880.1

Comment Excerpt Number: 102

Comment: PM CEMS MONITORING ISSUES 

EPA’s proposed IB MACT rule requires PM CEMS for compliance demonstration for units with 

heat input capacity greater than 250 x 106 Btu/hr that burn coal, biomass or residual oil.9 There 

are considerably more technical issues with using PM CEMS for compliance determinations than 

EPA apparently realizes. RMB reaches this conclusion based on its review of EPA’s response to 

comments in the recently released Portland Cement MACT rule. In that rulemaking, industry 

commenters raised a number of legitimate technical issues, which EPA summarily dismissed 

with a series of platitudes that were absent either technical support or test data. For example, in 

one response EPA states, in fact, PS-11 and Procedure 2 are working well. It would be helpful if 

EPA provided some "facts" to buttress this statement. 
129

Unlike conventional CEMS (SO2, NOx, CO2, etc.), PM CEMS do not measure mass directly. 

Rather, PM CEMS measure a parameter such as light scattering or beta attenuation which then 

must be correlated to PM concentration. Just by the very nature of the correlation process, there 

must be some allowable variation between the PM CEMS response and that which is accepted as 

the correct value (i.e., reference method measurement). In other words, the correlation line does 

not pass through all the data points meaning that there is deviation between the PM CEMS 

response and the corresponding reference method measurement. As explained below, the 

allowable deviation is controlled by the statistical criteria imbedded in the EPA performance 

specification. 

On January 12, 2004, EPA published in the Federal Register Performance Specification 11 (PS11), Specification and Test Procedures for Particulate Matter Continuous Emission Monitoring 

Systems at Stationary Sources.1° The principal component of PS-11 is the required correlation 

testing and subsequent correlation analysis. To comply with PS-11, the PM CEMS correlation 

must meet the following statistical criteria: The correlation coefficient shall be 0.85;The 

confidence interval (95%) half range at the median PM CEMS response value must be within 

10% of the PM emission limit value. 

The tolerance interval half range at the median PM CEMS response value must have 95% 

confidence that 75% of all possible values are within 25% of the PM emission limit value. 

As the third bullet item (tolerance interval) indicates, PS-11 allows considerable variation 

between the PM CEMS responses and the individual reference method test values. RMB finds no 

evidence in the rulemaking docket that EPA has considered how permissible PM CEMS 

measurement errors would impact compliance determinations. 

Response: Continuation of Document Control Number: EPA-HQ-OAR-2002-0058-2880.1

Comment Excerpt Number: 101, See response to that comment.

Commenter Name: Lee B. Zeugin

Commenter Affiliation: Utility Air Regulatory Group

Document Control Number: EPA-HQ-OAR-2002-0058-2880.1

Comment Excerpt Number: 103

Comment: An important PM CEMS technical issue the Agency appears to have overlooked is 

an assessment of the lowest PM concentration that a PM CEMS can reasonably be expected to 

resolve. PS-11 directs the owner/operator to correlate the PM CEMS to conditions consistent 

with those at which the PM CEMS operates. For example, PS-11 states, if your PM CEMS 

extracts and heats the sample gas to eliminate water droplets, then measures and reports PM 

emissions under those actual conditions, you must convert your reference method results to those 

same conditions (e.g., mg/acm at 160C).[ 40 C.F.R. Part 60, Appendix B, Performance 

Specification 11, section 8.6(1)(iii).] 

EPA’s proposed PM emission limit for new coal-fired boilers is 0.001 lb/10exp6 Btu. EPA’s 

proposed emission limit, in units of PM concentration, is on the order of 1 mg/m3. In RMB’s 
130

considerable experience with PM CEMS installations, we have never observed a PM CEMS that 

could measure a concentration this low. A PM concentration of 1 mg/m3 is indistinguishable 

from zero, or for that matter, 2 mg/m3 with a PM CEMS. 

PS-11 requires the owner/operator to attempt to obtain three different PM concentrations at 

which to conduct the correlation testing.[ 40 C.F.R. Part 60, Appendix B, Performance 

Specification 11, section 8.6(4).] 

Level 1: from zero to 50 percent of the maximum PM concentration; 

Level 2: 25 to 75 percent of the maximum PM concentration; and 

Level 3: 50 to 100 percent of the maximum PM concentration. 

PS-11 is silent with respect to defining "maximum PM concentration," but it is safe to assume 

that no responsible owner/operator is going to deliberately exceed the allowable PM limit Thus, 

for discussing new coal-fired units, 1 mg/m3 would be the maximum PM concentration. There is 

absolutely no conceivable way to create, much less to measure, two PM levels between zero and 

1 mg/m3. There is a second option if you cannot obtain the three distinct PM concentration 

levels. PS-11 allows you to test over "the maximum range of PM concentrations that is practical" 

and to add zero point data through either of several optional approaches.[ 13 40 C.F.R. Part 60, 

Appendix B, Performance Specification 11, section 8.6(5)]. As stated above, there simply is no 

range between zero and 1 mg/m3. It is virtually impossible for a PM CEMS to comply with PS11 when the PM emission limit is 0.001 lb/10exp6 Btu. 

Response: We disagree with the commenter.

On the sensitivity issue, related to precision and accuracy, we disagree that measurements made 

near the emissions limits are indistinguishable from zero. Modern light scatter devices (e.g., the 

Durag D-R 300-40 at http://www.ppmsystems.fi/files/d-r-300-40.pdf and the Sigrist StackGuard 

monitor at

http://www.photometer.com/en/products/details/features.html?productid=249)

can detect very low concentrations including in the microgram/m3 range.

These devices can also satisfy the relative accuracy requirements in

PS11 at those levels (e.g., with longer PM test runs for reference method PM mass sampling).

On the accuracy issue, we understand and appreciate the effect of measurement uncertainty, 

including the effects of uncertainty inherent in the PM CEMS calibration output, in establishing 

the applicable limits and in determining compliance.. As discussed in responses to other 

comments about establishing the applicable emissions limits, we considered and accounted for 

these uncertainties in applying statistically based confidence factors (i.e., the UPL calculations) 

using the emissions data developed in support of the rule. Once those emissions limits are 

established, it is agency policy that determinations of compliance are to be based on 

measurements conducted with the prescribed procedures including meeting all of the control 

quality assurance and quality control requirements without further adjustment.

Commenter Name: Lee B. Zeugin

Commenter Affiliation: Utility Air Regulatory Group

Document Control Number: EPA-HQ-OAR-2002-0058-2880.1

Comment Excerpt Number: 104
131

Comment: Proposed section 63.7525(b)(6) states, when PM emissions data are not obtained 

because of CEMS breakdown, . . . emission data shall be obtained by using other monitoring 

methods as approved by the Administrator . . . to provide, as necessary, valid emission data for 

all operating hours per 30-day rolling average [emphasis added]. It is unprecedented to require 

emission data to be collected for all operating hours to demonstrate compliance with a numerical 

emission limit Granted, cap-and-trade programs, which are based on mass emissions, require 

accounting for each operating hour. However, programs such as EPA’s Acid Rain Program 

contain procedures for filling in missing CEMS data (i.e., missing data substitution algorithms) 

and do not mandate alternative or back-up data. collection methods. Also note that a 30-day 

rolling average is referenceD in this section, which is inconsistent with proposed §63.7525(b)(3), 

as discussed above. 

Response: See the response to EPA-HQ-OAR-2002-0058-2997.1, Comment Excerpt Number 9.

Commenter Name: Jim Griffin

Commenter Affiliation: American Chemistry Council

Document Control Number: EPA-HQ-OAR-2002-0058-2792.1

Comment Excerpt Number: 169

Comment: PM CEMS Should not be Required for All Boilers >250 MMBtu/hr. EPA’s 

requirement that PM CEMS should be used to demonstrate continuous compliance on all solid 

fuel boilers larger than 250 MMBtu/hr is not justified and not supported by any data. There is no 

published information documenting that PM CEMS installed on multi-fuel boilers can measure 

PM emissions accurately and demonstrate compliance with PS 11. 

In the preamble to the proposed rule, EPA asked for comments on its determination that PM 

CEMS should be required and used for determining compliance with the emission standards on 

boilers which burn coal, biomass, or oil and have a heat input capacity greater than or equal to 

250 MMBtu/hr. [75 Fed. Reg. at 32033.] The installed PM CEMS would be required to meet 

Performance Specification 11 and also comply with Procedure 2 in Appendix F to 40 CFR 60. 

In order for a CEMS to be suitable for demonstrating compliance, a CEMS must be accurate and 

precise under all operating conditions, and must have demonstrated the capability of sustained 

operations for long periods of time. However, as discussed below, these needs are not met when 

considering installation of PM CEMS on solid fuel boilers. 

EPA has failed to provide any technical information regarding the suitability of PM CEMS as 

compliance monitors. Instead, in the proposal EPA has stated that PM CEMS are used at a 

variety of sources in Europe and several electric utilities either have or are planning to install PM 

CEMS. Such general information does not establish the performance capabilities of PM CEMS 

and does not justify their use as compliance monitors for all industrial boilers over 250 

MMBtu/hr. 
132

Response: See the response to EPA-HQ-OAR-2002-0058-2913.1, Comment Excerpt Number 

17.

Commenter Name: Jim Griffin

Commenter Affiliation: American Chemistry Council

Document Control Number: EPA-HQ-OAR-2002-0058-2792.1

Comment Excerpt Number: 170

Comment: An examination of their history shows that EPA promulgated PS 11 and Procedure 2 

based on very limited data. When EPA initially proposed PS 11, it was based on EPA’s view of 

what the capabilities of PM CEMS should be. However, the very few PM CEMS installed on 

electric utility industry boilers could not meet the proposed requirements. Consequently, PS 11 

was extensively modified based upon utility industry data. At the time of the promulgation of PS 

11, no information was provided by EPA regarding the capability of PM CEMS to satisfy PS 11 

on sources other than coal-fired electric utility boilers nor was an opportunity provided to the 

industry to comment on the suitability of implementing PS 11 and Procedure 2 on specific source 

types. 

There are several significant issues with installing PM CEMS on multi-fuel boilers and biomass 

boilers that need to be addressed before installation of such systems: 

Among the instruments used to quantify PM emissions are light scattering, optical scintillation, 

electrostatic induction, and beta gauge instruments. The responses of these instruments are 

expected to be affected by the size and nature of particles being emitted. Thus the calibration 

curve for such instruments would be expected to change as the fuel mix changes. Multi-fuel 

boilers co-fire a wide variety of fuels, including coal, wood (bark), tire-derived fuel, pulping 

process residuals, waste treatment residuals, oil and natural gas. Each of these fuels may be fired 

at different levels during an operating day depending upon process conditions and availability. 

EPA has not published the results of any study examining these issues and thus is not in a 

position to confirm that given the changing nature of PM emissions from multi-fuel boilers, PM 

CEMS will accurately measure source PM emissions. 

Similarly, even "biomass boilers" may burn different types of biomass. EPA has not published 

the results of any study examining biomass boilers and thus is not in a position to confirm that 

given the changing nature of PM emissions from these units, PM CEMS will accurately measure 

source PM emissions. Although EPA has mentioned installation at utility industry boilers, it has 

not provided reference to any peer-reviewed publication documenting that PM CEMS are 

routinely capable of meeting the requirements of PS 11 and PS2 and measure PM emissions 

accurately. 
133

Response: Continuation of Document Control Number: EPA-HQ-OAR-2002-0058-2792.1, 

Comment Excerpt Number: 169. See that response. 

Commenter Name: Jim Griffin

Commenter Affiliation: American Chemistry Council

Document Control Number: EPA-HQ-OAR-2002-0058-2792.1

Comment Excerpt Number: 171

Comment: PS 11 specifies in Section 8.6 (4) (i) that simultaneous CM CEMS and reference 

method tests must be performed to obtain three levels of PM mass concentrations. Section 8.6 (4) 

(ii) specifies that the three PM concentrations must be distributed over the complete operating 

range experienced by the source. Thus, if a source experiences high PM emissions for short 

periods of time due to process upsets or malfunctions, the facility would have to conduct the 

correlation tests at emission levels that exceed the emission standards. This raises the following 

issues: 

Does EPA have the legal authority to require a source to operate above its permit limit? 

EPA has assumed that PM emissions from a source are like "dial a PM" and can be controlled 

within a narrow range through minor operating changes. Such changes in PM emissions are, 

however, not always easily accomplished. For example, the efficiency of a wet scrubber is 

affected by the particle size distribution, gas flow rate, pressure drop, and scrubbing solution 

flow rate. Thus a facility cannot just dial a PM emission rate and continue their PS 11 test. 

Similarly, it is not clear how a facility equipped with a bag house will achieve targeted PM 

emission rates to satisfy the requirements of PS 11, other than purposefully creating a hole in one 

or more of its bags (certainly not a desirable action). 

Some states ban facilities from operating their control devices below their maximum capability. 

What mechanism has EPA set up to allow facilities to operate in violation of state permit 

conditions? 

EPA has failed to document that PM CEMS are sufficiently precise and accurate to determine 

compliance with the applicable standards. PM CEMS are required to meet the requirements of 

PS 11. PS 11 specifications include a correlation coefficient of ?0.85 between measured and 

predicted stack gas PM concentrations. A confidence interval (95%) mid range value at the mean 

PM CEMS response of ±10% of the emission limit, and a tolerance interval mid range 95% 

confidence interval value such that 75% of all possible values are within 25% of the PM 

emission limit. This suggests a very high probability that many CEMS PM measurements that 

exceed the standard would actually be below the emission standard. In this situation, operators 

would be forced to make changes to a control device or even shut down the boiler if these 

changes did not cause a response, even though PM emissions were in compliance with the 

standard! This is in direct conflict with the current view of compliance as being either in 

compliance or out of compliance. If it is EPA’s desire to use PM CEMS for demonstrating 
134

compliance, it must show how compliance would be determined with devices with such a high 

error band. 

Response: For the process upsets issue raised by the commenter, process upsets are not part of 

"normal operations" as per PS-11, therefore the facility would not have try to capture that 

emission level for the correlation testing. Achieving a range of emission levels for units with 

wet scrubbers or fabric filters is a challenge, but many sources have been able to achieve the 

requirements of PS-11 by either perturbing these devices and/or by using the "zero point" that is 

given in section 8.6.

On the sensitivity issue, related to precision and accuracy, we disagree that measurements made 

near the emissions limits are indistinguishable from zero. Modern light scatter devices (e.g., the 

Durag D-R 300-40 at http://www.ppmsystems.fi/files/d-r-300-40.pdf and the Sigrist StackGuard 

monitor at

http://www.photometer.com/en/products/details/features.html?productid=249) can detect very 

low concentrations including in the microgram/m3 range. These devices can also satisfy the 

relative accuracy requirements in PS11 at those levels (e.g., with longer PM test runs for 

reference method PM mass sampling).

On the accuracy issue, we understand and appreciate the effect of measurement uncertainty, 

including the effects of uncertainty inherent in the PM CEMS calibration output, in establishing 

the applicable limits and in determining compliance.. As discussed in responses to other 

comments about establishing the applicable emissions limits, we considered and accounted for 

these uncertainties in applying statistically based confidence factors (i.e., the UPL calculations) 

using the emissions data developed in support of the rule. Once those emissions limits are 

established, it is agency policy that determinations of compliance are to be based on 

measurements conducted with the prescribed procedures including meeting all of the control 

quality assurance and quality control requirements without further adjustment.

Commenter Name: Richard L. Killion

Commenter Affiliation: Babcock and Wilcox Power Generation Group

Document Control Number: EPA-HQ-OAR-2002-0058-2722.1

Comment Excerpt Number: 3

Comment: B&W, also a very large supplier of continuous emissions monitoring systems and 

software (CEMS), is concerned that available CEMS equipment is not accurate enough in 

commercial field application to reliably report PM at the proposed MACT emissions limit on 

new Coal. 

Response: See the response to EPA-HQ-OAR-2002-0058-2913.1, Comment Excerpt Number 

17.
135

Commenter Name: Robert Ellerhorst

Commenter Affiliation: Michigan State University

Document Control Number: EPA-HQ-OAR-2002-0058-2816.1

Comment Excerpt Number: 1

Comment: MSU operates three dry bottom wall-fired bituminous coal-fred boilers and one 

circulating fluidized bed (CFB) bituminous coal-fired boiler each with a heat input greater than 

250 MMBtu/hr. Each boiler contains a fabric filter baghouse to control PM emissions, except for 

one of the pulverized coal boilers which contain an electrostatic precipitator (ESP). All four 

boilers contain a continuous opacity monitor (COM). MSU also has the capability to burn natural 

gas and up to 10 percent on a heat input basis of varying biofuels in the CFB boiler and is 

currently pursuing some addition of biofuel in the three pulverized coal (PC) units. 

For units using a fabric filter baghouse, MSU believes that compliance with the proposed PM 

emission limits can be obtained in the same way as for boilers smaller than 250 MMBtu/hr, 

which is through stack testing and the use of a bag leak detection system. Bag leak detection is a 

direct and continuous indicator of baghouse performance to ensure that the control system is 

achieving the optimal collection efficiencies (typically around 99.9 percent for particles down to 

10 microns in size.) 

Although a PM CEMS will obtain output PM concentrations, it does not measure mass 

particulate emissions directly. For example, light-scattering PM CEMS measure the ability of a 

flue gas to transmit light whereas n—attenuation devices measure the transmission of electrons 

through particulate that is collected on a filter. Mathematical correlation methods are then used 

to associate this data with actual particulate mass concentrations determined using manual test 

methods. These correlations must be made on a unit-by-unit basis and varied over different 

operating conditions. Adjustments in fuel or process rates, which can result in changes in the 

particle size distribution or characteristics, can significantly affect the correlation. To have valid 

correlation with the PM CEMS data a source must account for a wide range of fuel and process 

variability. Establishing an appropriate correlation becomes more difficult for sources that use 

multiple solid fuels (different coal ranks, biomass, and natural gas) where the fuel mix can 

change at any time. These factors must be considered as part of the annual operating expense of 

the monitoring devise. Due to the fuel variability and continuously changing mixes of the fuels 

for each of our units, we anticipate annual costs to be much higher than the $33,000 per unit per 

year indicated by EPA. 

A PM CEMS is used to calculate PM concentrations using a correlation of boiler operating data 

with PM concentrations obtained through manual stack testing. As such, it is more of a 

measurement of boiler performance than direct PM emissions. Bag leak detection can also 

continuously measure performance of the baghouse and ensure that the baghouse control is 

achieving the maximum filterable particulate removal efficiency and operating at its optimal 

design. As such, MSU believes that baghouse leak detection and continuously monitoring the 

pressure drop across the baghouse is sufficient for demonstrating compliance with PM limits for 

boilers of all sizes. For units using ESP control, MSU further believes that current practices of 
136

continuously monitoring boiler opacity, as well as the spark rate, amperage, and voltage of each 

of the four ESP fields, are also sufficient for demonstrating compliance with PM limits. 

Response: See the response to EPA-HQ_OAR-2002-0058-2875.1, Comment Excerpt Number 8.

Commenter Name: Robin Mills Ridgway

Commenter Affiliation: Purdue University

Document Control Number: EPA-HQ-OAR-2002-0058-2782.1

Comment Excerpt Number: 9

Comment: Particulate matter CEMS are an unnecessarily expensive continuous compliance 

method for particulate matter emissions 

Purdue University’s three coal fired boilers are all rated for greater than 250 MMBTU/hr heat 

input. EPA proposes that particulate matter CEMS be installed on each of these units to satisfy 

continuous compliance requirements for particulate matter emissions (§63.7525(b)). Purdue 

estimates that the cost for installation of PM CEMS for these three units will be in excess of 

$500,000 with an annual certification expense for the PM CEMS alone of greater than $100,000. 

Further, EPA guidance on presumptively acceptable compliance assurance monitoring for coalfired boilers does not specify a PM CEMS. See Proposed Compliance Assurance Monitoring 

(CAM) Protocol For An Electrostatic Precipitator (ESP) Controlling Particulate Matter (PM) 

Emissions From A Coal-Fired Boiler, at 14, April 2003 (available at: 

http://www.epa.gov/ttn/emc/cam/espcam.pdf). 

Method 5 stack testing is performed at the rated capacity of the boiler. At this rated capacity, all 

systems for particulate control are maximized as well (e.g., the air/cloth ratio in the baghouse, 

the ID fan output, ductwork losses, etc.). Hence, for particulate matter, stack testing conditions 

are the worst case operating conditions. At lower loads, the basic design parameters for the 

particulate collection system and for the combustion air management are not as taxed so it would 

be reasonable to expect that at lower loads, particulate emissions on a lb/MMBTU basis would 

be lower than the stack test. If all systems that were operating during the stack test continue to 

operate properly during normal operation, continuous compliance with the stack test can be 

determined due to the nature of particulate matter emissions behavior. Purdue already operates 

and maintains PS1 certified opacity monitors on all three units as well as monitoring baghouse 

pressure drop. 

As an alternative to the extremely expensive particulate matter CEMS installation EPA proposes, 

Purdue asks that EPA allow the installation and operation of bag leak detection systems in 

accordance with the proposed rule’s §63.7525(j)(1) through (8) in addition to the existing opacity 

monitors and pressure drop monitoring. The bag leak detection system provides ongoing 

monitoring of the bag house component performance and provides for continuous compliance 

demonstration. 

Response: See the response to EPA-HQ-OAR-2002-0058-2875.1, Comment Excerpt Number 8.
137

Commenter Name: Tim Keneally

Commenter Affiliation: KapStone Paper and Packaging Corporation

Document Control Number: EPA-HQ-OAR-2002-0058-2673.1

Comment Excerpt Number: 12

Comment: EPA’s requirement that PM CEMS should be used to demonstrate continuous 

compliance on all solid fuel boilers larger than 250 MMBtu/hr is arbitrary and not supported by 

any data. In the proposal EPA has stated that PM CEMS are used at a variety of sources in 

Europe and several electric utilities either have or are planning to install PM CEMS. Such 

general information does not establish the performance capabilities of PM CEMS and does not 

justify their use as compliance monitors for all industrial boilers over 250 MMBtu/hr. There are 

several significant issues with installing PM CEMS on multi-fuel boilers and biomass boilers 

commonly used in the forest products industry that need to be addressed before installation of 

such systems. 

Response: EPA disagrees that the requirement is arbitrary. See generally the response to EPAHQ-OAR-2002-0058-2913.1, Comment Excerpt Number 17.

Commenter Name: Michael Palazzolo

Commenter Affiliation: Alcoa Inc

Document Control Number: EPA-HQ-OAR-2002-0058-2967.1

Comment Excerpt Number: 14

Comment: The proposed provision requiring the use of "other monitoring systems" for PM 

CEMS out of control periods is not workable . 

The proposed provision in §63.7525(b)(6) requiring the use of "other monitoring systems as 

approved by the Administrator or EPA Reference Method 19" is also not workable. Adoption of 

either a percentage minimum data availability or a data substitution procedure patterned after 

Part 75 would remove the uncertainty associated with having to obtain an alternate monitoring 

system approval from the Administrator. In addition, EPA Method 19 does not provide for PM

measurement (and Method 9 measures opacity, not PM, if this was a typographical error). 

Response: See the response to EPA-HQ-OAR-2002-0058-2997.1, Comment Excerpt Number 9.

In the final rule, 63.7525(b)(6) and the reference to Method 19 has been removed.

Commenter Name: Jack Carter

Commenter Affiliation: Weyerhaeuser Company

Document Control Number: EPA-HQ-OAR-2002-0058-2797.1

Comment Excerpt Number: 24
138

Comment: We also are concerned about the proposed requirement to install and use PM CEMS. 

Quality of biomass fuels can change from day to day and even hour to hour, depending on 

market source and availability. Mills often burn a mixture of fuels (green versus dry, top of the 

pile versus bottom of the pile, hardwood residuals versus softwood residuals, bark versus wood, 

etc.), and most often the fuels are not blended. In some cases, biomass is co-fired with fossil 

fuels. The proposed rule would require CEMS for particulate matter for biomass boilers with a 

heat input capacity of 250 MMBtu per hour or more. However, the reliability of particulate 

matter CEMS under constantly changing fuel conditions has not been demonstrated, thus EPA’s 

proposed requirement is unreasonable. 

Response: See the response to EPA-HQ-OAR-2002-0058-2913.1, Comment Excerpt Number 

17.

Commenter Name: Timothy Hunt

Commenter Affiliation: American Forest and Paper Association (AF&PA)

Document Control Number: EPA-HQ-OAR-2002-0058-3213.1

Comment Excerpt Number: 285

Comment: EPA’s requirement that PM CEMS should be used to demonstrate continuous 

compliance on all solid fuel boilers larger than 250 MMBtu/hr is arbitrary and not supported by 

any data. There is no published information documenting that PM CEMS installed on multi-fuel 

boilers can measure PM emissions accurately and demonstrate compliance with PS 11. 

In order for a CEM to be suitable for demonstrating compliance, a CEM must be accurate and 

precise under all operating conditions, and must have demonstrated the capability of sustained 

operations for long periods of time. 

However, as discussed below, these needs are not met when considering installation of PM 

CEMS on solid fuel boilers. 

EPA has failed to provide any technical information regarding the suitability of PM CEMS as 

compliance monitors. Instead, in the proposal EPA has stated that PM CEMS are used at a 

variety of sources in Europe and several electric utilities either have or are planning to install PM 

CEMS. Such general information does not establish the performance capabilities of PM CEMS 

and does not justify their use as compliance monitors for all industrial boilers over 250 

MMBtu/hr. 

An examination of the history of PS 11 and Procedure 2 shows that EPA promulgated PS 11 and 

Procedure 2 based on very limited data. When EPA initially proposed PS 11, it was based on 

EPA’s view of what the capabilities of PM CEMS should be. However, the very few PM CEMS 

installed on electric utility industry boilers could not meet the proposed requirements. 

Consequently, PS 11 was extensively modified based upon utility industry data. At the time of 

the promulgation of PS 11, no information was provided by EPA regarding the capability of PM 

CEMS to satisfy PS 11 on sources other than coal-fired electric utility boilers nor was an 

opportunity provided to the industry to comment on the suitability of implementing PS 11 and 

Procedure 2 on specific source types. 
139

Response: See the response to EPA-HQ-OAR-2002-0058-2913.1, Comment Excerpt Number 

17.

Commenter Name: Timothy Hunt

Commenter Affiliation: American Forest and Paper Association (AF&PA)

Document Control Number: EPA-HQ-OAR-2002-0058-3213.1

Comment Excerpt Number: 286

Comment: There are several significant issues with installing PM CEMS on multi-fuel boilers 

and biomass boilers commonly used in the forest products industry that need to be addressed 

before installation of such systems: 

* Among the instruments used to quantify PM emissions are light scattering, optical scintillation, 

electrostatic induction, and beta gauge instruments. The responses of these instruments are 

expected to be affected by the size and nature of particles being emitted. Thus the calibration 

curve for such instruments would be expected to change as the fuel mix changes. Multi-fuel 

boiler, such as those used at pulp and paper mills co-fire a wide variety of fuels, including coal, 

wood (bark), tire-derived fuel, pulping process residuals, waste treatment residuals, oil and 

natural gas. Each of these fuels may be fired at different levels during an operating day 

depending upon process conditions and availability. EPA has not published the results of any 

study examining these issues and thus is not in a position to confirm that given the changing 

nature of PM emissions from multi-fuel boilers, PM CEMS will accurately measure source PM 

emissions. 

* Similarly, even “biomass boilers” may burn different types of biomass. For example, boilers at 

plywood plants burn bark removed from the logs before they are processed into veneer and also 

burn trim and scrap from the finished veneer. Again, EPA has not published the results of any 

study examining biomass boilers and thus is not in a position to confirm that given the changing 

nature of PM emissions from these units, PM CEMS will accurately measure source PM 

emissions. 

* Although EPA has mentioned installation at utility industry boilers, it has not provided 

reference to any peer-reviewed publication documenting that PM CEMS are routinely capable of 

meeting the requirements of PS 11 and PS2 and measure PM emissions accurately. 

Response: Continuation of EPA-HQ-OAR-2002-0058-3213.1, Comment Excerpt Number: 285. 

See that response.

Commenter Name: Timothy Hunt

Commenter Affiliation: American Forest and Paper Association (AF&PA)

Document Control Number: EPA-HQ-OAR-2002-0058-3213.1

Comment Excerpt Number: 287
140

Comment: PS 11 specifies in Section 8.6 (4) (i) that simultaneous CM CEMS and reference 

method tests must be performed to obtain three levels of PM mass concentrations. Section 8.6 (4) 

(ii) specifies that the three PM concentrations must be distributed over the complete operating 

range experienced by the source. Thus, if a source experiences high PM emissions for short 

periods of time due to process upsets or malfunctions, the facility would have to conduct the 

correlation tests at emission levels that exceed the emission standards. This raises the following 

issues: 

* Does EPA have the legal authority to require a source to operate above its permit limit? 

* EPA has assumed that PM emissions from a source are like “dial a PM” and can be controlled 

within a narrow range through minor operating changes. Such changes in PM emissions are, 

however, not always easily accomplished. For example, the efficiency of a wet scrubber is 

affected by the particle size distribution, gas flow rate, pressure drop, and scrubbing solution 

flow rate. Thus a facility cannot just dial a PM emission rate and continue their PS 11 test. 

Similarly, it is not clear how a facility equipped with a bag house will achieve targeted PM 

emission rates to satisfy the requirements of PS 11, other than purposefully creating a hole in one 

or more of its bags (certainly not a desirable action). 

Some states ban facilities from operating their control devices below their maximum capability. 

What mechanism has EPA set up to allow facilities to operate in violation of state permit 

conditions? 

Response: Process upsets are not part of "normal operations" as per PS-11, therefore the 

facility would not have try to capture that emission level for the correlation testing. 

Achieving a range of emission levels for units with wet scrubbers or fabric filters is a challenge, 

but many sources have been able to achieve the requirements of PS-11 by either perturbing these 

devices and/or by using the "zero point" that is given in section 8.6.

Commenter Name: Timothy Hunt

Commenter Affiliation: American Forest and Paper Association (AF&PA)

Document Control Number: EPA-HQ-OAR-2002-0058-3213.1

Comment Excerpt Number: 288

Comment: EPA has failed to document that PM CEMS are sufficiently precise and accurate to 

determine compliance with the applicable standards. PM CEMS are required to meet the 

requirements of PS 11. PS 11 specifications include a correlation coefficient of ?0.85 between 

measured and predicted stack gas PM concentrations. A confidence interval (95%) mid range 

value at the mean PM CEMS response of ±10% of the emission limit, and a tolerance interval 

mid range 95% confidence interval value such that 75% of all possible values are within 25% of 

the PM emission limit. This suggests a very high probability that many CEMS PM 

measurements that show up as exceeding the standard would actually be below the emission 

standard. In this situation, operators would be forced to make changes to a control device or even 

shut down the boiler if these changes did not cause a response, even though PM emissions were 
141

in compliance with the standard! This is in direct conflict with the current view of compliance as 

being either in compliance or out of compliance. If it is EPA’s desire to use PM CEMS for 

demonstrating compliance, it must show how compliance would be determined with devices 

with such a high error band. 

Response:

EPA disagrees with the commenter.

On the sensitivity issue, related to precision and accuracy, we disagree that measurements made 

near the emissions limits are indistinguishable from zero. Modern light scatter devices (e.g., the 

Durag D-R 300-40 at http://www.ppmsystems.fi/files/d-r-300-40.pdf and the Sigrist StackGuard 

monitor at

http://www.photometer.com/en/products/details/features.html?productid=249)

can detect very low concentrations including in the microgram/m3 range.

These devices can also satisfy the relative accuracy requirements in

PS11 at those levels (e.g., with longer PM test runs for reference method PM mass sampling).

On the accuracy issue, we understand and appreciate the effect of measurement uncertainty, 

including the effects of uncertainty inherent in the PM CEMS calibration output, in establishing 

the applicable limits and in determining compliance.. As discussed in responses to other 

comments about establishing the applicable emissions limits, we considered and accounted for 

these uncertainties in applying statistically based confidence factors (i.e., the UPL calculations) 

using the emissions data developed in support of the rule. Once those emissions limits are 

established, it is agency policy that determinations of compliance are to be based on 

measurements conducted with the prescribed procedures including meeting all of the control 

quality assurance and quality control requirements without further adjustment.

Commenter Name: Timothy Hunt

Commenter Affiliation: American Forest and Paper Association (AF&PA)

Document Control Number: EPA-HQ-OAR-2002-0058-3213.1

Comment Excerpt Number: 289

Comment: In Section 63.7525 (b)(6) it is specified that when PM CEMS data are “not obtained 

because of CEMS breakdowns, repairs, calibration checks, and zero and span adjustments, 

emissions data shall be obtained by using other monitoring systems as approved by the 

Administrator or EPA Reference Method 19 of appendix A of 40 CFR part 60 to provide, as 

necessary, valid emissions data for all operating hours per 30-day rolling average.” This is very 

different from the CISWI rule which has specified valid data capture requirements in Section 

60.2730 (n) (14). Even more confusing and conflicting, Section 63.7535(b) says “Except for 

monitor malfunctions, associated repairs, and required quality assurance or control activities 

(including, as applicable, calibration checks and required zero and span adjustments), you must 

monitor continuously (or collect data at all required intervals) at all times the affected source is 

operating.” If the 100% data availability requirements for boilers is not changed, boilers with 

heat inputs >250 MMBtu would be forced to have duplicate PM CEMS systems so that 
142

emissions data are also available during calibration checks, and zero and span adjustments which 

are required daily. And, since two CEMS systems are required for normal operation, a redundant 

third CEMS will have to be installed for periods when one of the two systems malfunctions. 

EPA should change the boiler MACT requirements language in 63.7525 (b)(6) to what is 

required in Section 60.2730 (n) (14) for CISWI sources. 

Response: See the response to EPA-HQ-OAR-2002-0058-2997.1, Comment Excerpt Number 9.

Commenter Name: Timothy Hunt

Commenter Affiliation: American Forest and Paper Association (AF&PA)

Document Control Number: EPA-HQ-OAR-2002-0058-3213.1

Comment Excerpt Number: 290

Comment: To measure and report PM emissions in lb/MMBtu, boilers equipped with PM 

CEMS would also have to install stack gas moisture monitors. EPA has not published any 

performance specifications for stack gas moisture monitors. In the absence of such 

specifications, the reliability of the results of PM CEMS cannot be established. 

We recommend that prior to requiring the installation of CEMS on multi-fuel boilers, biomass 

boilers, or CISWI sources, EPA should sponsor field studies to (1) establish performance 

specifications for stack gas moisture monitors, and (2) determine the accuracy and precision of 

PM CEMS on biomass and multi-fuel boilers and CISWI sources. 

Absent the questions about the feasibility of installing PM CEMS on biomass and multiple fuel 

boilers, we believe that these monitors are not necessary, given the annual PM testing 

requirements and continuous parametric and opacity monitoring. 

Response: We agree that assuring that measured pollutant and flow data must be corrected for 

moisture content for the calculation of emissions in units of the applicable standard. We note that 

40 CFR part 60, appendix B, Performance Specification 2 (PS2) and other CEMS performance 

specifications that refer to PS2 highlight the need to correct measured data for moisture in order 

to calculate relative accuracy and also provides the calculations to do so. Section 12 of PS2 (and 

section 12 of 40 CFR part 60, appendix A, Method 19) provide calculation procedures for most 

typical calculation and measurement scenarios. That said, PS2 does not require a separate 

demonstration of the accuracy of a moisture determination but instead relies on the relative 

accuracy requirements and associated limitations expressed in units of the standard to assure that 

a moisture correction is accurate. We recognize that there are technologies for measuring 

moisture and the source owner may choose to use such technology. We also recognize that the 

moisture content of exhaust gases for many processes are nearly constant (e.g., downstream of 

combustion processes) allowing the use of a calculation constant rather than constant direct 

measurement. There are many examples of CEMS data management systems that apply sitespecific constant moisture values (e.g., established during emissions testing) that continue to pass 

relative accuracy testing and provide reliable emissions data. We believe that the comprehensive 

structure of PS2 and follow-up quality assurance procedures are adequate for this purpose and 

there is no need for an independent accuracy check of a moisture measurement.
143

For the commenter’s recommendations, see the responses to Comment Excerpt Numbers 285-

288 for this commenter.

Commenter Name: Timothy Hunt

Commenter Affiliation: American Forest and Paper Association (AF&PA)

Document Control Number: EPA-HQ-OAR-2002-0058-3213.1

Comment Excerpt Number: 302

Comment: Where facilities use CEMS, operating parameter monitoring is not necessary. 

EPA should incorporate flexibility into the rule for facilities using CEMS that are either required 

by the rule or installed for compliance monitoring. For example, the rule should clarify that when 

PM CEMS are installed and the facility is using a wet scrubber for PM control, scrubber 

parameter monitoring is not necessary. Sources using PM CEMS should also not be subject to an 

opacity limit or required to install COMS. 

Response: We agree that a PM CEMS installed and operated in accordance with Performance 

Specification 11 and the associated quality assurance procedures can provide assurance of 

ongoing compliance without the need for additional continuous or periodic compliance testing. 

The final rule reflects this provision, applying only PM CEMS to large units. For other units, the 

source could use the alternative monitoring under the general provisions to seek this type of 

alternative.

Commenter Name: Mike D. Craig

Commenter Affiliation: New Energy Corp.

Document Control Number: EPA-HQ-OAR-2002-0058-2695.1

Comment Excerpt Number: 3

Comment: Proposed 40 C.F.R. § 63.7525(b)(6) states that if the PM CEM’s is down, emission 

data shall be obtained by using other monitoring systems. Does this mean that a backup PM 

CEM is necessary? 

Response: See the response to EPA-HQ-OAR-2002-0058-2997.1, Comment Excerpt Number 9.

Commenter Name: Mary Graham

Commenter Affiliation: Charleston Metro Chamber of Commerce

Document Control Number: EPA-HQ-OAR-2002-0058-2732.1

Comment Excerpt Number: 10
144

Comment: EPA’s requirement that PM CEMS should be used to demonstrate continuous 

compliance on all solid fuel boilers larger than 250 MMBtu/hr is arbitrary and not supported by 

any data. In the proposal EPA has stated that PM CEMS are used at a variety of sources in 

Europe and several electric utilities either have or are planning to install PM CEMS. Such 

general information does not establish the performance capabilities of PM CEMS and does not 

justify their use as compliance monitors for all industrial boilers over 250 MMBtu/hr. There are 

several significant issues with installing PM CEMS on multi-fuel boilers and biomass boilers 

commonly used in the forest products industry that need to be addressed before installation of 

such systems. 

Response: See the response to EPA-HQ-OAR-2002-0058-2913.1, Comment Excerpt Number 

17.

Commenter Name: Melvin E. Keener

Commenter Affiliation: Coalition for Responsible Waste Incineration (CRWI)

Document Control Number: EPA-HQ-OAR-2002-0058-2824.1

Comment Excerpt Number: 11

Comment: CRWI is concerned that EPA is using one method to develop standards and requiring 

a different method to show compliance. 

CRWI is also concerned that EPA is developing a standard for PM based on stack test data while 

requiring compliance based on a PM CEMs. It appears that EPA is using one method to set the 

standard and a totally different method to show compliance. The U.S. Court of Appeals for the 

D.C. Circuit has ruled that "a significant difference, between techniques used by the Agency in 

arriving at standards, and requirements presently prescribed for determining compliance with 

standards, raises serious questions about the validity of the standard." Portland Cement supra at 

396. CRWI believes that using stack test data to set the standards and then PM CEMs to show 

compliance qualifies as "a significant difference between techniques." 

The primary difference between these two methods will be that the variability experienced 

during normal operations will not be captured during the stack test but will become apparent as 

the facility operates a CEMs over time. CRWI believes that if EPA wishes to use PM CEMs to 

show compliance with the standard, then the, standard must be developed using PM CEMs data. 

The same logic can be applied to the mercury requirements. 

Response: See the response to EPA-HQ-OAR-2002-0058-3179, Comment Excerpt Number 7.

Commenter Name: Ashok K. Jain

Commenter Affiliation: National Council for Air and Stream Improvement

Document Control Number: EPA-HQ-OAR-2002-0058-2804.1
145

Comment Excerpt Number: 14

Comment: 3. Comment on EPA Determination that PM CEMSs Should Be Installed on Boilers 

with Heat Input Capacity Greater Than or Equal to 250 MMBtu/hr 

In order for a CEM to be suitable for demonstrating compliance, a CEM must be accurate and 

precise under all operating conditions, and must have demonstrated the capability of operating 

for long periods of time without breaking down. 

However, as discussed below, these needs are not met when considering installation of PM 

CEMSs on solid fuel industrial boilers. 

EPA has failed to provide any technical information regarding the suitability of PM 

CEMSs as compliance monitors. Instead, in the proposal EPA has stated that PM CEMSs are 

used at a variety of sources in Europe and several electric utilities either have or are planning to 

install PM CEMSs. Such broad general statements neither establish the performance capabilities 

of PM CEMSs nor do they justify their use as compliance monitors. 

An examination of the history of PS 11 and Procedure 2 would show that EPA 

promulgated PS 11 and Procedure 2 based on very limited data. When EPA initially proposed PS 

11, it was based on EPA’s view of what the capabilities of PM CEMSs should be. However, the 

very few PM CEMSs installed on electric utility industry boilers at that time could not meet the 

proposed criteria. Consequently, PS 11 was extensively modified based upon utility industry 

experience with units installed on coal-fired boilers. At the time of the promulgation of PS 11, no 

information was provided by EPA regarding the capability of PM CEMSs to satisfy PS 11 on 

sources other than coal-fired electric utility boilers nor was an opportunity provided to the public 

to comment on the suitability of implementing PS 11 and Procedure 2 on other types of emission 

sources. 

Response: See the response to EPA-HQ-OAR-2002-0058-2913.1, Comment Excerpt Number 

17.

Commenter Name: Ashok K. Jain

Commenter Affiliation: National Council for Air and Stream Improvement

Document Control Number: EPA-HQ-OAR-2002-0058-2804.1

Comment Excerpt Number: 15

Comment: There are several significant issues with installing PM CEMSs on multi-fuel boilers 

that need to be addressed before such systems could be considered for use as compliance 

monitors: 

(i) Among the instruments used to quantify PM emissions are light scattering, optical 

scintillation, electrostatic induction and beta gauge instruments. The responses of these 
146

instruments are expected to be affected by the size and nature of particles being emitted. Thus 

the calibration curve for such instruments would be expected to change as the fuel mix changes. 

EPA has not published the results of any study examining these issues and thus is not in a 

position to confirm that given the changing nature of PM emissions from multi-fuel boilers, PM 

CEMSs are capable of accurately measuring source PM emissions. 

(ii) 

Although EPA has mentioned installation of PM CEMSs at utility industry boilers, it has not 

provided reference to any peer-reviewed publication documenting that PM CEMSs are routinely 

capable of meeting the requirements of PS 11 and PS2, or that they measure PM emissions 

accurately. 

Response: See response to Document Control Number: EPA-HQ-OAR-2002-0058-2804.1, 

Comment Excerpt Number: 14.

Commenter Name: Ashok K. Jain

Commenter Affiliation: National Council for Air and Stream Improvement

Document Control Number: EPA-HQ-OAR-2002-0058-2804.1

Comment Excerpt Number: 16

Comment: PS 11 specifies in Section 8.6 (4) (i) that simultaneous PM CEMSs and reference 

method tests must be performed to obtain three levels of PM mass concentrations. Section 8.6 (4) 

(ii) specifies that the three PM concentrations must be distributed over the complete operating 

range experienced by the source. Thus, if a source experiences high PM emissions for short 

periods of time due to startup, shutdown, or process upsets, the facility would have to conduct 

the correlation tests at emission levels that could be above the emission standards. This raises the 

following issues: 

(i) How can a source operate above its PM limits in order to conduct stack tests to meet PS-11 

requirements if it must be in compliance with its PM limits at all times’ 

(ii) EPA has assumed that PM emissions from a source are like “dial a PM” and can be 

controlled within a narrow range through minor operating changes. Such changes in PM 

emissions are, however, not always easily accomplished. For example, the efficiency of a wet 

scrubber is affected by the particle size distribution, gas flow rate, pressure drop, and scrubbing 

solution flow rate. Thus a facility cannot just dial a PM emission rate and continue their PS-11 

test. Similarly, it is not clear how a facility equipped with a bag house will achieve targeted PM 

emission rates to satisfy the requirements of PS-11. 

(iii) Some states do not allow facilities to operate control devices below their maximum 

capability, yet this would be necessary to meet the PS-11 requirements. How will EPA deal with 

this situation’ 
147

Response: See the preamble for revised treatment of SSM. 

Process upsets are not part of "normal operations" as per PS-11, therefore the facility would not 

have try to capture that emission level for the correlation testing. 

Achieving a range of emission levels for units with wet scrubbers or fabric filters is a challenge, 

but many sources have been able to achieve the requirements of PS-11 by either perturbing these 

devices and/or by using the "zero point" that is given in section 8.6.

Commenter Name: Chris Greissing

Commenter Affiliation: Industrial Minerals Association

Document Control Number: EPA-HQ-OAR-2002-0058-2740.2

Comment Excerpt Number: 17

Comment: EPA Incorrectly Estimates the Burden on Sources of PM Monitoring. The Proposed 

Rule requires the installation, certification, maintenance and operation of a CEMS for PM 

emissions. Proposed 63.7525(b). Such a requirement is excessive and the capital, operating and 

maintenance costs cannot be justified given that non-mercury metallic HAPs represent only 6 

percent of total HAPs regulated by this NESHAP. EPA should eliminate the requirement for PM 

CEMS and impose the same standard for all sources; that is, units with heat input capacities 

greater than 250 MMBtu/hr should be required to meet the same compliance demonstration as 

those units < 250 MMBtu/hr, i.e. initial and annual performance stack tests. Similarly, the 

Proposed Rule requires parameter monitoring for PM control equipment for units less than 250 

MMBtu/hr, bag leak detectors for fabric filters and voltage and current for ESPs. Requiring 

parameter monitoring for larger units would provide continuous monitoring regarding PM 

control, a reasonable alternative to a CEMS. 

Response: For the operations and facilities subject to the rule, we believe that the combination 

of periodic compliance emissions testing and continuous monitoring of operational and 

parametric control measure conditions is appropriate for assuring ongoing compliance for most 

units. For large boilers, we have required use of a PM CEMS. The costs and burdens of these 

requirements are included in the impact assessments conducted for this rule, and are part of 

compliance costs that EPA has found to be reasonable for the affected sources.

Commenter Name: Ashok K. Jain

Commenter Affiliation: National Council for Air and Stream Improvement

Document Control Number: EPA-HQ-OAR-2002-0058-2804.1

Comment Excerpt Number: 17

Comment: EPA has failed to document that PM CEMSs are sufficiently precise and accurate to 

determine compliance with the applicable standards. 
148

PM CEMSs are required to meet the requirements of PS-11. PS-11 specifications include 

obtaining a correlation coefficient of ‘0.85 between measured and predicted stack gas PM 

concentrations, a confidence interval (95%) mid range value at the mean PM CEMS response of 

±10% of the emission limit, and a tolerance interval mid range 95% confidence interval value 

such that 75% of all possible values are within 25% of the PM emission limit. This suggests a 

very high probability that many CEMS PM measurements that show up as exceeding the 

standard would actually be below the emission standard. This is in direct conflict with the current 

view of compliance as being either in compliance or out of compliance. If it is EPA’s desire to 

use PM CEMSs for demonstrating compliance, it must show how compliance would be 

determined using devices with such a high error band. 

Response:

EPA disagrees with the commenter.

On the sensitivity issue, related to precision and accuracy, we disagree that measurements made 

near the emissions limits are indistinguishable from zero. Modern light scatter devices (e.g., the 

Durag D-R 300-40 at http://www.ppmsystems.fi/files/d-r-300-40.pdf and the Sigrist StackGuard 

monitor at

http://www.photometer.com/en/products/details/features.html?productid=249)

can detect very low concentrations including in the microgram/m3 range.

These devices can also satisfy the relative accuracy requirements in

PS11 at those levels (e.g., with longer PM test runs for reference method PM mass sampling).

On the accuracy issue, we understand and appreciate the effect of measurement uncertainty, 

including the effects of uncertainty inherent in the PM CEMS calibration output, in establishing 

the applicable limits and in determining compliance.. As discussed in responses to other 

comments about establishing the applicable emissions limits, we considered and accounted for 

these uncertainties in applying statistically based confidence factors (i.e., the UPL calculations) 

using the emissions data developed in support of the rule. Once those emissions limits are 

established, it is agency policy that determinations of compliance are to be based on 

measurements conducted with the prescribed procedures including meeting all of the control 

quality assurance and quality control requirements without further adjustment.

Commenter Name: Ashok K. Jain

Commenter Affiliation: National Council for Air and Stream Improvement

Document Control Number: EPA-HQ-OAR-2002-0058-2804.1

Comment Excerpt Number: 18

Comment: Proposed Section 63.7525 (b)(6)specifies that when PM CEMS data are “not 

obtained because of CEMS breakdowns, repairs, calibration checks, and zero and span 

adjustments, emissions data shall be obtained by using other monitoring systems as approved by 

the Administrator or EPA Reference Method 19 of appendix A of 40 CFR part 60 to provide, as 

necessary, valid emissions data for all operating hours per 30-day rolling average.” (Note: The 
149

reference to a 30-day rolling average is apparently in error since 63.7525(b)(3) indicates 

compliance is to be determined based on 24-hour block averages.) The requirement for obtaining 

valid data for all operating hours is unrealistic. The proposed CISWI rule recognizes this fact, 

and requires 85% valid data for each 24- hour period (see proposed §60.2730 (n) (14)). If the 

100% data availability requirement remains in the final MACT rule, boilers with heat inputs 

>250 MMBtu will need duplicate PM CEMSs to obtain data during the required daily calibration 

checks, zero adjustments and span adjustments on the primary CEMS. Since two CEMSs would 

be required for normal operation, a third CEMS will be needed to cover for periods when one of 

the other two CEMSs malfunctions. 

EPA apparently overlooked this 100% data availability requirement, since only the cost of a 

single PM CEMS was included in cost impact estimates. EPA should change the boiler MACT 

data recovery provisions in 63.7525 (b)(6) to make them more realistic, such as the provisions 

proposed for CISWI sources in §60.2730 (n) (14). 

Response: &&& See the response to EPA-HQ-OAR-2002-0058-2997.1, Comment Excerpt 

Number 9.

Commenter Name: Ashok K. Jain

Commenter Affiliation: National Council for Air and Stream Improvement

Document Control Number: EPA-HQ-OAR-2002-0058-2804.1

Comment Excerpt Number: 19

Comment: (d) To measure and report PM emissions in lb/MMBtu, boilers equipped with PM 

CEMSs would also have to install stack gas moisture monitors. EPA has not published any 

performance specifications for stack gas moisture monitors. In the absence of such 

specifications, the reliability of the results of PM CEMSs cannot be established. 

We recommend that prior to requiring the installation of CEMSs on biomass boilers, residual oil 

boilers, multi-fuel boilers and CISWI sources, EPA should sponsor field studies to (1) establish 

performance specifications for stack gas moisture monitors, and (2) determine the accuracy and 

precision of PM CEMSs on biomass boilers, residual oil, multi-fuel boilers and CISWI sources, 

especially when load and fuel mix ratios are constantly changing. 

Response: Same as EPA-HQ-OAR-2002-0058-3213.1, Comment Excerpt Number 290. See 

that response. 

Commenter Name: William A. Moore

Commenter Affiliation: Luminant

Document Control Number: EPA-HQ-OAR-2002-0058-2780.1

Comment Excerpt Number: 22
150

Comment: Luminant does not support use of PM CEMS to demonstrate continuous compliance. 

EPA’s proposed rule requires PM CEMS for units combusting coal, biomass, or oil with heat 

input capacity greater or equal to 250 mmBtu/hr to demonstrate continuous compliance with the 

applicable PM emissions limit. 75 Fed. Reg. at 32,033, 32,055. EPA’s justification for this 

requirement is that “[s]everal electric utility companies in the United States have now installed or 

are planning to install PM CEMS,” that EPA has developed “Performance Specifications” for 

PM CEMS, and that “capital costs were estimated to be $88,000 per unit and annualized costs 

were estimated to be $33,000 per unit.” Id. at 32,033. However, PM CEMS should not be 

required because their accuracy and long-term stability has not been sufficiently demonstrated 

and the cost of installing, maintaining and monitoring PM CEMS is too high. It is Luminant’s 

experience that developing a correlation to Method 5 measurements at the low emission rates 

proposed in this rule is difficult, at best. The primary problem is trying to operate a unit at three 

different PM concentrations during correlation testing where the not-to-exceed emission rate is 

near the method detection level. Another issue is that a correlation cannot be established during 

startup and shutdown conditions because PM sampling cannot be conducted during unit

transitional operation. Luminant recommends using an annual Method 5 test for compliance, and 

ESP or baghouse parameter monitoring for initiating equipment evaluation and maintenance 

practices, not determining compliance with enforceable limits. 

Response: See the response to EPA-HQ-OAR-2002-0058-2913.1, Comment Excerpt Number 

17.

Commenter Name: Randall D. Quintrell

Commenter Affiliation: Georgia Paper and Forest Products Association, GPFPA

Document Control Number: EPA-HQ-OAR-2002-0058-2905

Comment Excerpt Number: 24

Comment: The Boiler MACT proposal requires the installation and use of particulate matter 

continuous emissions monitoring systems (PM CEMs) to assure continuous compliance with the 

emission standard for boilers combusting coal, biomass or residual oil with a heat input capacity 

of 250 MMBtu/hr or greater. Under the proposed Rule, many of our boilers will be required to 

install PM CEMs. NCASI indicates that they are not aware of any PM CEMs in operation in the 

pulp and paper industry. 

We are aware of six types of PM monitoring technologies: light scattering, beta attenuation, 

probe electrification, light extinction, optical scintillation and harmonic oscillation. The only 

technology that is not dependent upon particle characteristics is harmonic oscillation; however, 

that technology is designed for short-term use (e.g., less than a week). Light scattering and beta 

attenuation technologies both have longer use histories than the other technologies but have 

notable limitations. Both are dependent upon particle characteristics. Moreover, light scattering 

cannot be employed for wet-scrubber-controlled sources. Our industry uses a wide variety of fuel 
151

types often burned at the same time with a wide range of proportions, and we have serious 

reservations about the accuracy of data generated by PM CEMs systems that are dependent upon 

particle characteristics since variation in the types of fuels combusted will impact the operation 

of such device(s). 

There is no "calibration gas" for PM CEMS and the meters require in-situ calibration. The PM 

CEMs calibration protocol requires 21 one-hour runs at three PM emission levels: low, medium 

[i.e., near limit] and high [i.e., over limit] to develop a calibration curve. Presuming that a fourhour stack test is required to even collect sufficient PM to reach the practical quantitation limit, 

the one-hour calibration runs at such low emission levels, especially those at low and medium 

emission rates, will provide no valid data and are essentially a useless exercise. Mandating the 

use of these meters presents another untenable dilemma. The standard requires compliance at all 

times, and calibration of the meter requires operation out of compliance! Further, the calibration 

protocol erroneously presumes that a source can readily and reliably "dial in" a low, medium or 

high PM emission rate at will. Finally, different calibration curves may need to be established as 

a function of various fuel blends, multiplying the time and expense to try to calibrate such a 

meter. Then, the PM CEMS must be "switched" to a new curve when the fuel mix changes. 

Collectively, the challenges associated with the use of PM CEMs in our industry leads us to 

question the feasibility of the use of these systems in this application, and it makes the reliability 

of the data the units generate highly questionable, particularly at the extremely low PM limits 

proposed in the Rule. In short, the PM CEMS is unsuited for use as a compliance monitor under 

Boiler MACT and its use must be eliminated in the final Rule. 

We believe that there are other valid indicators to determine if control equipment is operating 

properly. For electrostatic precipitators, monitoring total secondary power is a suitable indicator. 

For scrubbers, monitoring pressure drop and scrubbant flow have been reliably used for years to 

verify that the scrubber is operating in the range that demonstrates compliance. After all, PM is 

only a surrogate for PM-HAP, and PM-HAP is a tiny fraction of the PM. These conventional 

parametric monitoring systems used for PM are adequate and reasonable for monitoring 

compliance and should be specified as acceptable compliance assurance monitoring 

methodology in the final Rule. 

Response: See the response to EPA-HQ-OAR-2002-0058-2913.1, Comment Excerpt Number 

17.

Commenter Name: David A. Buff

Commenter Affiliation: Golder Associates Inc

Document Control Number: EPA-HQ-OAR-2002-0058-2801.1

Comment Excerpt Number: 50

Comment: A PM CEMS is not necessary since all boilers have a PM control device and the rule 

contains adequate surrogate monitoring parameters, which are much less costly to install and 

operate compared to a CEMS. FSI sugar mills have 5 or 6 boilers, and the cost of PM CEMS on 
152

all of these would be significant for every mill. Also, PM CEMS are not well demonstrated on 

industrial boilers. EPA has estimated in the preamble that existing biomass units will require on 

average $85,000 per year per boiler for testing and monitoring. For a sugar mill, this would mean 

upwards of $400,000 per year, a significant portion of which would be attributable to the PM 

CEMS. 

Response: For the operations and facilities subject to the rule, we believe that the combination of 

periodic compliance emissions testing and continuous monitoring of operational and parametric 

control measure conditions is appropriate for assuring ongoing compliance for most units. For 

large boilers, we have required use of a PM CEMS. The costs and burdens of these requirements 

are included in the impact assessments conducted for this rule, and are part of compliance costs 

that EPA has found to be reasonable for the affected sources.

Commenter Name: Robert D. Bessette

Commenter Affiliation: Council of Industrial Boiler Owners (CIBO)

Document Control Number: EPA-HQ-OAR-2002-0058-2702.1

Comment Excerpt Number: 114

Comment: PM CEMS 

A. PM floor Based on Three, One-hour Emission Test Runs. 

EPA should also use data from existing PM CEMS to determine variability impacts for inclusion 

in establishing the floor when PM CEMS are required. If PM CEMS are required for specific 

units, EPA needs to include consideration of actual PM CEMS response for units in the 

particular subcategory firing applicable fuels. It is inappropriate to only use 3 limited time 

reference method runs to establish an emission limit that will need to be met using continuous 

monitoring. Reference method testing at high load steady state conditions does not represent 

actual average emissions as would be measured over all operating conditions with a CEMS. 

Response: See the response to EPA-HQ-OAR-2002-0058-3179, Comment Excerpt Number 7.

Commenter Name: Robert D. Bessette

Commenter Affiliation: Council of Industrial Boiler Owners (CIBO)

Document Control Number: EPA-HQ-OAR-2002-0058-2702.1

Comment Excerpt Number: 115

Comment: B. EPA’s Proposed PM Limit for Units > 250MMBtu/hr and Requirement to Use 

PM CEMs Is Too Stringent. 

EPA proposes that particulate matter CEMS be installed on units > 250MMBtu per hour to 

satisfy continuous compliance requirements for particulate matter emissions. 75 FR 32055. The 

installation and annual certification expenses for the PM CEMS are extreme and unreasonable. 

As an alternative to PM CEMS, CIBO recommends that EPA allow the installation and operation 
153

of bag leak detection systems in accordance with the Proposed Rule’s §63.7525(j)(1) through (8) 

in addition to the existing opacity monitors. The bag leak detection system provides ongoing 

monitoring of the bag house component performance and provides for continuous compliance 

demonstration. 

Response: For the operations and facilities subject to the rule, we believe that the combination of 

periodic compliance emissions testing and continuous monitoring of operational and parametric 

control measure conditions is appropriate for assuring ongoing compliance for most units. For 

large boilers, we have required use of a PM CEMS. The costs and burdens of these requirements 

are included in the impact assessments conducted for this rule, and are part of compliance costs 

that EPA has found to be reasonable for the affected sources.

Commenter Name: Robert D. Bessette

Commenter Affiliation: Council of Industrial Boiler Owners (CIBO)

Document Control Number: EPA-HQ-OAR-2002-0058-2702.1

Comment Excerpt Number: 117

Comment: EPA should consider the following with regard to the proposed PM CEMS 

requirement: 

Large RO units, and probably large solid fuel units, should not be forced to install a redundant 

PM monitoring system (i.e., PM CEMS) in light of the fact that the resultant emissions after 

installing equipment to comply with Boiler MACT are likely to be low. 

EPA should provide an achievable alternative to install PM controls on existing RO units rather 

than encourage the conversion to gas. Requiring excessive and redundant PM monitoring 

systems on large RO units is just another reason to convert to gas. 

Based on best performer PM data for liquid fired units noted above, it appears lowest emission 

rate units fire lower sulfur oil. It is logical that PM emissions are associated with the sulfur level 

since the EPA document AP-42 Table 1.3-1 equation for filterable PM is calculated from oil 

sulfur level. EPA should evaluate all available data and evaluate PM emissions as a function of 

Residual Oil sulfur content and provide an alternative standard that simply requires use of low 

sulfur Residual Oil. Such a standard could rely on supplier certification of the oil sulfur level. 

This low sulfur option approach is believed also adequate for fuel dependent HAP emissions 

such as HCl and Hg as well. EPA can evaluate and support that approach with the available data. 

It appears that EPA has never required a PM CEMS without allowing for alternative PM 

monitoring options. At the very least, EPA should explicitly open the door to alternative site/unit 

specific PM monitoring proposals in the rule for large RO fired units. 

EPA’s requirement that PM CEMS should be used to demonstrate continuous compliance on all 

solid fuel boilers larger than 250 MMBtu/hr is arbitrary and not supported by any data. There is 

no published information documenting that PM CEMS installed on multi-fuel boilers can 

measure PM emissions accurately and demonstrate compliance with PS 11. 
154

In the preamble to the Proposed Rule at 75 FR 32033, EPA asked for comments on its 

determination that PM CEMS should be required and used for determining compliance with the 

emission standards on boilers which burn coal, biomass, or oil and have a heat input capacity 

greater than or equal to 250 MMBtu/hr. The installed PM CEMS would be required to meet

Performance Specification 11 and also comply with Procedure 2 in Appendix F to 40 CFR 60. 

In order for a CEM to be suitable for demonstrating compliance, a CEM must be accurate and 

precise under all operating conditions, and must have demonstrated the capability of sustained 

operations for long periods of time. However, as discussed below, these needs are not met when 

considering installation of PM CEMS on solid fuel boilers. 

EPA has failed to provide any technical information regarding the suitability of PM CEMS as 

compliance monitors. Instead, in the proposal EPA has stated that PM CEMS are used at a 

variety of sources in Europe and several electric utilities either have or are planning to install PM 

CEMS. Such general information does not establish the performance capabilities of PM CEMS 

and does not justify their use as compliance monitors for all industrial boilers over 250 

MMBtu/hr. 

Response: See the response to EPA-HQ-OAR-2002-0058-2913.1, Comment Excerpt Number 

17. Also, on the sensitivity issue, related to precision and accuracy, we disagree that 

measurements made near the emissions limits are indistinguishable from zero. Modern light 

scatter devices (e.g., the Durag D-R 300-40 at http://www.ppmsystems.fi/files/d-r-300-40.pdf 

and the Sigrist StackGuard monitor at

http://www.photometer.com/en/products/details/features.html?productid=249)

can detect very low concentrations including in the microgram/m3 range.

These devices can also satisfy the relative accuracy requirements in

PS11 at those levels (e.g., with longer PM test runs for reference method PM mass sampling).

On the accuracy issue, we understand and appreciate the effect of measurement uncertainty, 

including the effects of uncertainty inherent in the PM CEMS calibration output, in establishing 

the applicable limits and in determining compliance.. As discussed in responses to other 

comments about establishing the applicable emissions limits, we considered and accounted for 

these uncertainties in applying statistically based confidence factors (i.e., the UPL calculations) 

using the emissions data developed in support of the rule. Once those emissions limits are 

established, it is agency policy that determinations of compliance are to be based on 

measurements conducted with the prescribed procedures including meeting all of the control 

quality assurance and quality control requirements without further adjustment.

Commenter Name: Robert D. Bessette

Commenter Affiliation: Council of Industrial Boiler Owners (CIBO)

Document Control Number: EPA-HQ-OAR-2002-0058-2702.1

Comment Excerpt Number: 118
155

Comment: An examination of the history of PS 11 and Procedure 2 shows that EPA 

promulgated PS 11 and Procedure 2 based on very limited data. When EPA initially proposed PS 

11, it was based on EPA’s view of what the capabilities of PM CEMS should be. However, the 

very few PM CEMS installed on electric utility industry boilers could not meet the proposed 

requirements. Consequently, PS 11 was extensively modified based upon utility industry data. At 

the time of the promulgation of PS 11, no information was provided by EPA regarding the 

capability of PM CEMS to satisfy PS 11 on sources other than coal-fired electric utility boilers 

nor was an opportunity provided to the industry to comment on the suitability of implementing 

PS 11 and Procedure 2 on specific source types. 

Response: See the response to EPA-HQ-OAR-2002-0058-2913.1, Comment Excerpt Number 

17.

Commenter Name: Robert D. Bessette

Commenter Affiliation: Council of Industrial Boiler Owners (CIBO)

Document Control Number: EPA-HQ-OAR-2002-0058-2702.1

Comment Excerpt Number: 119

Comment: There are several significant issues with installing PM CEMS on multi-fuel boilers 

and biomass boilers commonly used in the forest products industry that need to be addressed 

before installation of such systems: 

Among the instruments used to quantify PM emissions are light scattering, optical scintillation, 

electrostatic induction, and beta gauge instruments. The responses of these instruments are 

expected to be affected by the size and nature of particles being emitted. Thus the calibration 

curve for such instruments would be expected to change as the fuel mix changes. Multi-fuel 

boilers, such as those used at pulp and paper mills co-fire a wide variety of fuels, including coal, 

wood (bark), tire-derived fuel, pulping process residuals, waste treatment residuals, oil and 

natural gas. Each of these fuels may be fired at different levels during an operating day 

depending upon process conditions and availability. EPA has not published the results of any 

study examining these issues and thus is not in a position to confirm that given the changing 

nature of PM emissions from multi-fuel boilers, PM CEMS will accurately measure source PM 

emissions. 

Similarly, even "biomass boilers" may burn different types of biomass. For example, boilers at 

plywood plants burn bark removed from the logs before they are processed into veneer and also 

burn trim and scrap from the finished veneer. Again, EPA has not published the results of any 

study examining biomass boilers and thus is not in a position to confirm that given the changing 

nature of PM emissions from these units, PM CEMS will accurately measure source PM 

emissions. 
156

Although EPA has mentioned installation at utility industry boilers, it has not provided reference 

to any peer-reviewed publication documenting that PM CEMS are routinely capable of meeting 

the requirements of PS 11 and PS2 and measure PM emissions accurately. 

PS 11 specifies in Section 8.6 (4) (i) that simultaneous PM CEMS and reference method tests 

must be performed to obtain three levels of PM mass concentrations. Section 8.6(4)(ii) specifies 

that the three PM concentrations must be distributed over the complete operating range 

experienced by the source. Thus, if a source experiences high PM emissions for short periods of 

time due to process upsets or malfunctions, the facility would have to conduct the correlation 

tests at emission levels that exceed the emission standards. 

Response: See response to Document Control Number: EPA-HQ-OAR-2002-0058-2702.1, 

Comment Excerpt Number: 118 

Commenter Name: Robert D. Bessette

Commenter Affiliation: Council of Industrial Boiler Owners (CIBO)

Document Control Number: EPA-HQ-OAR-2002-0058-2702.1

Comment Excerpt Number: 120

Comment: C. Does EPA have the legal authority to require a source to operate above its permit 

limit? 

EPA assumes that PM emissions from a source can be controlled within a narrow range through 

minor operating changes. Such changes in PM emissions are not always easily accomplished. 

For example, the efficiency of a wet scrubber is affected by the particle size distribution, gas 

flow rate, pressure drop, and scrubbing solution flow rate. Thus a facility cannot just dial a PM 

emission rate and continue their PS 11 test. Similarly, it is not clear how a facility equipped with 

a bag house will achieve targeted PM emission rates to satisfy the requirements of PS 11, other 

than purposefully creating a hole in one or more of its bags (certainly not a desirable action). 

EPA has failed to document that PM CEMS are sufficiently precise and accurate to determine 

compliance with the applicable standards. PM CEMS are required to meet the requirements of 

PS 11. PS 11 specifications include a correlation coefficient of 10.85 between measured and 

predicted stack gas PM concentrations. A confidence interval (95%) mid range value at the mean 

PM CEMS response of ±10% of the emission limit, and a tolerance interval mid range 95% 

confidence interval value such that 75% of all possible values are within 25% of the PM 

emission limit. This suggests a very high probability that many CEMS PM measurements that 

show up as exceeding the standard would actually be below the emission standard. In this 

situation, operators would be forced to make changes to a control device or even shut down the 

boiler if these changes did not cause a response, even though PM emissions were in compliance 

with the standard. This is in direct conflict with the current view of compliance. If it is EPA’s 

desire to use PM CEMS for demonstrating compliance, it must show how compliance would be 

determined with devices with such a high error band. 
157

In proposed § 63.7525(b)(6) it is specified that when PM CEMS data are "not obtained because 

of CEMS breakdowns, repairs, calibration checks, and zero and span adjustments, emissions data 

shall be obtained by using other monitoring systems as approved by the Administrator or EPA 

Reference Method 19 of appendix A of 40 CFR part 60 to provide, as necessary, valid emissions 

data for all operating hours per 30-day rolling average." 75 FR 32055 This is very different from 

the CISWI rule which has specified valid data capture requirements in Section 60.2730 (n) (14). 

Even more confusing and conflicting, Proposed Section 63.7535(b) says "Except for monitor 

malfunctions, associated repairs, and required quality assurance or control activities (including, 

as applicable, calibration checks and required zero and span adjustments), you must monitor 

continuously (or collect data at all required intervals) at all times the affected source is 

operating." 75 FR 32056. If the 100% data availability requirements for boilers is not changed, 

boilers with heat inputs >250 MMBtu would be forced to have duplicate PM CEMS systems so 

that emissions data are also available during calibration checks, and zero and span adjustments 

which are required daily. And, since two CEMS systems are required for normal operation, a 

redundant third CEMS will have to be installed for periods when one of the two systems 

malfunctions. 

EPA should change the boiler MACT requirements language in 63.7525 (b)(6) to what is 

required in Section 60.2730 (n) (14) for CISWI sources. 

Response:

See the preamble for revised treatment of SSM. Process upsets are not part of "normal 

operations" as per PS-11, therefore the facility would not have try to capture that emission level 

for the correlation testing. 

Achieving a range of emisson levels for units with wet scrubbers or fabric filters is a challenge, 

but many sources have been able to achieve the requirements of PS-11 by either perturbing these 

devices and/or by using the "zero point" that is given in section 8.6.

On the sensitivity issue, related to precision and accuracy, we disagree that measurements made 

near the emissions limits are indistinguishable from zero. Modern light scatter devices (e.g., the 

Durag D-R 300-40 at http://www.ppmsystems.fi/files/d-r-300-40.pdf and the Sigrist StackGuard 

monitor at

http://www.photometer.com/en/products/details/features.html?productid=249)

can detect very low concentrations including in the microgram/m3 range.

These devices can also satisfy the relative accuracy requirements in

PS11 at those levels (e.g., with longer PM test runs for reference method PM mass sampling).

On the accuracy issue, we understand and appreciate the effect of measurement uncertainty, 

including the effects of uncertainty inherent in the PM CEMS calibration output, in establishing 

the applicable limits and in determining compliance. As discussed in responses to other 

comments about establishing the applicable emissions limits, we considered and accounted for 

these uncertainties in applying statistically based confidence factors (i.e., the UPL calculations) 

using the emissions data developed in support of the rule. Once those emissions limits are 

established, it is agency policy that determinations of compliance are to be based on 
158

measurements conducted with the prescribed procedures including meeting all of the control 

quality assurance and quality control requirements without further adjustment.

Also, See the response to EPA-HQ-OAR-2002-0058-2997.1, Comment Excerpt Number 9 on the 

data availability issue.

Commenter Name: Robert D. Bessette

Commenter Affiliation: Council of Industrial Boiler Owners (CIBO)

Document Control Number: EPA-HQ-OAR-2002-0058-2702.1

Comment Excerpt Number: 121

Comment: To measure and report PM emissions in lb/MMBtu, boilers equipped with PM 

CEMS would also have to install stack gas moisture monitors. EPA has not published any 

performance specifications for stack gas moisture monitors. In the absence of such 

specifications, the reliability of the results of PM CEMS cannot be established. 

We recommend that prior to requiring the installation of CEMS on multi-fuel boilers, biomass 

boilers, or CISWI sources, EPA should sponsor field studies to (1) establish performance 

specifications for stack gas moisture monitors, and (2) determine the accuracy and precision of 

PM CEMS on biomass and multi-fuel boilers and CISWI sources.

Absent the questions about the feasibility of installing PM CEMS on biomass and multiple fuel 

boilers, we believe that these monitors are not necessary, given the annual PM testing 

requirements and continuous parametric and opacity monitoring. If PM CEMS remain a rule 

requirement for larger boilers, the averaging period should be increased to 30 days, similar to the 

averaging period for sources installing CO CEMS. As stated in the discussion elsewhere in these 

comments regarding averaging times and SSM, it will be difficult for sources to meet 24-hour 

block average limits when operational variability and SSM are considered. 

Response: See EPA-HQ-OAR-2002-0058-3213.1, Comment Excerpt Number 290. Also, the 

averaging period has been revised to a 30-day rolling average. 

Commenter Name: Robert D. Bessette

Commenter Affiliation: Council of Industrial Boiler Owners (CIBO)

Document Control Number: EPA-HQ-OAR-2002-0058-2702.1

Comment Excerpt Number: 122

Comment: 1. Requirements appear excessive and costly given marginal environmental benefit. 

Proposed section 63.7540(a)(9) requires annual RATA testing, plus initial correlation testing, 

and then response correlation audits every 3 years. Response correlation audits include a 

minimum of 15 manual reference tests over the full range of PM responses that correspond to 
159

normal operating conditions for the source and control device and result in the widest range of 

emission concentration. This entails considerable cost and time for testing. EPA should justify 

why the every 3 year response correlation audits are required if fuel types and equipment do not 

change over that period compared to the apparent initial correlation testing and annual RATA in 

PS-11/Appendix F. This additional testing imposes additional cost with no additional 

environmental benefit over use of COMS/BLD and periodic PM testing. Since that is the case, it 

also appears that required use of PM CEMS has not been justified. 

Response: PS-11 requires correlation audits as one of the elements of providing adequate 

QA/QC for a PM CEMS. These were included in the specification when it was promulgated and 

will apply under this rule as part of the overall effort associated with operating a PM CEMS.

Commenter Name: Robert D. Bessette

Commenter Affiliation: Council of Industrial Boiler Owners (CIBO)

Document Control Number: EPA-HQ-OAR-2002-0058-2702.1

Comment Excerpt Number: 125

Comment: D. EPA should allow PM CEMS as an alternative to opacity or BLD approaches. 

There may be some applications where use of PM CEMS makes sense. EPA should allow 

sources the option of using a PM CEMS or COMS/BLD with PM emissions testing. 

Response: We agree that a PM CEMS installed and operated in accordance with Performance 

Specification 11 and the associated quality assurance procedures can provide assurance of 

ongoing compliance without the need for additional continuous or periodic compliance testing. 

The final rule reflects this provision, applying only PM CEMS to large units. For other units, the 

source could use the alternative monitoring under the general provisions to seek this type of 

alternative.

Commenter Name: Robert D. Bessette

Commenter Affiliation: Council of Industrial Boiler Owners (CIBO)

Document Control Number: EPA-HQ-OAR-2002-0058-2702.1

Comment Excerpt Number: 126

Comment: E. Rule should specifically state that if PM CEMS is installed, neither COMS nor 

BLD should be required. 

EPA needs to specifically state that when a PM CEMS is installed, neither a COMS nor BLD is 

required to be installed. That is not clear in the Proposed Rule. This approach is included in the 

Proposed CISWI Rule preamble. 75 FR 31961. EPA should include the following in the final 

rule: "PM CEMS. The proposed amendments would allow the use of PM CEMS as an alternative 

testing and monitoring method (except for energy recovery units with a heat input capacity 

greater than 250 MMBtu/hr which are required to use them). Owners or operators who are 

required to use, or choose to rely on, PM CEMS would be able to discontinue their annual PM 

compliance test. In addition, because units that demonstrate compliance with the PM emission 
160

limits with a PM CEMS would also be meeting the opacity standard, compliance demonstration 

with PM CEMS would be considered a substitute for opacity testing or opacity monitoring. 

Owners and operators who use PM CEMS also would be able to discontinue their monitoring of 

minimum wet scrubber pressure drop, horsepower or amperage." 

Response: We agree that a PM CEMS installed and operated in accordance with Performance 

Specification 11 and the associated quality assurance procedures can provide assurance of 

ongoing compliance without the need for additional continuous or periodic compliance testing. 

The final rule reflects this provision, applying only PM CEMS to large units. For other units, the 

source could use the alternative monitoring under the general provisions to seek this type of 

alternative.

Commenter Name: Jacquelyn Taylor

Commenter Affiliation: South Carolina Pulp and Paper Association

Document Control Number: EPA-HQ-OAR-2002-0058-3154.1

Comment Excerpt Number: 3

Comment: EPA’s requirement that PM CEMS should be used to demonstrate continuous 

compliance on all solid fuel boilers larger than 250 MMBtu/hr is arbitrary and not supported by 

any data. 

In the proposal EPA has stated that PM CEMS are used at a variety of sources in Europe and 

several electric utilities either have or are planning to install PM CEMS. Such general 

information does not establish the performance capabilities of PM CEMS and does not justify 

their use as compliance monitors for all industrial boilers over 250 MMBtu/hr. There are several 

significant issues with installing PM CEMS on multi-fuel boilers and biomass boilers commonly 

used in the forest products industry that need to be addressed before installation of such systems. 

To measure and report PM emissions in lb/MMBtu, boilers equipped with PM CEMSs would 

also have to install stack gas moisture monitors. EPA has not published any performance 

specifications for stack gas moisture monitors. In the absence of such specifications, the 

reliability of the results of PM CEMSs cannot be established. 

SCPPA recommends that prior to requiring the installation of CEMSs on biomass boilers and 

multi-fuel boilers, EPA should sponsor field studies to (1) establish performance specifications 

for stack gas moisture monitors, and (2) determine the accuracy and precision of PM CEMSs on 

biomass boilers and multi-fuel boilers, especially when load and fuel mix ratios are constantly 

changing. 

Response: See response to EPA-HQ-OAR-2002-0058-3213.1, Comment Excerpt Number 290. 

Commenter Name: David Bonistall

Commenter Affiliation: NewPage Corp

Document Control Number: EPA-HQ-OAR-2002-0058-2920.1
161

Comment Excerpt Number: 5

Comment: We believe the framework already exists in the rule to ensure sufficient monitoring is 

performed for a TSM alternative standard. The proposed rule [75 FR 32056, §63.7530(b)] 

contains procedures for determining initial compliance with mercury and hydrogen chloride 

through stack testing and fuel analysis. This approach could be easily adapted for a TSM 

standard as well. The proposed rule [75 FR 32056, §63.7540(a)(2)] also contains procedures for 

determining continuous compliance with mercury and hydrogen chloride and could be adapted to 

TSM. If a source selects the TSM alternative, there would not be the need to continuous monitor 

PM emissions. While the TSM alternative may entail increased costs for stack testing and fuel 

analysis, the costs associated with the initial installation and on-going maintenance and 

manpower support for a PM continuous monitor will not be incurred. 

Response: EPA has not included a TSM standard in the final rule, so this monitoring approach 

is not applicable.

Commenter Name: John W. Fainter, Jr.

Commenter Affiliation: Association of Electric Companies of Texas

Document Control Number: EPA-HQ-OAR-2002-0058-2790.1

Comment Excerpt Number: 12

Comment: Oppose particulate matter (PM) Continuous Emissions Monitors (CEMS) to 

demonstrate continuous compliance 

EPA’s proposal to use PM CEMS is seriously flawed, First, EPA provides no PM CEMS data to 

support any of its proposed requirements or averaging times. Nor does EPA provide any analysis 

to justify use of stack test data to set a proposed PM CEMS standard, While averaging time can 

be used to compensate for variability not seen in individual stack tests, that adjustment cannot be 

made by simply arbitrarily selecting a longer period (e.g,, daily or monthly). Nor is that 

adjustment sufficient to compensate for the differences between the methods themselves 

(Method 5 and PM CEMS). Second, EPA has failed to consider the limitations of PM CEMS in 

measuring emissions during periods of SSM, which are not conditions under which the PM 

CEMS are correlated. Third, EPA has failed to consider whether PM CEMS can be correlated 

under PS 11 at the levels of EPA’s proposed standards (or whether PM (I’1’..MS can even 

measure such low levels). 

In short. EPA has not provided sufficient support for its proposal to use PM CEMS, let alone to 

require their use to make compliance determinations. Even if a source could meet EPA’s PS 11 

correlation criteria at all of the levels EPA has proposed, there is no evidence that EPA’s 

proposed standards sufficiently compensate for the permissible measurement error or for data 

collected during SSM. 

Response:
162

See the response to EPA-HQ-OAR-2002-0058-3179, Comment Excerpt Number 7.

Also, on the sensitivity issue, related to precision and accuracy, we disagree that measurements 

made near the emissions limits are indistinguishable from zero. Modern light scatter devices 

(e.g., the Durag D-R 300-40 at http://www.ppmsystems.fi/files/d-r-300-40.pdf and the Sigrist 

StackGuard monitor at

http://www.photometer.com/en/products/details/features.html?productid=249)

can detect very low concentrations including in the microgram/m3 range.

These devices can also satisfy the relative accuracy requirements in

PS11 at those levels (e.g., with longer PM test runs for reference method PM mass sampling).

On the accuracy issue, we understand and appreciate the effect of measurement uncertainty, 

including the effects of uncertainty inherent in the PM CEMS calibration output, in establishing 

the applicable limits and in determining compliance.. As discussed in responses to other 

comments about establishing the applicable emissions limits, we considered and accounted for 

these uncertainties in applying statistically based confidence factors (i.e., the UPL calculations) 

using the emissions data developed in support of the rule. Once those emissions limits are 

established, it is agency policy that determinations of compliance are to be based on 

measurements conducted with the prescribed procedures including meeting all of the control 

quality assurance and quality control requirements without further adjustment.

Also see the preamble for revised treatment of SSM. Process upsets are not part of "normal 

operations" as per PS-11, therefore the facility would not have try to capture that emission level 

for the correlation testing. 

Commenter Name: Douglas A. McWilliams

Commenter Affiliation: American Municipal Power

Document Control Number: EPA-HQ-OAR-2002-0058-2808.1

Comment Excerpt Number: 28

Comment: The Proposed Rule requires all boilers with a heat input capacity equal to or greater 

than 250 mmBtulhr that combust coal, biomass, or residual oil to install and maintain continuous 

emission monitors for particulate matter ("PM CEMs"). EPA provided no explanation for this 

monitoring requirement whatsoever, instead merely stating that "requiring PM CEMs . . . is a 

reasonable monitoring option." 75 Fed. Reg. at 32033. EPA is mistaken. The cost of this 

monitoring equipment, its redundancy to monitoring systems already in place, and the 

demonstrated inaccuracy of PM CEMs makes EPA’s inclusion of PM CEMs as required 

monitoring equipment unreasonable and arbitrary. 

EPA’s lack of justification is particularly disturbing since most boilers in the source 

category are already equipped NArith continuous monitoring equipment for particulate matter 

control devices. Boilers of this site that operate particulate matter control devices are subject to 

the Compliance Assurance Monitoring ("CAM") rule at 40 C.F.R. Part 64. This rule requires 

continuous monitoring sufficient to ensure proper control device operation. Adding a PM CEMS 
163

is redundant and unnecessary. AMP’s municipal utilities also have continuous operating 

monitoring ("COM") systems that monitor PM control device performance. COMs monitor 

particulate matter in flue gas streams by sending a beam of light through the flue gas and 

measuring the attenuation caused by particles in the flue gas. Electric Power Research Institute, 

Status of Particulate Matter Continuous Emission Monitoring Systems 2-1 (Mar. 2006). Certain 

PM CEMs use a similar light absorption technique, or other optical techniques, to generate PM 

readings. Id. EPA has relied on COMs readings, combined with periodic stack testing, to monitor 

compliance with PM limits for decades. Regulated units have already installed this equipment 

and are familiar with its maintenance and operation. EPA is now attempting to require a PM 

CEM, in addition to COMs that are already installed, in addition to annual PM stack testing, 

without offering any explanation for why the additional PM CEMs are necessary. This is an 

unreasonable and arbitrary burden on municipal utilities without any environmental benefit. 

Response: These monitoring requirements are specifically designed to ensure continuous 

compliance with hazardous air pollutant standards,and thus by their nature may be expected to 

require compliance investments, including monitoring, beyond existing requirements such as the 

CAM rule. The PM CEMS requirements only apply to a subset of the larger units. Also annual

stack testing is not required in addition to PM CEMS for those units.

Commenter Name: J. Michael Geers

Commenter Affiliation: Duke Energy

Document Control Number: EPA-HQ-OAR-2002-0058-2765.1

Comment Excerpt Number: 33

Comment: In Cases Where EPA is Mandating the Use of PM monitors, it Should Give Sources 

the Ability to Delete Opacity Monitoring Requirements 

In cases where PM monitoring is required, Duke Energy strongly recommends that EPA 

allow sources with current opacity monitoring requirements to supersede those requirements 

where they are required to install PM monitors. The source need simply demonstrate that the new 

particulate limit is more stringent than the existing opacity limits. Duke Energy feels that this is 

an excellent example of regulatory flexibility. Moreover, sites should not be put in a position of 

“double jeopardy” by having to measure and report against both. 

Response: Under this subpart, if a PM CEMS applies, no separate opacity standard will apply. 

As for other federal and state standards that may independently require compliance with an 

opacity limit, this rule does not automatically render those requirements superfluous. As part of 

the permitting process under Title V, EPA has issued guidance on streamlining applicable

requirements (see “White Paper Number 2 for Improved Implementation of The Part 70 

Operating Permits Program,” dated March 5, 1996). EPA does not suggest that all opacity limits 
164

could be streamlined because of the PM CEMS requirements in this rule, but does believe that 

the permit process is the appropriate venue for addressing these issues.

Commenter Name: David Foerter

Commenter Affiliation: Institute of Clean Air Companies

Document Control Number: EPA-HQ-OAR-2002-0058-2937.1

Comment Excerpt Number: 44

Comment: There are several types of PM emissions measuring techniques that may be applied 

to industrial boilers depending on the specific application. One PM CEMS technology, beta 

attenuation based systems, can be used for both wet and dry stack situations and the installed 

costs are in the range from $120,000 to $140,000. PM CEMs have been applied to coal-fired 

power plants with almost a dozen systems installed to date and more than a dozen required at 

recently permitted boilers. PM CEMs have also been applied to pulp mill recovery boilers with 

one application having three years of data, and also applied to incinerators with one application 

having two years of operating data. A second PM measurement technology, optical-based 

technology, uses a light scattering technology for dry stacks and the installed costs are 

approximately $25,000 for the equipment and another $20,000 – $40,000 to perform the stack 

test that develops the correlation curve to match instrument readings to the amount of particulate 

emissions. 

PM CEMS technology development is ongoing, therefore, ICAC recommends EPA look to a 

future study by the Electric Power Research Institute (EPRI) that will compare the performance 

of the PM CEMS technologies in a wet stack environment. The technologies to be evaluated 

include: beta attenuation, optical based and a hybrid technology using Taper Element Oscillation 

Microbalance (TEOM) and light scattering. The study is expected to being September 2010. 

Response: Thank you for the information.

Commenter Name: Chris M. Hobson

Commenter Affiliation: Southern Company

Document Control Number: EPA-HQ-OAR-2002-0058-2741.1

Comment Excerpt Number: 66

Comment: RMB does not believe the use of a PM CEMS as a compliance monitor is 

appropriate due to technical concerns regarding monitor calibration and the ability to produce 

representative measurements during periods of boiler startup, shutdown, or malfunction. Unlike 

other types of CEMS, PM CEMS do not provide direct measurement of PM but rather an 

indication of PM measurement that must be calibrated to reference method measurements. 

Therefore, PM CEMS output is subject to the limitations of the calibration procedures and the 

inherent limitations of the measurement technology. Performance Specification 11 (PS-11), 

which is the performance specification for calibrating and certifying the monitor in the proposed 
165

rule, includes relatively generous [Footnote: PS-11 statistical criteria: (1) the confidence interval 

(95%) half range at the median PM CEMS response value must be within 10% of the PM 

emission limit value and (2) tolerance interval half range at the median PM CEMS response 

value must have 95% confidence that 75% of all possible values are within 25% of the PM 

emission limit value.] statistical performance criteria that results in considerable potential for 

reporting “false positives” (i.e., reporting emission violations that are the result of instrument 

measurement error). In addition, RMB does not believe that PM CEMS can provide 

representative measurements over the entire range of boiler operation, which would be required 

for demonstrating continuous compliance with emissions standards that exclude periods of 

startup, shutdown, and malfunction. These periods of operation result in transient flue gas 

conditions causing changes in particle density, morphology, size distribution or stratification of 

PM within the flue are not reflected in the calibration of the instrument. 

Due to these technical concerns, RMB recommends that EPA remove the requirement for the 

installation and use of PM CEMS as the continuous compliance determination method for coal-, 

biomass-, and residual oil-fired sources with heat input ratings greater than 250 mmBtu/hr. 

Alternatively, sources could demonstrate a reasonable assurance of compliance based on opacity 

or parametric monitoring as EPA has already proposed for those units with heat input ratings < 

250 mmBtu/hr. EPA could allow the installation and operation of a PM CEMS as an option for 

all sources, which is consistent with approach taken in the recent revisions to NSPS Subpart Da. 

However, in this case, RMB would recommend increasing the compliance averaging time (i.e. 

30-day rolling average) in order to mitigate some of the effects of startup/shutdown. 

Response: See the response to EPA-HQ-OAR-2002-0058-2913.1, Comment Excerpt Number 

17.

Commenter Name: Chris M. Hobson

Commenter Affiliation: Southern Company

Document Control Number: EPA-HQ-OAR-2002-0058-2741.1

Comment Excerpt Number: 68

Comment: The proposed rule specifies that sources that are required to install and operate a PM 

CEMS must also install and operate a continuous opacity monitoring system (COMS), a bag leak 

detector (for units with a fabric filter) or implement parametric monitoring of the control device. 

Sources that install a PM CEMS should not be required to provide further assurance of 

compliance with the PM standards. Such additional monitoring is redundant and creates an 

unnecessary burden on these sources. 

Response: The final rule clarifies that units with PM CEMS do not have to meet the opacity or 

other operating limit monitoring requirements.
166

Commenter Name: Chris M. Hobson

Commenter Affiliation: Southern Company

Document Control Number: EPA-HQ-OAR-2002-0058-2741.1

Comment Excerpt Number: 73

Comment: Section 63.7525(b)(6) states: “When PM emissions data are not obtained because of 

CEMS breakdowns, repairs, calibration checks, and zero and span adjustments, emissions data 

shall be obtained by using other monitoring systems as approved by the Administrator or EPA 

Reference Method 19 of appendix A of 40 CFR part 60 to provide, as necessary, valid emissions 

data for all operating hours per 30-day rolling average.” 

First, the requirement to have “valid emissions data for all operating hours” is unrealistic. 

It should be noted that Section 60.48(p) of Subpart Da, 40 CFR Part 60 provides the 

owner/operator the option to use PM CEMS to determine compliance with the PM emission 

limit. 60.48Da(p)(5) specifies that at minimum, valid CEMS hourly averages shall be obtained 

for 75 percent of all operating hours on a 30-day rolling average basis. 

Beginning on January 1, 2012, valid CEMS hourly averages shall be obtained for 90 percent of 

all operating hours on a 30-day rolling average basis.” 

Section 63.7525(b)(6) should be revised as follows: “When PM emissions data are not obtained 

because of CEMS breakdowns, repairs, calibration checks, and zero and span adjustments, 

emissions data shall be obtained by using other monitoring systems as approved by the 

Administrator or EPA Reference Method 19 of appendix A of 40 CFR part 60 to provide, as 

necessary, valid emissions data for a minimum of 90 percent (only 75 percent is required prior to 

January 1, 2012) of all operating hours per 30-day rolling average.” 

Response: &&& See the response to EPA-HQ-OAR-2002-0058-2997.1, Comment Excerpt 

Number 9.

Commenter Name: Chris M. Hobson

Commenter Affiliation: Southern Company

Document Control Number: EPA-HQ-OAR-2002-0058-2741.1

Comment Excerpt Number: 75

Comment: Section 63.7540(a)(9)(ii) states: “During each PM correlation testing run ..., PM and 

O2 (or CO2) data shall be collected concurrently (or within a 30- to 60-minute period) by both 

the CEMS...” RMB notes that only PM CEMS that currently measures PM emissions on a drybasis is the Mechanical System, Inc. Beta-Guard. The rule does not address procedures for 

correcting dry O2 data from a straight-extractive CEMS to a wet basis to calculate PM mass 

emissions in conjunction with a PM CEMS that measures PM concentrations on a wet basis. 
167

Response: We agree that assuring that measured pollutant and flow data must be corrected for 

moisture content for the calculation of emissions in units of the applicable standard. We note that 

40 CFR part 60, appendix B, Performance Specification 2 (PS2) and other CEMS performance 

specifications that refer to PS2 highlight the need to correct measured data for moisture in order 

to calculate relative accuracy and also provides the calculations to do so. Section 12 of PS2 (and 

section 12 of 40 CFR part 60, appendix A, Method 19) provide calculation procedures for most 

typical calculation and measurement scenarios. That said, PS2 does not require a separate 

demonstration of the accuracy of a moisture determination but instead relies on the relative 

accuracy requirements and associated limitations expressed in units of the standard to assure that 

a moisture correction is accurate. We recognize that there are technologies for measuring 

moisture and the source owner may choose to use such technology. We also recognize that the 

moisture content of exhaust gases for many processes are nearly constant (e.g., downstream of 

combustion processes) allowing the use of a calculation constant rather than constant direct 

measurement. There are many examples of CEMS data management systems that apply sitespecific constant moisture values (e.g., established during emissions testing) that continue to pass 

relative accuracy testing and provide reliable emissions data. We believe that the comprehensive 

structure of PS2 and follow-up quality assurance procedures are adequate for this purpose and 

there is no need for an independent accuracy check of a moisture measurement.

Commenter Name: Jim Eubank

Commenter Affiliation: Kentucky Division of Air Quality

Document Control Number: EPA-HQ-OAR-2002-0058-3176.2

Comment Excerpt Number: 17

Comment: 40 CFR 63.7510(d) requires that certain boilers or process heaters demonstrate initial 

compliance using PM CEMS. Other sources should be allowed to demonstrate compliance using 

PM CEMS if they choose. While PM CEMS may be too expensive for smaller sources today, it 

is possible that PM CEMS may one day be less expensive than stack testing. 

Response: We agree that a PM CEMS installed and operated in accordance with Performance 

Specification 11 and the associated quality assurance procedures can provide assurance of 

ongoing compliance without the need for additional continuous or periodic compliance testing. 

The final rule reflects this provision, applying only PM CEMS to large units . For other units, the 

source could use the alternative monitoring under the general provisions to seek this type of 

alternative.

Commenter Name: Sheila C. Holman

Commenter Affiliation: North Carolina Department of Environment and Natural Resources

Document Control Number: EPA-HQ-OAR-2002-0058-2798.1

Comment Excerpt Number: 33

Comment: We agree with the proposal use of PM CEMs. With plans to add more, there are 3 

Pm CEMs currently installed and operating on coal-fired utility boilers controlled by ESPs and 
168

FGD scrubbers. It is true that the NC utilities have a favorable PM CEM experience-over 98.55 

data availability. In general, the capability of PM CEMs to measure accurate data based on 

compliance with Performance Specification 11 requirements is good. 

Response: Thank you for the information and support.

Commenter Name: Michael L. Corvese

Commenter Affiliation: Thermo Fisher Scientific, Inc

Document Control Number: EPA-HQ-OAR-2002-0058-2997.1

Comment Excerpt Number: 1

Comment: These regulations for boilers and process heaters (together with the certain heat 

recovery units regulated under the concurrently proposed rules for Commercial and Industrial 

Solid Waste Incineration Units [Federal Register Vol. 75, No. 107 June 4, 2010]), if 

promulgated, would be the first EPA regulations to require PM CEMS and would affect many 

sources. There is a need to address technical problems that have been encountered with PM 

CEMS and improve efficiency in implementation such regulations that are not addressed by the 

proposed regulations. 

EPA’s work to develop Performance Specification 11 (PS11) and Appendix F, Procedure 2 was 

based on the evaluation of light scattering devices, beta attenuation monitors and other inferential 

measurement devices that cannot directly measure PM concentration. Hence the approach 

adopted in Procedure 2 (as with European requirements such as EN14181) requires the 

development of a PM CEMS calibration by performing a large number of PM tests using 

conventional methods and creating a correlation with the PM measuring device through 

regression analysis. To accomplish this, it is necessary that PM concentrations over a fairly wide 

range be tested, and that very careful PM tests are performed to reduce test method imprecision, 

especially at very low concentrations. Problems in achieving the initial correlation requirements 

of PS11 have been widely reported by representatives of the electric utility industry where PM 

CEMS have been required through consent decrees and enforcement actions at a limited number 

of sources. These problems include: 

Difficulty in generating sufficient PM and range of PM concentrations from well controlled 

sources for establishing correlations. 

Necessity for non-representative air pollution control device operations (such as turning off ESP 

fields, bypassing scrubbers, by-passing fabric filters) which would never be allowed to occur by 

the source operators at any other time. 

Limitations of reference methods, particularly at low concentrations, resulting in the need to 

conducted paired test runs to minimize imprecision and repeat correlation test attempts. 
169

Inability to assess potential changes in PM characteristics (i.e., particle size distribution, 

refractive index, particulate density etc.) which result from creating unusual source operating 

conditions necessary to generate the PM concentration range on the resulting correlation. 

Insufficient history to establish PM correlation stability over time 

Inability for the source operator to know if PM characteristics have changed over time and the 

associated affect on the PM CEMS accuracy. 

The above problems reduce the reliability and increase the uncertainty of the PM monitoring data 

that are obtained, increase the costs for performing the initial certification of the monitoring 

device, and have been the cause for much frustration and objections to PM CEMS. These 

problems will become more severe at the very strict proposed PM emission limits for boilers and 

process heaters, (e.g., 0.001 lb/MMBtu for new coal fired units and 0.02 lb/MMBtu for existing 

coal fired units.) 

Response: See the response to EPA-HQ-OAR-2002-0058-2913.1, Comment Excerpt Number 

17.

Commenter Name: Michael L. Corvese

Commenter Affiliation: Thermo Fisher Scientific, Inc

Document Control Number: EPA-HQ-OAR-2002-0058-2997.1

Comment Excerpt Number: 2

Comment: We are in the process of developing a Hybrid PM CEMS design to address many of 

the technical issues that have been encountered. [EUEC presentation, February 2010.] [SES 

conference presentation, March 2010.] [EPRI presentation, May 2010.] Although the design 

continues to evolve, important aspects are: 

The extractive sampling system will present the same sample to two different design light 

scattering devices and a tapered element oscillating microbalance (TEOM). 

The TEOM provides a direct measurement of PM mass versus time, and together with 

measurement of the system sampling rate, PM concentration is determined without operator 

intervention. 

The TEOM is used periodically to calibrate each of the light scattering instruments, and at other 

times is “parked” to increase the time between maintenance intervals. 

The calibrated outputs of the light scattering devices provide on-going monitoring of the PM 

concentration. 
170

Because two different design light scattering devices are used, monitoring the ratio of their 

outputs signals potential changes in particle characteristics, such as particle size distribution, 

refractive index, etc. 

The TEOM can be activated to assess or recalibrate the output of the light scattering devices 

when the ratio of their outputs change, or periodically as a routine QA check, or when a new PM 

level is observed. 

• The extractive sampling system will have the capability for diluting and cooling the PM sample 

and have sufficient residence time to afford total PM measurement results equivalent to EPA 

CTM 039 and a scalable output equivalent to filterable PM as measured by EPA Method 5 or 17. 

The Thermo Scientific Hybrid PM CEMS includes three devices to sense PM concentration, and 

is considered self-validating because the TEOM is based on first principals of mass measurement 

and has already been demonstrated to provide results equivalent to EPA methods in another 

configuration. (See also Comment 4 below.) 

Advantages of the Thermo Scientific Hybrid PM CEMS are that it could: 

Alert operator to particle size, refractive index changes on ongoing basis (which may also be 

useful for process/control equipment assessment or corrective action). 

Implement self-validating calibration relative to internal TEOM, initially, periodically, and/or 

when particle characteristics change, and/or when new PM levels are experienced. 

Greatly improve accuracy and reliability of data because the TEOM is very sensitive, very 

precise, and the approach of comparing the TEOM directly to the light scattering devices avoids 

the imprecision associated with manual sampling and manual recovery/weighing of PM filters 

and PM residue. 

Eliminates the need to artificially create range of PM concentrations for initial certification 

correlation tests, or for periodic re-tests to assess correlation stability, because each PM level can 

be validated as it naturally occurs. 

Reduce costs, complexity and likelihood of failures for initial certification by eliminating much 

of the manual testing required to establish a correlation. 

Eliminate need to detune APCD and increase emissions during correlation tests raising 

compliance issues and potential for damages to APCD equipment. 

Reduce cost and complexity for on-going QA. 

Provide source operators with a direct means to check monitor at any time without the long 

delays for retaining and scheduling stack tests and waiting on results. 
171

Eliminate the need for supplemental testing for determining total PM for state permit emission 

limits. 

Response: Thank you for the information and support.

Commenter Name: Michael L. Corvese

Commenter Affiliation: Thermo Fisher Scientific, Inc

Document Control Number: EPA-HQ-OAR-2002-0058-2997.1

Comment Excerpt Number: 3

Comment: While we recognize EPA’s need to set standard methods and performance 

specifications, CEMS technology, and they may well constrain current and future development 

of better approaches. Therefore, EPA should: 

Include explicit language in the promulgated Boiler MACT regulations at section 

63.7541(a)(9)(i) such as: “... conduct a performance evaluation of the CEMS according to the 

applicable requirements in 60.13 and/or 63.8 and PS11 in Appendix B of 40 CFR part 60 or prior 

approved alternative procedures for advanced technologies and Procedure 2 in appendix F, or 

prior approved alternative procedures for advanced technologies.” 

Include a discussion of these issues in the preamble to the promulgated regulations to encourage 

development and use of advanced technologies which improve the quality and reliability of 

monitoring data and reduce the implementation cost and problems for industrial users. 

Establish guidance for the submission of information by developers and timely 

approval of alternative approaches by EPA to encourage technical development. 

We recognize that EPA will need sound technical information and results of field trials to 

establish the appropriate certification and QA requirements for alternative approaches or 

procedures. We will work with EPA representatives to determine what is required and will 

conduct the necessary technical evaluations and provide the information to EPA and the 

regulated community. 

Response: The agency appreciates the commenter's recommendations and will evaluate 

information on the alternative approaches suggested. For this rule, however, a source owner or 

operator required to do performance testing by a relevant standard may use an alternative test 

method from that specified in the standard, provided they meet the requirements of the 

alternative test provisions in Sections 63.7(f) or 63.8(f).

Commenter Name: Duane Mummert

Commenter Affiliation: South Carolina Chamber of Commerce Environmental Technical 

Committee
172

Document Control Number: EPA-HQ-OAR-2002-0058-3171

Comment Excerpt Number: 4

Comment: EPA’s requirement that PM CEMS should be used to demonstrate continuous 

compliance on all solid fuel boilers larger than 250 MMBtu/hr is arbitrary and not supported by 

any data. In the proposal EPA has stated that PM CEMS are used at a variety of sources in 

Europe and several electric utilities either have or are planning to install PM CEMS. Such 

general Information does not establish the performance capabilities of PM CEMS and does not 

justify their use as compliance monitors for all industrial boilers over 250 MMBtu/hr. There are 

several significant issues with installing PM CEMS on multi-fuel boilers and biomass boilers 

commonly used in the forest products industry that need to be addressed before installation of 

such systems. 

Response: See the response to EPA-HQ-OAR-2002-0058-2913.1, Comment Excerpt Number 

17.

Commenter Name: Michael L. Corvese

Commenter Affiliation: Thermo Fisher Scientific, Inc

Document Control Number: EPA-HQ-OAR-2002-0058-2997.1

Comment Excerpt Number: 4

Comment: Recommend that EPA approve and publish optional PM profile test procedures that 

can be used to evaluate the representativeness of candidate and actual PM CEMS sampling 

locations or detect the presence of PM concentration stratification. 

EPA guidance on conducting such tests would benefit industrial sources required to install PM 

CEMS and providers of PM CEMS monitoring equipment. This is practical necessity because all 

extractive systems and most in-situ light scattering devices obtain a sample at a point or sense the 

measurement parameter in a small region of the stack cross-section. Procedures that could be 

used before the PM CEMS is installed to evaluate the representativeness of candidate locations 

and/or demonstrate that PM concentration stratification does not exist could avoid potential 

failures of initial correlation tests resulting in the need to re-locate the PM CEMS and/or repeat 

the costly correlation test. Relying exclusively on the correlation test where measurements from 

a PM CEMS sampling at a single point are compared to the results of methods traversing the 

stack or duct cross-section provides no insight regarding the cause of a failed test (e.g., poor 

monitoring device, bad location, reference method problems, etc.). There is a need to separate 

vendor’s liabilities for proper measurement from plants responsibilities for its installation at a 

representative location. Vendors should not be asked to guarantee PM CEMS performance based 

on comparisons with traversing tests which confound potential temporal and spatial variations. 

In cases where a measurement location can be demonstrated to have no significant PM 

concentration stratification, the correlation testing can be simplified to single point sampling, 

which would allow for reduction in the amount of time to perform the test, reduction in the 
173

amount of air pollution emitted while performing the necessary tests at elevated PM 

concentrations, and reducing the costs of the test. (See also comment 3.) 

We understands that EPA removed suggestions and guidance regarding performing PM profile 

tests and requirements to relocate PM CEMS if failure of the correlation tests was due to 

stratification from the promulgated PS11 which were previously included in the proposed 

versions. However, EPA guidance or approval (and publication) of optional procedures would 

establish no new requirements for industrial users and would establish consistent basis for 

decisions and eliminate case-by-case decisions or individual state agency determinations. 

Response: Continuation of Document Control Number: EPA-HQ-OAR-2002-0058-2997.1. See 

response to Comment Excerpt Number: 3.

Commenter Name: Domtar Corp

Commenter Affiliation: Guy R. Martin

Document Control Number: EPA-HQ-OAR-2002-0058-2823.1

Comment Excerpt Number: 4

Comment: The issue of using a PM CEMS in a wet stack, especially following a wet scrubber, 

is problematic. The primary interference with measuring PM with a continuous monitor is the 

presence of water droplets in the stack. The water droplets, usually found in a stack following a 

wet scrubber system but also when wet fuels such as biomass are 

used, will impact all of the PM analytical technologies by appearing as a particulate to the 

monitor. 

Two primary methods for measuring PM in a wet stack use an extractive sampling system. This 

extractive sampling system is utilized with either the light scattering or Beta attenuation 

technology. One type of device draws a small sample from the stack, heats it in a cyclonic 

chamber (thermocyclone) to approximately 320°F to drop out large droplets and evaporate any 

smaller droplets, passes it through the standard light scattering cell and then returns it to the 

stack. This is all close coupled on the stack to avoid a heated sample line transporting hot, dirty, 

wet gases to an analyzer. 

Another type of device uses a dilution probe to extract the sample from the stack. In this 

extraction system accurately measured dilution air is introduced at right angles to the sample and 

then mixed with the sample in a turbulent mixing chamber. This simplifies the transport of the 

particulate sample. Diluting the sample with dry air raises the dew point preventing condensation 

in the sample line. The sample is then transported to the Beta attenuation monitor for analysis. 

[Footnote: Review and Evaluation of Particulate Matter Continuous Emission Monitoring 

Systems (May 2004, updated July 2010), RMT Inc.] 

Domtar recommends that prior to requiring the installation of CEMS on multi-fuel boilers, 

biomass boilers, or CISWI sources, EPA should sponsor field studies to (1) establish 
174

performance specifications for stack gas moisture monitors, and (2) determine the accuracy and 

precision of PM CEMS on biomass and multi-fuel boilers and CISWI sources. 

Response: See response to EPA-HQ-OAR-2002-0058-3213.1, Comment Excerpt Number 290. 

Commenter Name: Michael L. Corvese

Commenter Affiliation: Thermo Fisher Scientific, Inc

Document Control Number: EPA-HQ-OAR-2002-0058-2997.1

Comment Excerpt Number: 5

Comment: Recommend that EPA allow single point “reference method” sampling adjacent to 

PM CEMS sampling locations where the measurement location can be demonstrated to be nonstratified to reduce correlation testing costs and improve the accuracy and reliability of the 

monitoring data. 

The very strict emission limits in the proposed regulations ensure that sources are very well 

controlled (e.g., 0.001 lb/MMBtu for new coal fired units and 0.02 lb/MMBtu for existing coal 

fired units.). In order to comply with such limits, high efficiency control devices will remove 

essentially all of the large particles, resulting in effluent streams containing only small particles 

at the measurement location which remain well distributed and exhibiting uniform PM 

concentration. In view of this, single-point sampling using conventional EPA test methods or 

ASTM D6831-02 “Standard Test Method for Sampling and Determining Particulate Matter in 

Stack Gasses Using an In-Stack, Inertial Microbalance” could be performed to reduce the cost of 

the correlation test and improve the accuracy and reliability of the PM CEMS results. Support for 

this premise includes: 

Electric utility units required to install PM CEMS used extractive systems and in-situ light 

scattering devices that essentially sample a small area of the stack cross-section. Because these 

devices have been certified by PS11 in comparison to traversing methods, EPA must in fact 

conclude that the monitoring points selected were and are representative of the entire cross 

section PM concentration. 

Emission Monitoring Inc. has done PM stratification tests at electric utility units and other 

industrial sources with the Series 7000 TEOM and found no-indication of PM concentration 

stratification during many of these tests. 

Emission Monitoring Inc, Clean Air Engineering and other experienced testers have conducted 

test programs to evaluate opacity or optical density trigger levels for CAM plans and other 

applications using single-point sampling and comparison of concurrent data streams from TEOM 

and COMS or particulate matter detectors. Selecting periods of relatively constant PM 

concentration for comparison (absent spikes or other transients) results in excellent correlation 

coefficients greater than 0.95 because imprecision resulting from the manual method and batch 

sampling is eliminated. 
175

If the option of conducting a PM stratification test and single-point PM correlation testing is 

allowed as an alternative approach, adjustments to the correlation coefficients required by PS11 

could be applied to provide assurance to the EPA that the approach is justified. For example: 

If PM stratification test shows no variation, perform the PS 11 correlation with side-by-side 

testing and meet the 0.85 correlation coefficient requirements for all sources, including low 

emitters (0.75 required by PS11 for low emitters). 

If PM concentration stratification is less than 10%, meet tighter correlation coefficient of 0.90 

and apply a positive bias adjustment factor to account for any apparent stratification. 

If PM concentration stratification is less than 20%, meet tighter correlation coefficient of 0.95 

and apply a positive bias adjustment factor to account for any apparent stratification. 

The above optional alternative approach can: 

Reduce time required to perform correlation test but greatly expand the effective number of test 

runs. 

Reduce time required to operate plant at elevated PM concentrations, hence reduce pollution and 

reduce time required to operate above emission standard for purpose of establishing correlation. 

Significantly improve the correlation results and hence data reliability. 

Eliminate many of the detrimental effects due to imprecision of manual reference method, 

particularly at very low PM concentrations 

Save industry substantial costs and trouble from failed correlation attempts. 

Response: Continuation of Document Control Number: EPA-HQ-OAR-2002-0058-2997.1. See 

response to Comment Excerpt Number: 3.

Commenter Name: James C. Jackson

Commenter Affiliation: Boise, Inc

Document Control Number: EPA-HQ-OAR-2002-0058-2855.1

Comment Excerpt Number: 6

Comment: Boise is also strongly opposed to the use of PM CEMs for continuous monitoring of 

particulate matter compliance for solid fuel boilers. While PM CEMs may be in operation in the 

utility industry and in Europe, they are not proven compliance grade monitoring technology for 

industrial boilers in the United States. Boise’s boilers are subject to much operating variability in 
176

terms of steam load and fuel mix. It would be virtually impossible and prohibitively expensive to 

develop a correlation between actually stack PM emissions and PM CEMs results. This is 

particularly significant when one considers that the PM CEMs will be a compliance monitor. 

Response: See the response to EPA-HQ-OAR-2002-0058-2913.1, Comment Excerpt Number 

17.

Commenter Name: Jim Griffin

Commenter Affiliation: American Chemistry Council

Document Control Number: EPA-HQ-OAR-2002-0058-2792.1

Comment Excerpt Number: 172

Comment: In proposed section 63.7525 (b)(6) it is specified that when PM CEMS data are "not 

obtained because of CEMS breakdowns, repairs, calibration checks, and zero and span 

adjustments, emissions data shall be obtained by using other monitoring systems as approved by 

the Administrator or EPA Reference Method 19 of appendix A of 40 CFR part 60 to provide, as 

necessary, valid emissions data for all operating hours per 30-day rolling average." This is very 

different from the proposed CISWI rule which has specified valid data capture requirements in 

Section 60.2730 (n) (14). Even more confusing and conflicting, section 63.7535(b) of the 

proposed Boiler rule states "Except for monitor malfunctions, associated repairs, and required 

quality assurance or control activities (including, as applicable, calibration checks and required 

zero and span adjustments), you must monitor continuously (or collect data at all required 

intervals) at all times the affected source is operating." If the 100% data availability requirements 

for boilers is not changed, boilers with heat inputs >250 MMBtu would be forced to have 

duplicate PM CEMS systems so that emissions data are also available during calibration checks, 

and zero and span adjustments which are required daily. And, since two CEMS systems are 

required for normal operation, a redundant third CEMS will have to be installed for periods when 

one of the two systems malfunctions. 

EPA should change the proposed requirements language in section 63.7525 (b)(6) to what is 

required in proposed section 60.2730 (n)(14) for CISWI sources. 

Response: &&& See the response to EPA-HQ-OAR-2002-0058-2997.1, Comment Excerpt 

Number 9.

Commenter Name: Jim Griffin

Commenter Affiliation: American Chemistry Council

Document Control Number: EPA-HQ-OAR-2002-0058-2792.1

Comment Excerpt Number: 173
177

Comment: To measure and report PM emissions in lb/MMBtu, boilers equipped with PM 

CEMS would also have to install stack gas moisture monitors. EPA has not published any 

performance specifications for stack gas moisture monitors. In the absence of such 

specifications, the reliability of the results of PM CEMS cannot be established. 

We recommend that prior to requiring the installation of CEMS on multi-fuel boilers, biomass 

boilers, or CISWI sources, EPA should sponsor field studies to (1) establish performance 

specifications for stack gas moisture monitors, and (2) determine the accuracy and precision of 

PM CEMS on biomass and multi-fuel boilers and CISWI sources. 

Response: See response to EPA-HQ-OAR-2002-0058-3213.1, Comment Excerpt Number 290.

Commenter Name: Jim Griffin

Commenter Affiliation: American Chemistry Council

Document Control Number: EPA-HQ-OAR-2002-0058-2792.1

Comment Excerpt Number: 174

Comment: Absent the questions about the feasibility of installing PM CEMS on biomass and 

multiple fuel boilers, we believe that these monitors are not necessary, given the annual PM 

testing requirements and continuous parametric and opacity monitoring. If PM CEMS remain a 

rule requirement for larger boilers, the averaging period should be increased to 30 days, similar 

to the averaging period for sources installing CO CEMS. As stated in the discussion elsewhere in 

these comments regarding averaging times and SSM, it will be difficult for sources to meet 24-

hour block average limits when operational variability and SSM are considered. 

Response: The final rule includes a 30-day rolling averaging period. EPA believes that the 

combination of parametric monitoring and CEMS requirements depending on boiler size is a 

reasonable approach to ensuring continuous compliance with the standards. 

Commenter Name: Jim Griffin

Commenter Affiliation: American Chemistry Council

Document Control Number: EPA-HQ-OAR-2002-0058-2792.1

Comment Excerpt Number: 240

Comment: In the proposed section 63.7525(b), EPA specifies that a PM CEMS must be 

installed on all coal, biomass and residual oil boilers and process heaters that are more than 250 

MM Btu/hr. The Agency also requires at section 63.7525(c) that a COMS must be installed on 

all boilers and process heaters that are have an opacity requirement. Proposed Table 4 requires 

that 10% opacity must be met by any unit using a dry electrostatic precipitator (ESP). Requiring 

these two monitors on units >250 MMBtu/hr and using an ESP is redundant since they are 

indicators of emissions of the same pollutant, particulate matter, and it makes no sense to require 
178

both on the same unit. We recommend that this redundancy be eliminated by requiring only one 

continuous monitor. 

In the proposed section 63.7525(b), EPA specifies that a PM CEMS must be installed on all coal, 

biomass and residual oil boilers and process heaters that are more than 250 MM Btu/hr. The 

Agency also requires in section 2.a and 2.b of Table 4 that units using a fabric filter as a control 

install either a bag leak detection system or COMS. Again, it is redundant to require both a PM 

CEMS and COMS for large units. We recommend that this redundancy be eliminated by 

requiring only one continuous monitor. 

Response: Table 4 in the final rule clarifies that opacity requirements do not apply for boilers 

that must use a PM CEMS.

Commenter Name: James C. Jackson

Commenter Affiliation: Boise, Inc

Document Control Number: EPA-HQ-OAR-2002-0058-2855.1

Comment Excerpt Number: 7

Comment: The PM standard was developed using stack tests, it is imperative that the 

compliance demonstration method be comparable; i.e, stack testing. Parametric monitoring (e.g., 

opacity, voltage, current, etc.) for continuous PM compliance demonstration should be adopted 

in the final rule in lieu of a PM CEMS. 

Response: See the response to EPA-HQ-OAR-2002-0058-3179, Comment Excerpt Number 7.

Commenter Name: Lee B. Zeugin

Commenter Affiliation: Utility Air Regulatory Group

Document Control Number: EPA-HQ-OAR-2002-0058-2880.1

Comment Excerpt Number: 91

Comment: Proposed section 63.7525(b)(3) states, compliance with the applicable emission limit 

shall be determined based on the 24-hour daily (block) average of the hourly arithmetic average 

emission concentrations using the continuous monitoring system outlet data. This is totally 

unacceptable and certainly has not been demonstrated to be achievable on any one of several 

levels. It is also inconsistent with a statement in the preamble, which states . . . we are proposing 

that PM CEMS be installed and operated and that PM levels (monthly average) be maintained 

below the applicable PM limit." 

It is not at all certain that the proposed PM emission limits are continuously achievable. After all, 

the numerical limits are based on snapshot tests, and we question whether long-term variability is 

accurately reflected in EPA’s standard setting approach. Perhaps more importantly, the 
179

rulemaking record contains no analysis in which EPA purports to equate the snapshot PM stack 

testing data to continuous PM CEMS data. For example, EPA might be able to show that the 

numerical limit, which is enforced through periodic stack testing, would be of the same 

stringency as the limit enforced with continuous data on a 30-day rolling average basis. 

Response: The final rule clarifies that, if a PM CEMS applies, then compliance is determined 

on a 30-day rolling average basis.

COMS (opacity)

Commenter Name: Norbord Industries

Commenter Affiliation: Norbord Industries

Document Control Number: EPA-HQ-OAR-2002-0058-0854.1

Comment Excerpt Number: 3

Comment: One Norbord facility with a dry ESP that is currently well below the proposed PM 

standard frequently has opacity levels above 10% mainly due to the high percentage of moisture 

in the gas stream. Subsequently it has been found that PM CEMs will likely not be effective at 

this facility. 

Norbord suggests that an exception to the 10% opacity limit be accepted when stack test results 

coupled with opacity results show the opacity standard could not be achieved (assuming PM 

emissions below the limit). 

Response: The general provisions to Part 63 allow for sources to establish an alternative opacity 

limit to address site-specific issues.

Commenter Name: Michael Palazzolo

Commenter Affiliation: Alcoa Inc

Document Control Number: EPA-HQ-OAR-2002-0058-2967.1

Comment Excerpt Number: 11

Comment: EPA should clarify in §63.7525(c) that an opacity meter is only required for an 

applicable opacity operating limit "under this subpart" 

All boilers and process heaters have opacity operating limits under State SIPs and the current 

language in §63.7525(c) could be interpreted to require an opacity meter for all of these 

combustion units. We therefore request that EPA revise §63.7525(c) as follows to clarify the 

opacity monitoring requirement: 

(c) If you have an applicable opacity operating limit under this subpart, you must install, operate, 

certify and maintain each continuous opacity monitoring system (COMS) according to ... 
180

Response: The final rule addresses this concern.

Commenter Name: Arthur N. Marin

Commenter Affiliation: NESCAUM

Document Control Number: EPA-HQ-OAR-2002-0058-2893.1

Comment Excerpt Number: 28

Comment: It is our understanding that the proposed rules require installing an opacity monitor, 

if any facility installs an ESP in order to meet a 10% opacity limit on a daily basis, with no de 

minimus threshold. Additionally, if a facility installs a fabric filter, it would be required to install 

an opacity monitor or a broken bag leak detector, with no de minimus threshold. We recommend 

that EPA require opacity monitors only on units larger than 30 mmBtu/hr. 

Response: The proposed requirement referenced by the commenter is for units burning coal, 

biomass, or residual fuel oil with heat input capacities less than 250 mmBtu/hr, and do not use a 

wet scrubber. EPA disagrees with the commenter. Opacity levels can be an indicator of good 

emissions control device operation for pollutants such as particulate matter and associated 

hazardous metal hazardous metals. Continuous opacity values are one way to provide the 

information necessary to demonstrate compliance on a continuous basis. PM CEMS, a 

preapproved alternative monitoring provision already included in the proposed rule, provides 

another way to demonstrate compliance without needing to collect COMS or control equipment 

parametric monitoring data. 

Commenter Name: Donald R. Schregardus

Commenter Affiliation: Department of Defense

Document Control Number: EPA-HQ-OAR-2002-0058-2763.1

Comment Excerpt Number: 30

Comment: The proposed rule defines opacity as the degree to which emissions reduce the 

transmission of light and obscure the view of an object in the background but does not further 

define the allowable method(s) for determining opacity. 

ASTM method D7520-09 "Standard Test Method for Determining the Opacity of a Plume in the 

Outdoor Ambient Atmosphere" was shown to be equivalent to EPA Method 9 "Visual 

determination of the opacity of emissions from stationary sources" during field tests of the new 

method by ASTM. ASTM method D7520-09 employs the use of a Digital Camera Opacity 

Technique (DCOT) that consists of a digital still camera and analysis software to obtain and 

interpret digital images to determine and report plume opacity. 

This comment is in accordance with the EPA’s Emission Measurement Center Guideline 

Document "Handling Requests for Approval of Minor/Major Modifications/Alternatives to 

Testing and Monitoring Methods or Procedures" (GD-022R3). It also supports the requirements 

of The National Technology Transfer and Advancement Act (NTTAA) 
181

http://standards.gov/standards.gov/nttaa.cfm,Section 12, item 3, enacted in March 1996. The 

NTTAA directs Federal agencies with respect to their use of private sector standards and 

conformity assessment practices. The objective is for Federal agencies to adopt private sector 

standards, wherever possible, in lieu of creating proprietary, non-consensus standards. 

EPA should specify the use of ASTM Method D7520-09 as an equivalent or alternative to EPA 

Method 9 for any opacity requirements associated with this standard. 

Response: EPA is still in the process of reviewing ASTM D7520-09. Source wishing to use 

this method may apply for an alternative monitoring methodology per Section 63.8(f).

Commenter Name: Chris Greissing

Commenter Affiliation: Industrial Minerals Association

Document Control Number: EPA-HQ-OAR-2002-0058-2740.2

Comment Excerpt Number: 19

Comment: Existing COMS Systems. The requirement of CEMS will require sources to impose 

additional, unnecessary equipment. Soda ash companies already employ continuous opacity 

monitoring systems (COMS) as an NSPS requirement. EPA states“... in developing the proposed 

rule, we considered the monitoring requirements, testing requirements, and recordkeeping 

requirements of the NSPS to avoid duplicating requirements.” 75 Fed. Reg. 32011. Mandating 

PM CEMS for those sources that already have a COMS will indeed result in duplicating 

monitoring requirement for particulate emissions. 

Response: EPA did attempt to avoid creating unnecessary duplication. However, the standards 

under this part have their own continuous compliance needs. For the operations and facilities 

subject to the rule, we believe that the combination of periodic compliance emissions testing and 

continuous monitoring of operational and parametric control measure conditions is appropriate 

for assuring ongoing compliance for most units. For large boilers, we have required use of a PM 

CEMS. The costs and burdens of these requirements are included in the impact assessments 

conducted for this rule, and are part of compliance costs that EPA has found to be reasonable for 

the affected sources.

Commenter Name: William R. Ermatinger

Commenter Affiliation: Northrop Grumman

Document Control Number: EPA-HQ-OAR-2002-0058-2506.1

Comment Excerpt Number: 26

Comment: The requirement to measure and control opacity to less than 10% (daily average) is 

redundant to results obtained from a properly operating boiler. In addition opacity does not 

directly correlate with the mass emission rate of particulate matter (PM) or of any of the HAPs 

intended to be regulated under the Boiler MACT. All states and some localities have enforceable 
182

opacity limitations, and in many cases the opacity limits are less than the 10% proposed by EPA. 

The regulation of opacity is not germane to the regulation of HAP emissions, should be removed 

from the Boiler MACT, and should be left to the states and localities already having jurisdiction. 

Response: EPA disagrees with the commenter. Opacity levels can be an indicator of good 

emissions control device operation for pollutants such as particulate matter and associated 

hazardous metal hazardous metals. Continuous, low cost, parametric monitoring, supplemented 

by continuous opacity values, is one way to provide the information necessary to demonstrate 

compliance on a continuous basis. PM CEMS, a preapproved alternative monitoring provision 

already included in the proposed rule, provides another way to demonstrate compliance without 

needing to collect COMS or control equipment parametric monitoring data. 

Commenter Name: Pamela F. Faggert

Commenter Affiliation: Dominion

Document Control Number: EPA-HQ-OAR-2002-0058-2908.1

Comment Excerpt Number: 26

Comment: To the extent a general requirement for COMS is retained for these larger units in the 

final rule, EPA should allow the decision to require COMS to the discretion of the state 

regulators for limited-use (low capacity factor) units. 

Response: Limited-use units are subject only to a biennial tune-up requirement as a work 

practice standard, and COMS are not required for such units under this subpart.

Commenter Name: Chris M. Hobson

Commenter Affiliation: Southern Company

Document Control Number: EPA-HQ-OAR-2002-0058-2741.1

Comment Excerpt Number: 62

Comment: EPA has specified the use of a continuous opacity monitoring system (COMS) with 

an opacity operating limit of 10% (based on a daily block average) for sources combusting coal, 

biomass, or residual fuel oil with a heat input capacity less than 250 mmBtu/hr. While the 

proposed 10% limit might be suitable as a default value, EPA should allow sources the option of 

establishing an alternative opacity operating limit for those sources than can not meet the 

proposed limit due to stack size or fuel-related issues. This would also allow some sources 

additional operating flexibility while still providing a reasonable assurance of compliance with 

the underlying emission limits. 

Response: The Part 63 general provisions allow a source to request an alternative opacity limit 

based on site-specific issues.
183

Commenter Name: David O'Keefe

Commenter Affiliation: USEC, Inc

Document Control Number: EPA-HQ-OAR-2002-0058-3122

Comment Excerpt Number: 11

Comment: Opacity limit. The proposed 10 percent opacity limit is more stringent than the 

typical 20 percent limit under Title V permits and should be set at the 20 percent limit. The 

lower limit creates a situation where there are two limits for the same parameter. Conflict with 

state regulations and SIP plans may occur as a result. 

There seems to be no basis for a 10 percent opacity limit. Opacity is a surrogate for particulate 

matter (PM) emissions. The proposal already contains operating parameter limits to ensure the 

PM emission limit is not exceeded. If the 10 percent opacity limit is retained, requirements for 

establishment of parameter operating limits should be removed. 

Response: The 10 percent opacity limit applies on a 24-hour block average and thus is not 

directly comparable to many other standards that may require a 20 percent standard on a 6-

minute basis. Table 4 in the final rule clarifies that when opacity monitoring is required, other 

operating parameter limits do not apply.

Commenter Name: Lee B. Zeugin

Commenter Affiliation: Utility Air Regulatory Group

Document Control Number: EPA-HQ-OAR-2002-0058-2880.1

Comment Excerpt Number: 35

Comment: Under EPA’s proposal, units that do not use a wet scrubber (e.g., units with no 

controls or with a dry scrubber) must comply with an opacity limit of 10 percent based on a daily 

block average. Proposed § 63.7500(a)(2) and Tables 4 and 8.[ Source owners/operators can apply 

to the Administrator for approval of an “alternative opacity emission limit” under 40 C.F.R. § 

63.6(h)(9). Proposed § 63.7570(b)(2).] Units that use an ESP in combination with a wet scrubber 

(and thus cannot monitor opacity) must comply with operating limits on the voltage and 

secondary current (or total power input) of the ESP collection plates. Proposed § 

63.7530(b)(3)(ii). EPA’s proposal to use opacity and ESP voltage and power measurements as 

enforceable operating limits is flawed. The use of total power is not at all reliable as an indicator 

of ESP performance or problems. Although opacity can be used as an “indicator” of PM 

emissions, or as a trigger to initiate corrective action on an ESP, there is not a sufficiently direct 

correlation between opacity and PM or Hg to justify imposition of an enforceable limit. 

Response: We believe that continuous monitoring is needed to ensure ongoing compliance with 

this rule. In order to minimize costs, we look for parameters that are already monitored to use for 

compliance demonstration. We require performance tests to demonstrate compliance with 

emission limits, then use operating limits to ensure the source is operating similarly to how it 

was operating when it completed a successful performance test. Operating limits are not direct 

measures of emissions, but provide measure of fuel characteristics and control device 

performance, and are established as enforceable operating limits routinely in NESHAP 
184

standards. You are also able to petition the Administrator for approval of an alternative 

monitoring plan under section §63.8(f) of subpart A of part 63.

Commenter Name: Lee B. Zeugin

Commenter Affiliation: Utility Air Regulatory Group

Document Control Number: EPA-HQ-OAR-2002-0058-2880.1

Comment Excerpt Number: 36

Comment: It is well known that the relationship between opacity and mass PM (i.e., mass 

concentration) is affected by the particle size distribution, particle shape, and the color 

(reflectivity) of the flyash. UARG Comments, EPA-HQ-OAR-2002-0058-0413, Attachment C at 

8. Numerous tests have confirmed that western subbituminous coal ash creates considerable 

opacity at very low flue gas PM mass loading, while eastern bituminous coal has a higher 

opacity/mass relationship. Id. Given these and other variables, the relationship simply is not 

sufficient to make assumptions based on the proposed opacity operating limit that the PM limit is 

not being met. 

Response: See response to EPA-HQ-OAR-2002-0058-2880.1, Comment Excerpt Number 35.

Commenter Name: Lee B. Zeugin

Commenter Affiliation: Utility Air Regulatory Group

Document Control Number: EPA-HQ-OAR-2002-0058-2880.1

Comment Excerpt Number: 37

Comment: The use of opacity as an operating limit for Hg is even more problematic. Hg is 

emitted from boilers in three forms - particle bound, oxidized, and elemental Hg. Even if opacity 

were directly related to PM (which it is not), it would only be sensitive to particle bound Hg. 

Oxidized and elemental Hg cannot be detected at all by an opacity monitor. Id. at 9. EPA has not 

adequately explained how this tenuous relationship can justify use of opacity as a limit that could 

create liability for violation of the Hg emission limit. 

Response: See response to EPA-HQ-OAR-2002-0058-2880.1, Comment Excerpt Number 35.

Commenter Name: Lee B. Zeugin

Commenter Affiliation: Utility Air Regulatory Group

Document Control Number: EPA-HQ-OAR-2002-0058-2880.1

Comment Excerpt Number: 43

Comment: To ensure that the proposed 24-hour block opacity standard is achievable during 

periods that include startups and shutdowns, when PM controls may not be at full efficiency, 

EPA should include a minimum data requirement for calculation of compliance with the 

proposed opacity standard. If EPA has established the 10 percent standard based on data showing 
185

that compliance is achievable with 24 hours of data, including startup and shutdown data, EPA 

should either (1) limit the compliance calculation to any day upon which the unit operates for at 

least 24 hours, or (2) combine data from the partial operating day with data from the prior or next 

day full operating day. This approach would be similar to that taken in 40 C.F.R. Subpart Da,§ 

60.48Da(g)(3) (stating that averages for compliance with the daily PM standard are only 

calculated for “boiler operating days that have valid data for at least 18 hours of unit operation 

during which the standard applies”), except that standard would apply at all times. If EPA does 

not have data demonstrating that the standard is achievable on a 24-hour block basis including 

startup and shutdown, EPA must provide a higher limit or a longer averaging period consistent 

with the data it has. EPA also must provide that data in the docket. 

Response: See the preamble for how SSM periods are handled in the final rule. EPA believes 

that a 24-hour block period for opacity is an appropriate period to ensure continuous compliance 

with good operating practices to minimize emissions.

Averaging Times for Monitored Pollutants

Commenter Name: Michael L. Steele

Commenter Affiliation: CraftMaster Manufacturing, Inc

Document Control Number: EPA-HQ-OAR-2002-0058-1907.1

Comment Excerpt Number: 19

Comment: Please identify the averaging period for the various limits. Daily or 30-day averages? 

Response: The final rule clarifies the averaging periods that apply based on the monitoring and 

testing that applies. Generally, if a CEMS is used, a 30-day rolling average applies. Opacity 

uses a 24-hour block average, while other operating parameters generally use a 12-hour block 

average. We based the operating parameter 12-hour block average on the estimated maximum 

sampling time required to perform a three run performance test under this rule. For initial and 

annual performance tests, compliance is determined based on the test period.

Commenter Name: Stephen R. Gossett

Commenter Affiliation: Eastman Chemical Company

Document Control Number: EPA-HQ-OAR-2002-0058-3137.1

Comment Excerpt Number: 47

Comment: EPA seeks to address the fact that units will not be able to comply with the proposed 

emissions standards during startups and shutdowns by proposing extended (daily or monthly) 

averaging periods. The assumption that longer averaging periods will provide a reasonable 

method to ensure compliance is likewise flawed. Because unplanned outages are a reality in the 
186

operation of any boiler, industrial or utility, and because unplanned outages are by their nature 

unpredictable, unplanned shutdowns can and will cluster together. 

Extended averaging periods are similarly inadequate to provide a reasonable method to 

demonstrate compliance with the CO standard, due to the inherent variability of CO in solid fuel 

boilers across the load range, but especially upon startup. In addition to Figure 11 we also 

include Figure 12 that shows CO data from another coal stoker fired boiler that monitors CO via 

CEMS. It is readily apparent that CO emissions during normal startup conditions can be as much 

as two orders of magnitude above the proposed standard of 50 ppm for stoker boilers. Figure 13 

demonstrates the impact of the startup of this unit on the calculation of a 30-day average. This 

data set illustrates the impact of a typical unit startup on a calculated 30 day average and the 

problem with requiring a unit to comply with a steady-state emission standard during startups 

and shutdowns. Had this unit been subject to the standard proposed in this rule, the source would 

have been out of compliance due to the two calendar days that saw startup activities, despite the 

fact that the source was operated near or below the proposed standard for CO the following 40 

days. 

Response: CO CEMS are not required. Oxygen monitoring is used to monitor that a source 

properly operates in a manner to minimize CO emissions, and uses a 30-day averaging period.

Commenter Name: Timothy Hunt

Commenter Affiliation: American Forest and Paper Association (AF&PA)

Document Control Number: EPA-HQ-OAR-2002-0058-3213.1

Comment Excerpt Number: 202

Comment: Forest products industry boilers that will be subject to the Boiler MACT many times 

burn multiple types of fuels and are subject to frequent load swings. Therefore, the emissions 

from these boilers vary over the course of a day, depending on the fuel burned and the required 

steam production. EPA acknowledged during the Phase 2 ICR test program that emissions from 

industrial boilers are variable by requesting multi-year historical stack test data and conducting 

30-day fuel and emissions monitoring studies. We believe that additional variability data and 

CEMS data should be reviewed to support longer averaging times, especially since lengthening 

averaging times and incorporating variability seems to be EPA’s preferred approach for 

addressing emissions during startups, shutdowns, and malfunction periods. The court reviewing 

the Brick MACT authorized EPA to look at intra-unit variability and EPA’s work on the 

Hazardous Waste Combustion MACT confirmed the importance of considering variability. The 

EPA also acknowledged that averaging times longer than 3 hours can be appropriate for 

compliance with the condensate collection and treatment requirements in pulp and paper MACT 

Subpart S. Therefore, it is inappropriate for EPA to set limits under the new Boiler MACT that 

cannot be met consistently by a top performing unit overall operating conditions. One way to 

consider a unit’s variability in emissions is to set a longer averaging time for compliance with an 

emission limit. 
187

Averaging times of longer than 3 hours are needed for industrial boilers, especially those in the 

forest products industry that burn multiple fuels and have varying emissions characteristics, in 

order to preserve operational flexibility and ensure cost-efficient operation of the boiler. The 

facility must be able to operate the boiler in a manner that is responsive to process needs, not at 

full load all the time. Longer averaging periods are also desirable if the Boiler MACT emission 

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

The proposed rule is inconsistent in the averaging times specified for operating parameters. The 

body of the rule specifies 3-hour parameter averages while Table 8 specifies 12-hour block 

averages be calculated for CPMS. Where a COMS is used, a daily block average is specified. We 

support daily block averages for CPMS as well. A 24-hour averaging period for CPMS 

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. 

There are factors beyond the boiler operator’s control that can cause emissions to vary over a 

period of days and not hours. For example, the weather will impact moisture content of solid 

fuels, which will affect how the fuels combust over a period of days, not hours. For a biomass 

boiler, the fuel supply and fuel characteristics could also vary over a period of days because mills 

have multiple biomass fuel suppliers providing both green and dry wood. For all types of boilers, 

the pollutant content of the fuel will vary over a period of days, as evidenced by the range of 

results obtained during the 30-day fuel sampling required by EPA for many ICR Phase 2 

participants. Where CEMS are the compliance method (e.g., PM and CO), we support a 30-day 

averaging period to account for operational and emissions variability. 

We believe that the Boiler MACT limits should be set considering intra-unit variability and with 

averaging periods that will ensure compliance can be met consistently. 

Response: See the response to EPA-HQ-OAR-2002-0058-1907.1, Comment Excerpt Number 

19. 

Commenter Name: Timothy Hunt

Commenter Affiliation: American Forest and Paper Association (AF&PA)

Document Control Number: EPA-HQ-OAR-2002-0058-3213.1

Comment Excerpt Number: 291

Comment: If PM CEMS remain a rule requirement for larger boilers, the averaging period 

should be increased to 30 days, similar to the averaging period for sources installing CO CEMS. 

As stated in the discussion elsewhere in these comments regarding averaging times and SSM, it 

will be difficult for sources to meet 24-hour block average limits when operational variability 

and SSM are considered. 

Response: The final rule uses a 30-day rolling average.
188

Commenter Name: Chris Greissing

Commenter Affiliation: Industrial Minerals Association

Document Control Number: EPA-HQ-OAR-2002-0058-2740.2

Comment Excerpt Number: 20

Comment: Averaging Period. It also is not clear which averaging period is being required for 

PM. The Proposed Rule, 63.7525(b)(3) specifies a 24-hour daily (block) average while 

63.7525(b)(4) specifies a 30-day rolling average. EPA states PM CEMS will be installed and that 

“PM levels (monthly average) be maintained below the applicable PM limit.” 75 Fed. Reg. at 

32014. Notwithstanding the lack of justification for requiring a PM CEMS (as discussed above), 

a 30-day rolling average would be less burdensome, would be more appropriate for an averaging 

period of a surrogate that represents only 6% of the total HAP regulated by the rule, and would 

be consistent with the averaging period specified for CO (63.7525(a)(5)). If EPA continues to 

conclude PM is the appropriate surrogate and a CEMS is the appropriate measuring tool, then 

compliance should be determined based on a 30-day averaging period. Proposed 63.7525(b)(3) 

should be eliminated. 

Response: See the response to EPA-HQ-OAR-2002-0058-1907.1, Comment Excerpt Number 

19.

Commenter Name: David A. Buff

Commenter Affiliation: Golder Associates Inc

Document Control Number: EPA-HQ-OAR-2002-0058-2801.1

Comment Excerpt Number: 48

Comment: FSI supports a 30-day rolling average emission limit for CO. CO is highly variable 

from hour to hour and even day to day. A 30-day rolling average will allow these fluctuations to 

be averaged. 

Response: The final rule does not require use of a CO CEMS. The rule does require O2 CEMS 

to ensure that the source operates the source so as to minimize CO emissions. The O2 operating 

limit is based on a 30-day rolling average.

Commenter Name: David A. Buff

Commenter Affiliation: Golder Associates Inc

Document Control Number: EPA-HQ-OAR-2002-0058-2801.1

Comment Excerpt Number: 49

Comment: Sources with PM CEMS should also be afforded a 30-day rolling averaging time to 

comply with the PM emission limits. Little is known about the hour to hour variability of PM 
189

emissions, since few PM CEMS are employed at this time. Ultimately, complying with a 30-day 

rolling average PM limit will not result in any higher annual PM (or metallic HAP) emissions. 

Response: The 30-day rolling average is used.

Commenter Name: Matthew Todd and David Friedman

Commenter Affiliation: American Petroleum Institute (API) and National Petrochemical and 

Refiners Association (NPRA)

Document Control Number: EPA-HQ-OAR-2002-0058-2960.1

Comment Excerpt Number: 76

Comment: Furthermore, taking individual burners out-ofservice for inspection generally will 

cause CO bobbles, at least temporarily increase furnace excess air, and impede oxygen control, 

thereby increasing energy consumption and emissions. 

Recommendation: Exclude periods when a burner is out-of-service for inspection or cleaning 

from CO compliance averages. 

Response: EPA disagrees. The final rule uses a CO compliance test at representative operating 

conditions, combined with an O2 CEMS (on a 30-day rolling average basis) to ensure good air 

pollution control practices to minimize CO emissions.

Commenter Name: Matthew Todd and David Friedman

Commenter Affiliation: American Petroleum Institute (API) and National Petrochemical and 

Refiners Association (NPRA)

Document Control Number: EPA-HQ-OAR-2002-0058-2960.1

Comment Excerpt Number: 95

Comment: Tables 1 and 2 establish the proposed emission limitations for CO as 30-day rolling 

averages for units over 100 MMBTU/hr. CO can vary considerably and it is likely for the low 

CO emission limits proposed for gas- and liquid-fired units that one short incident will cause the 

rolling, 30-day average to be violated for all averages, until the incident is no longer included. 

For instance, for a 1 ppm limit, one day above 30 ppm or one hour above 360 ppm will cause 30 

days of rolling averages to be out-of-compliance. It is unreasonable for one incident to create 30 

deviations or to require 30 deviation reports, as this proposed rule would require, particularly in 

light of the fact that the CO requirements address organic HAPs because of their purported 

chronic health effects. 

Recommendation: Clarify that multiple rolling average exceedances are a single deviation if they 

are caused by the same incident. For such situations, report the number of days where the 30 day 

rolling average is above the limit because of that single event. 
190

Response: The specific CO limit is no longer on a 30-day rolling average, so this comment is no 

longer applicable, but generally for EPA standards, each failure to meet a 30-day rolling average 

is a separate deviation.

Commenter Name: Matthew Todd and David Friedman

Commenter Affiliation: American Petroleum Institute (API) and National Petrochemical and 

Refiners Association (NPRA)

Document Control Number: EPA-HQ-OAR-2002-0058-2960.1

Comment Excerpt Number: 97

Comment: clarification is needed on how to handle boiler and process heater outages. If the 

boiler or process heater is out-of-service during the 30 day period, is the time the unit was outofservice excluded from the average or are out-of-service times counted as zero in the average? 

The former means the 30 day average will often cover a shorter time period and raises serious 

compliance issues if the unit only operated briefly during the 30 days, since the basis for the 

standard assumed a full 30 day average. Since the proposed emission limits are so low, the 

impact of using zero will be small and would provide the most consistent compliance 

demonstration and would comport with the basis for the limits and thus we recommend that 

approach. 

CO monitor outages will be frequent, though generally short, due to the required QA/QC, but the 

handling of those periods also need to be addressed. We recommend that the monitor readings 

during those periods simply be excluded from the average. Having a few percent less data points 

in a 30 day period will have no significant impact on the average. This is consistent with the 

approach outlined in the part 63 general provisions. 

Recommendation: Clarify that boiler and process heater out-of-service times are counted as zero 

when calculating 30-day averages and that monitor outages are excluded from the calculation of 

compliance averages. 

Response: The 30-day rolling averages that apply in the final rule require the source to use all 

hourly data for the preceding 30 “operating days,” as defined in the rule. Monitor outages are 

not used in calculating averages.

Commenter Name: Matthew Todd and David Friedman

Commenter Affiliation: American Petroleum Institute (API) and National Petrochemical and 

Refiners Association (NPRA)

Document Control Number: EPA-HQ-OAR-2002-0058-2960.1

Comment Excerpt Number: 98
191

Comment: The proposal is silent as to the averaging time applicable to CO and PM for units 

without CEMS and without controls for which parameter monitoring is specified and for 

dioxin/furan. This will create problems for sources because of the credible evidence provisions 

applicable to the emission limits without and because it would presumably make the emission 

limits instantaneous where control operating parameters are measured continuously. Having an 

averaging time is important to being able to evaluate compliance. Since the proposed initial 

compliance determination associated with these emission limits is based on three 4-hour 

performance test runs, a 12 hour averaging time is suggested and we ask the Agency to make this 

explicit in the rule. 

Recommendation: Specify a 12 hour averaging time for CO, PM and dioxin/furan in Table 1 and 

2, where no CEMS is installed or parameter monitoring is used to continuously demonstrate 

compliance. 

Response: Because continuous testing is not required for units without a CEMS, no averaging 

period is necessary for such emission limits. For operating limits, the averaging period is stated 

for the specific parameter being measured. 

Commenter Name: Robert D. Bessette

Commenter Affiliation: Council of Industrial Boiler Owners (CIBO)

Document Control Number: EPA-HQ-OAR-2002-0058-2702.1

Comment Excerpt Number: 123

Comment: 2. PM CEMS compliance basis. 

Conflicting averaging times in the Proposed Rule 

EPA states that PM CEMS would be used to demonstrate a monthly average is maintained below 

the applicable PM limit. 75 FR 32014. Section 63.7525(b)(3) indicates compliance on a 24 hour 

block average basis as an average of the hourly emissions and 63.7525(b)(4) indicates a 30 day 

rolling average basis. EPA needs to be consistent in the required compliance averaging time. 

CIBO recommends that a 30 day rolling average basis is most appropriate and allows for normal 

operational variations. 

Response: The final rule uses a 30-day rolling average.

Commenter Name: Russ A. Wozniak

Commenter Affiliation: Dow Chemical Company

Document Control Number: EPA-HQ-OAR-2002-0058-2632.1

Comment Excerpt Number: 21
192

Comment: Table 2 Should Specify the Same Averaging Time for Particulate Matter as noted in 

Section 63.7525(b)(3). The emission limit for particulate matter in Table 2 for coal-fueled boilers 

does not specify a time period for compliance demonstration. In cases where a continuous PM 

CEMS will be required, the averaging time should be specified to be the same as outlined in 

proposed Section 63.7525(b)(3). This section specifies that compliance with the applicable 

emission limit shall be determined based on the 24-hour daily (block) average of the hourly 

arithmetic average emissions concentrations using the continuous monitoring system outlet data. 

Response: The final rule uses a 30-day rolling average.

Commenter Name: Russ A. Wozniak

Commenter Affiliation: Dow Chemical Company

Document Control Number: EPA-HQ-OAR-2002-0058-2632.1

Comment Excerpt Number: 61

Comment: There are factors beyond the boiler operator’s control that can cause emissions to 

vary over a period of days and not hours. For all types of boilers, the pollutant content of the fuel 

will vary over a period of days, as evidenced by the range of results obtained during the 30-day 

fuel sampling required by EPA for many ICR Phase 2 participants. Where CEMS are the 

compliance method (e.g., PM and CO), Dow supports a 30-day averaging period to account for 

operational and emissions variability. 

Response: The final rule uses a 30-day rolling average.

Commenter Name: J. Michael Geers

Commenter Affiliation: Duke Energy

Document Control Number: EPA-HQ-OAR-2002-0058-2765.1

Comment Excerpt Number: 23

Comment: Compared to gaseous and liquid fossil fuels, solid fuels can exhibit much more 

variability in their fuel characteristics that can inhibit efficient combustion. Listed below are 

examples of these differences in their characteristics: 

Variable fuel mix, e.g. often residuals from various processes. 

Variable heating values and moisture contents. 

Variable size distribution. 

Higher noncombustible material contamination, e.g. rocks, dirt, metal debris, etc. 

Due to the variability of the solid fuel characteristics, combustion efficiency will be affected. As 

a result, this may lead to elevated CO emission levels, as well as inconsistent CO emission rates 

throughout the day. However, there are significant economic incentives for the boilers to be 

operated as efficiently as possible. Therefore, over the course of the day the operation of the 
193

boiler will be continuously tuned to account for and accommodate fuel variability as best it can 

be. For that reason, a daily averaging period would allow for these 

changes to be properly included in the averaging period, and not be penalized for the short-term 

effects of making these changes. 

Response: The final rule does not require use of a CO CEMS. The rule does require O2 CEMS 

to ensure that the source operates the source so as to minimize CO emissions. The O2 operating 

limit is based on a 30-day rolling average.

Commenter Name: Steve Zika

Commenter Affiliation: Hampton Lumber Mills, Inc

Document Control Number: EPA-HQ-OAR-2002-0058-2817.1

Comment Excerpt Number: 11

Comment: All of Hampton’s air permits require our mills to document emissions on a monthly 

and annual basis for determining compliance with our permits. Hampton does not see why the 

EPA believes we should also monitor emissions from our CEMS on a rolling 30 day average 

when state and federal air permits already require the reporting on a monthly calendar basis. 

Response: For boiler standards, the 30-day rolling average is a commonly used approach in 

federal standards, and EPA has not opted for a calendar month averaging period in this rule.

Commenter Name: Steven G. Hanson

Commenter Affiliation: Graphic Packaging International

Document Control Number: EPA-HQ-OAR-2002-0058-2723.1

Comment Excerpt Number: 15

Comment: If the averaging period for continuous emissions monitors (CEM) is established as 

24-hours, there is a strong probability that compliance with the proposed limitations are not 

possible. 

Response: A 30-day rolling average is used in the final rule.

Commenter Name: Steven G. Hanson

Commenter Affiliation: Graphic Packaging International

Document Control Number: EPA-HQ-OAR-2002-0058-2723.1

Comment Excerpt Number: 30
194

Comment: Should EPA move forward with the PM CEM mandate, EPA has conflicting 

information regarding the intended averaging period for the PM emission limitation for units 

requiring installation of a PM CEM. On page 32014 of the federal register, EPA states the 

following: we are proposing that PM CEMS be installed and operated and that PM levels 

(monthly average) be maintained below the applicable limit. In this statement, EPA clearly states 

an intent for a monthly average limitation. However, the regulatory language proposed per 40 

CFR 63.7525(b) (3) — (6) contains conflicting requirements between either a 24-hour block 

average or a 30-day rolling average basis. If EPA retains the requirement for installation of a PM 

CEM, GPI — Macon Mill encourages the use of the 30-day rolling average requirement. 

Proposed emission limitations for PM are based on data from infrequent (typically annual) stack 

testing. Extrapolation of such limited short-term testing into a 24-hour continuously monitored 

requirement is not sufficiently supported. A 24-hour block average does not allow for variability 

in the emissions profile that could arise from load variability, fuel variability, or start-up and 

shutdown events (events where use of controls is not always feasible, depending on the boiler 

configuration). 

Response: A 30-day rolling average is used in the final rule.

Commenter Name: Gary W. Kruger

Commenter Affiliation: Morton Salt

Document Control Number: EPA-HQ-OAR-2002-0058-2883.1

Comment Excerpt Number: 37

Comment: The Boiler MACT limits should be set considering intra-unit variability and with 

averaging periods that will ensure compliance can be met consistently. 

The industrial boilers that will be subject to the Boiler MACT are many times subject to frequent 

load swings. Therefore, the emissions from these boilers vary over the course of a day, 

depending on the fuel burned and the required steam production. EPA acknowledged during the 

Phase 2 ICR test program that emissions from industrial boilers are variable by requesting 

multiyear historical stack test data and conducting 30-day fuel and emissions monitoring studies. 

We believe that additional variability data and CEMS data should be reviewed to support longer 

averaging times, especially since lengthening averaging times and incorporating variability 

seems to be EPA’s preferred approach for addressing emissions during startups, shutdowns, and 

malfunction periods. The court reviewing the Brick MACT authorized EPA to look at intra-unit 

variability and EPA’s work on the Hazardous Waste Combustor MACT confirmed the 

importance of considering variability. The EPA also acknowledged that averaging times longer 

than 3 hours can be appropriate for compliance with the condensate collection and treatment 

requirements in pulp and paper MACT Subpart S. Therefore, it is inappropriate for EPA to set 

limits under the new Boiler MACT that cannot be met consistently by a top performing unit over 

all operating conditions. One way to consider a unit’s variability in emissions is to set a longer 

averaging time for compliance with an emission limit. 
195

Averaging times of longer than 3 hours are needed for industrial boilers in order to preserve 

operational flexibility and ensure cost-efficient operation of the boiler. The facility must be able 

to operate the boiler in a manner that is responsive to process needs, not at full load all the time. 

Longer averaging periods are also desirable if the Boiler MACT emission limits are going to 

apply at all times, including periods of startup, shutdown, and malfunction. The proposed rule is 

inconsistent in the averaging times specified for operating parameters. The body of the rule 

specifies 3-hour parameter averages while Table 8 specifies 12-hour block averages be 

calculated for continuous parameter monitoring systems (CPMS). Where a continous opacity 

monitoring system (COMS) is used, a daily block average is specified. We support daily block 

averages for CPMS as well. A 24-hour 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. 

There are factors beyond the boiler operator’s control that can cause emissions to vary over a 

period of days and not hours. For example, the weather will impact moisture content of solid 

fuels, which will affect how the fuels combust over a period of days, not hours. For all types of 

boilers, the pollutant content of the fuel will vary over a period of days, as evidenced by the 

range of results obtained during the 30-day fuel sampling required by EPA for many ICR Phase 

II participants. Where CEMS are the compliance method such as for PM and CO, we support a 

30-day averaging period to account for operational and emissions variability. 

Response: See the response to EPA-HQ-OAR-2002-0058-1907.1, Comment Excerpt Number 

19.

Commenter Name: David M. Kiser

Commenter Affiliation: International Paper Company

Document Control Number: EPA-HQ-OAR-2002-0058-2777.1

Comment Excerpt Number: 43

Comment: 40 CFR 63.7525(b)(4), refers to a 30 day rolling average, but in the previous section 

section 63.7525(b)(3), it says compliance will be determined on a 24 hour daily (block) average. 

This discrepancy in averaging time needs to be resolved in the final rule. 

Response: The final rule applies a 30-day rolling average.

Commenter Name: Jim Griffin

Commenter Affiliation: American Chemistry Council

Document Control Number: EPA-HQ-OAR-2002-0058-2792.1

Comment Excerpt Number: 160
196

Comment: EPA SHOULD CONSIDER LONGER AVERAGING PERIODS. The 2004 Boiler 

rule included emission limits for PM/metals, mercury, and HCl for existing boilers, and 

PM/metals, mercury, HCl, and CO for new boilers. Compliance with the PM/metals, mercury, 

and HCl limits was determined using a stack test (3-hour average) or fuel sampling (90th 

percentile of all samples collected, no averaging period specified) and compliance with the CO 

limit was determined using either a stack test (3-hour average) or a CEMS (30-day rolling 

average). When demonstrating compliance using a 3-hour stack test, the "worst case" fuel mix 

was required to be fired, which may vary by compound. When demonstrating compliance using 

fuel sampling, facilities were required to obtain at least 3 representative samples and calculate 

the 90th percentile fuel pollutant content. For compliance with the CO limit using CEMS, 

variability of boiler operation was acknowledged by specifying a 30-day rolling average. 

The industrial boilers that will be subject to this rule often burn multiple types of fuels and are 

subject to frequent load swings. Therefore, the emissions from these boilers vary over the course 

of a day, depending on the fuel burned and the required steam production. EPA acknowledged 

during the Phase II ICR test program that emissions from industrial boilers are variable by 

requesting multi-year historical stack test data and conducting 30-day fuel and emissions 

monitoring studies. We believe that additional variability data and CEMS data should be 

collected and reviewed to support longer averaging times, especially since lengthening averaging 

times and incorporating variability seems to be EPA’s preferred approach for addressing 

emissions during startups, shutdowns, and malfunction periods. 

The court reviewing the Brick MACT authorized EPA to consider intra-unit variability and 

EPA’s work on the Hazardous Waste Combustion MACT confirmed the importance of 

considering variability. EPA also acknowledged that averaging times longer than 3 hours can be 

appropriate for compliance with the condensate collection and treatment requirements in the Pulp 

and Paper MACT. Therefore, we believe it is inappropriate for EPA to set limits under the new 

Boiler MACT that cannot be met consistently by a top performing unit overall operating 

conditions. One way to consider a unit’s variability in emissions is to set a longer averaging time 

for compliance with an emission limit. 

Averaging times of longer than 3 hours are needed for industrial boilers, especially those that 

burn multiple fuels and have varying emissions characteristics, in order to preserve operational 

flexibility and ensure cost-efficient operation of the boiler. The facility must be able to operate 

the boiler in a manner that is responsive to process needs, not at full load all the time. Longer 

averaging periods are also desirable if the Boiler MACT emission limits are going to apply at all 

times, including periods of startup, shutdown, and malfunction. However, ACC strongly 

recommends that EPA provide for a work practice approach, such as use of an emissions 

minimization plan, during startup and shutdown periods, and apply emission limits and 

averaging times only to operational periods outside of unit startup and shutdown. 

Response: See the response to EPA-HQ-OAR-2002-0058-1907.1, Comment Excerpt Number 

19. See the preamble for the approach to SSM periods in the final rule.
197

Commenter Name: Jim Griffin

Commenter Affiliation: American Chemistry Council

Document Control Number: EPA-HQ-OAR-2002-0058-2792.1

Comment Excerpt Number: 162

Comment: There are factors beyond the boiler operator’s control that can cause emissions to 

vary over a period of days, not hours. For example, the weather will impact moisture content of 

solid fuels, which will affect how the fuels combust over a period of days. For all types of 

boilers, the pollutant content of the fuel will vary over a period of days, as evidenced by the 

range of results obtained during the 30-day fuel sampling required by EPA for many ICR Phase 

II participants. Where CEMS are the compliance method (e.g., PM and CO), we support a 30-

day averaging period to account for operational and emissions variability. 

We believe that this rule’s limits should be set based on consideration of intra-unit variability 

and with averaging periods that will ensure compliance can be met consistently. 

Response: The final rule applies a 30-day averaging period where CEMS are used.

Fuel Analysis Methods

Commenter Name: Michael L. Steele

Commenter Affiliation: CraftMaster Manufacturing, Inc

Document Control Number: EPA-HQ-OAR-2002-0058-1907.1

Comment Excerpt Number: 4

Comment: Compliance with HCl and Hg Limits by Fuel Analyses §63.7505(c) 

For biomass fuels it is questionable that it will be possible to use fuel analyses to demonstrate 

compliance. The ASTM methods for Hg and CI have detection limits of 0.010 and 20 mg/ kg, 

respectively. This is due to the ASTM procedures available and the low dry bulk density of the 

biomass fuel. ThenJ even if all fuel analyses results are not detected and values are considered to 

be the method detection limit, the Lbs Hg and HCl per MMBtu are above the proposed limits. 

This is also the case at even one-half of the detection limit 

This would also be an issue if the unit where establishing site-specific operating parameters 

under §63.7530. 

How are fuel test results of not detected to be treated for compliance purposes? Equal to 

detection limit? Equal to one-half detection limit? 

Please confirm that fuel test based compliance is based on an annual average of monthly fuel 

tests. 
198

Response: The fuel analysis for Hg and Cl is an alternative option and thus may not be 

appropriate for every source. It will be necessary for each operator to determine whether stack 

testing or fuel analysis is the best option for their fuel type. Also, the final rule has revised Hg 

and HCl limits which may allow more units to use fuel analysis as a compliance option. Nondetect data should be reported as the fuel analysis method detection level for compliance 

purposes, and each monthly fuel test must meet the limit.

Commenter Name: Randolph Price

Commenter Affiliation: Consolidated Edison Company of New York

Document Control Number: EPA-HQ-OAR-2002-0058-1869.1

Comment Excerpt Number: 6

Comment: The test method specified for hydrogen chloride in liquid fuel in Table 6 to Subpart 

DDDDD of Part 63 is inappropriate for residual oil. 

The Federal Register notice presents "Table 6 to Subpart DDDDD of Part 63 Fuel Analysis 

Requirements" on page 32070. Step "f’ under Part 2, "Hydrogen Chloride" requires a source 

owner to "[M]easure chlorine concentration in fuel sample." The method column identifies a 

method for coal (ASTM D6721-01) and biomass (ASTM E776-87), and a third method SW-846-

9250 presumably designated for use in measuring chlorine concentration in liquid fuels. SW846-9250 is typically used for water and wastewater samples, and not for residual oil analysis. 

EPA’s document entitled "Summary of Boiler and Process Heater Test Procedures, Methods and 

Reporting Requirements" included as Enclosure I of the ICR documents sent to selected sources, 

listed methods that are more suitable for residual oil sampling. Table 2.3 of Enclosure I listed 

SW-846-5050, -9056, -9076 or -9250 for determining chlorine concentration in liquid fuels. To 

ensure consistent results between the ICR and the compliance sampling envisioned in the 

proposed rule, EPA should list these additional, and in some cases more appropriate, methods in 

the final version of Table 6 to Subpart DDDDD of Part 63. 

Response: EPA thanks the commenter for the additional suggestions and recognizes these other 

methods as appropriate, given previous approval of these methods under the ICR testing 

program. As long as the most up to date versions of the listed methods are used they will be 

accepted. Given the time constraints for requesting incorporation by reference approval, the 

general provisions to part 63 and the final rule will be amended at a future date to include 

reference to these additional methods but this edit will not occur simultaneously with publication 

of the final rule in the CFR.

Commenter Name: Michael L. Steele

Commenter Affiliation: CraftMaster Manufacturing, Inc

Document Control Number: EPA-HQ-OAR-2002-0058-1907.1

Comment Excerpt Number: 20
199

Comment: The proposed rules specify that the fuel CI level measured during successful stack 

testing will become the maximum allowable, site-specific limit for HCl. If so, how does one 

account for natural variations in fuel CI content? What if actual emissions are significantly below 

the allowable emissions? It would seem reasonable to allow some flexibility under such a 

circumstance. It is suggested that an HCl efficiency calculation be petiormed as per the MACT 

Floor fuel variability model. Then the site-specific fuel-based limit could be based on the 

allowable HAP’s emissions. 

Same comments apply to the site specific fuel-based Hg limit. 

Response: See response to EPA-HQ-OAR-2002-0058-1907.1, Comment Excerpt Number 4. 

Commenter Name: Jim Griffin

Commenter Affiliation: American Chemistry Council

Document Control Number: EPA-HQ-OAR-2002-0058-2792.1

Comment Excerpt Number: 184

Comment: Although use of an "equivalent" method does not require EPA approval, there are 

often questions as to whether a particular method meets EPA’s equivalency criteria. To 

circumvent such uncertainties, it would be extremely helpful for EPA to specifically include 

additional methods that EPA has previously determined to be "equivalent," or has approved as 

acceptable "alternative" methods. EPA did publish a list of such methods for fuel sampling and 

analyses in revisions made to the 2004 Boiler rule.[See Table 1, 71 Fed. Reg. at 70653.] EPA 

should add these previously approved methods for moisture analysis, higher heating value, 

digestion procedures, sample preparation, mercury, HCl, and chlorine to Table 6 if they do not 

already appear. 

Response: If any of the methods listed at Table 1, 71 Fed. Reg. at 70653 are not in the final rule 

they are considered equivalent for the new rule. We will conduct a comprehensive review and 

incorporate these additional methods by reference in the near future, if necessary and if they 

represent the most up to date versions of the voluntary consensus standards on record with 

ASTM or ISO.

Commenter Name: Jim Griffin

Commenter Affiliation: American Chemistry Council

Document Control Number: EPA-HQ-OAR-2002-0058-2792.1

Comment Excerpt Number: 185

Comment: Besides the previously EPA-approved methods, we believe ASTM D3684-01 should 

be added to Table 6 as an equivalent method for mercury, and ASTM D2361-95 (2001) and 

D4208-02e1 as equivalent methods for hydrogen chloride. 
200

Response: EPA thanks the commenter for the additional suggestions and recognizes these other 

methods as appropriate, given previous approval of these methods under the vacated 2004 rule. 

As long as the most up to date versions of the listed methods are used they will be accepted. 

Given the time constraints for requesting incorporation by reference approval, the general 

provisions to part 63 and the final rule will be amended at a future date to include reference to 

these additional methods but this edit will not occur simultaneously with publication of the final 

rule in the CFR.

Commenter Name: Jim Griffin

Commenter Affiliation: American Chemistry Council

Document Control Number: EPA-HQ-OAR-2002-0058-2792.1

Comment Excerpt Number: 186

Comment: Table 5 to Subpart JJJJJJ in Part 63 has fuel analysis requirements for mercury, and 

it would be appropriate to incorporate the additional methods pertinent to mercury into this table 

so that it will be compatible with Subpart DDDDD. 

Response: See response to EPA-HQ-OAR-2002-0058-2792.1 Comment Excerpt Number 184.

Commenter Name: Kerry Flick

Commenter Affiliation: Metso Power

Document Control Number: EPA-HQ-OAR-2002-0058-2388.1

Comment Excerpt Number: 11

Comment: The EPA-proposed Industrial Boiler MACT mercury limit for new installations of 

circulating fluidized-bed units firing biomass is 0.0000002 IbIMMBtu. Should a facility want to 

comply by fuel choice alone, the mercury concentration in the biomass feedstock would have to 

be lower than 0.0012 ppmw (dry), assuming a heating value of 6000 Btu/lb (dry). Most biomass 

feedstocks have mercury concentrations that range from <0.001 to 0.04 ppmw (dry). Meeting 

this limit by fuel choice alone, especially when taking variability into consideration, will be 

extremely difficult and, in most cases, not possible unless the unit is designed and demonstrated 

to capture mercury or the addition of specific mercury control technology such as activated 

carbon is used. 

A short study conducted by the Energy & Environmental Research Center shows that mercury 

concentrations as measured in biomass are highly variable and tend to be approximately a factor 

of 10 to 100 lower than mercury-in-coal values. However, some biomass feedstocks had 

concentrations that were similar to coals that typically exhibit low mercury concentrations. The 

mercury data collected and reported herein ranged from<0.001 to 0.04 ppmw (dry). Table 1 

summarizes the mercury concentrations for different biomass feedstocks. Mentz et aL found that 

the bark from stemwood trees exhibited a significantly higher mercury concentration than the 

woody part of the tree. Mentz found that the stemwood mercury concentrations had a range of 
201

0.001 to 0.004 ppmw, while the bark ranged from 0.001 to 0.037 ppmw with the average values 

represented in Table 1. [See submittal for Enclosure B Table 1 and corresponding references]. 

The data set shows a significant amount of variability, even within similar feedstock types. This 

indicates that geography (where the feedstock is grown) is a significant factor in the mercury 

concentration, along with other factors such as tree type, growth rate, age, etc. In general, 

biomass feedstocks have lower mercury concentrations than coal, with at least a factor of 10 to 

100 lower mercury concentrations than most coals. If considering 100% biomass or biomass 

cofiring, mercury measurements of the potential feedstocks must be performed in order to 

determine mercury variability and the potential it may have on emissions. 

Response: See response to EPA-HQ-OAR-2002-0058-1907.1, Comment Excerpt Number 4.

Commenter Name: Peter Zalzal

Commenter Affiliation: Environmental Defense Fund

Document Control Number: EPA-HQ-OAR-2002-0058-2869.1

Comment Excerpt Number: 4

Comment: As described above, mercury emissions can vary along two dimensions – changes in 

boiler processes and changes in coal-mercury content – and EPA’s proposal does not adequately 

capture this variation. Allowing affected sources to demonstrate continuous compliance based

solely on fuel analysis fails to take into consideration the very real scenario in which boiler 

processes change, resulting in an increase in mercury emissions. 

Response: See response to EPA-HQ-OAR-2002-0058-2388.1, Comment Excerpt Number 11.

Commenter Name: Sharene Shealey

Commenter Affiliation: RRI Energy

Document Control Number: EPA-HQ-OAR-2002-0058-2759.1

Comment Excerpt Number: 6

Comment: EPA allows for demonstration of compliance with HCl and mercury emission limits 

through fuel analysis in the proposed rule in § 63.7505(c). For liquid-fired units, specifically 

distillate-oil fired units, EPA should also allow for demonstration of compliance with particulate 

matter standards by fuel-based methods. PM emissions are directly correlated to fuel and 

combustion conditions and are expected to be relatively low for distillate-oil fired units. EPA 

acknowledges the correlation between fuel and particulate emissions in the consideration of the 

floor for fuel-related HAP for both existing and new units (sections IV.D and IV.H of the 

preamble to the proposed rule), categorizing PM as a “fuel related HAP” in both sections. 

Response: EPA did not finalize a fuel analysis approach for PM in the final rule. This method 

was not considered in the vacated rulemaking and there are a wide variety of liquid fuel types 
202

which could make this exercise very complex. Further, EPA has incorporated a reduced testing 

frequency in the revised rule to reduce the testing burden.

Commenter Name: Sharene Shealey

Commenter Affiliation: RRI Energy

Document Control Number: EPA-HQ-OAR-2002-0058-2759.1

Comment Excerpt Number: 7

Comment: EPA should allow an option for compliance with the emission standards of the 

proposed rule via certified use of ultra-low sulfur diesel fuel. In the preamble, EPA states that 

fuel switching can lead to the reduction of some HAP emissions and increases in other HAP 

emissions. Switching from traditional No. 2 fuel oil to ultra-low sulfur diesel does not result in 

new or additional HAP emissions. Due to the reduced emissions, continuous compliance with the 

PM, HCl, and mercury limits is obtained by the use of ultra-low sulfur diesel in distillate-fired 

sources. The Title V annual compliance certification (supported by monthly record keeping as 

required in the proposed rule) would suffice to demonstrate initial and continuous compliance 

with the PM, HCl, and mercury limits of the proposed rule. 

Response: In the final rule, EPA has established emission limits for all liquid fuel units and a 

consistent compliance demonstration program based on either stack testing or fuel analysis 

alternatives for Hg and HCl. The fuel analysis alternative also includes the option for sources to 

use fuel supplier certification in order to reduce testing costs on the affected source. PM testing 

must be completed at the source, although EPA has included reduced testing frequency in the 

revised rule to reduce the burden on low emitting sources such as ULSFO.

Commenter Name: Britt S. Fleming

Commenter Affiliation: Auto Group

Document Control Number: EPA-HQ-OAR-2002-0058-2775.1

Comment Excerpt Number: 41

Comment: The initial compliance test requirement proposed in § 63.7510(a) and (b) that the 

source measure the chlorine content in the feed stream is not technically feasible for landfill gas 

units. Proposed § 63.7510(a) and (b), EPA does not specify sampling methods for gaseous fuels. 

Other proposed sections of EPA’s rule also are problematic in that they fail to consider landfill 

gas in the requirements. These sections are as follows: 

Response: Fuel analysis for gaseous fuels is not allowable for chlorine. EPA reviewed several 

fuel analysis methods and could not identify any appropriate methods for measuring chlorine in 

gaseous fuels. In the final rule, many adjustments have been made to the gas 1 subcategory, 

which most units firing gaseous fuels are expected to belong to. For the small amount of other 

process gases EPA has finalized a fuel gas specification for mercury and hydrogen sulfide only.
203

Commenter Name: Britt S. Fleming

Commenter Affiliation: Auto Group

Document Control Number: EPA-HQ-OAR-2002-0058-2775.1

Comment Excerpt Number: 42

Comment: Proposed § 63.7515(f), which specifies requirements for a monthly fuel analysis that 

are unsuitable for landfill gas units since there is no fuel sampling method specified. 

Response: Gaseous fuels are exempt from fuel analysis requirements with the exception of 

gaseous fuels trying to qualify as other gas 1 fuels through the H2S and mercury fuel 

specification.

Commenter Name: Britt S. Fleming

Commenter Affiliation: Auto Group

Document Control Number: EPA-HQ-OAR-2002-0058-2775.1

Comment Excerpt Number: 44

Comment: Proposed § 63.7521, which addresses fuel sampling but is completely focused on 

liquid and solid fuels. Given the focus of the provision, EPA needs to clarify that this section is 

not intended for gaseous fuels. As proposed, this section makes it impossible for sources using 

landfill gas to comply since there are no methods for gaseous fuels identified. For example, § 

63.7521(b)(2)(iv) requires identification of the fuel sampling methods and expected minimum 

detection levels for chlorine and mercury. Without an identified sampling method, it is not 

possible to anticipate the minimum detection level. In addition, § 63.7521(c) requires sampling 

according to (c)(1) (sampling from a belt feeder) or (c)(2) (sampling from a fuel pile). Neither of 

these sampling methods can be used for units using landfill gas. Similarly, the requirements to 

prepare fuel sample composites at § 63.7512(d) are inappropriate for landfill gas. Specifically, 

the initial compliance requirements include “conducting a fuel analysis for each type of fuel 

burned in your boiler or process heater according to § 63.7521 and Table 6 to this subpart . . . .” 

[Footnote: See 75 Fed. Reg. at 32,051.] This requirement is inconsistent for a boiler that burns 

both natural gas and landfill gas given that proposed § 63.7521 and Table 6 do not address 

sampling requirements for these gaseous fuels. 

Response: EPA agrees with the commenter that composite fuel sampling procedures in 

63.7521(c) and (d) does not apply to gaseous and liquid fuels, given the homogenous nature of 

these fuel types. Section 63.7521(a) has been modified in the final rule to exempt gaseous and 

liquid fuels from the composite sampling methods referenced in 63.7521(c) and (d). See 

response to comment DCN EPA-HQ-OAR-2002-0058-2702.1 Excerpt 84 for fuel analysis 

methods for gaseous fuels. EPA may need to add further clarification on the applicability of fuel 

analysis requirements in 63.7521 on certain gaseous fuels in a future reconsideration notice.
204

Commenter Name: Stephen R. Gossett

Commenter Affiliation: Eastman Chemical Company

Document Control Number: EPA-HQ-OAR-2002-0058-3137.1

Comment Excerpt Number: 63

Comment: EPA should clarify that solid fuel units that require start-up or supplemental fuels are 

considered “single fuel sources”, and are exempt from fuel analysis requirements if they elect to 

conduct a performance test. 

EPA proposed at § 63.7510(a) the following: 

For affected sources that burn a single type of fuel, you are exempted from the initial compliance 

requirements of conducting a fuel analysis for each type of fuel burned in your boiler or process 

heater according to §63.7521 and Table 6 to this subpart. 

Most solid fuel boilers cannot start up from a cold condition on their main fuel. Such units 

require an additional fuel source to initiate combustion until such time as the unit is warmed up 

and stable combustion with the solid fuel can be safely maintained. For example, pulverized coal 

fired boilers typically start up by firing either Natural Gas or Fuel Oil. These startup periods 

typically last for several hours per OEM recommendations, during which time coal combustion 

is started. When certain OEM specified conditions are met (e.g., minimum steam temperature, 

minimum tube temperature, minimum flue gas temperature, minimum pulverizer temperature, 

elapsed time from light-off, etc.), the start up fuel is shut down and the unit fires coal 

exclusively. Some pulverized coal units have additional OEM specified flame stability controls 

that require the start up fuel to be fired on specific burners when a pulverizer is either being 

removed from service or put into service (e.g., Eastman Chemical Company’s No. 31 Boiler, a 

Riley Stoker pulverized coal boiler with attrition pulverizers). Solid fueled units can also utilize 

the startup fuel to preserve unit capacity due to an unforeseen malfunction in the solid fuel 

feeding and/or firing system(s). Whether for startup, short-term flame stability when solid fuel 

feeding and/or firing systems are taken in- or out-of-service, or in reaction to unusual conditions, 

the startup or supplemental fuel is a transient fuel source. The start up or supplemental fuel 

represents a negligible percentage of the source’s total hours of operation, and thus has a 

negligible impact on overall emissions from the source. For example, if a source operates 

Eastman Boiler MACT Comments Page 36 of 45 continuously on coal for 49 weeks per calendar 

year; and has three start ups per year, each of which requires firing Natural Gas for 8 hours; the 

annual source operating time on Natural Gas equals (3 x 8 hours = 24 hours) divided by (49 

weeks x 7 days per week x 24 hours per day = 8,232 hours) equaling 0.3% of the source’s 

operating hours on the startup fuel. 

We support EPA’s intent to exempt units that fire a single type of fuel from the additional burden 

of conducting fuel analyses during performance stack testing as a reasonable accommodation to 

minimize unnecessary costs. EPA should clarify its intent in this matter by including language to 

explain that units which require a start-up fuel for initial startup, units shutdown, or transient 

flame stability purposes, still qualify as “sources that burn a single type of fuel” and are exempt 

from the fuel analysis requirements under §63.7521 and Table 6. 
205

EPA should further clarify that solid fuel units that fire natural gas or commercial fuel oil as a 

supplementary or start up fuel are likewise considered “sources that burn a single type of fuel” 

and are exempt from the fuel analysis requirements under §63.7521 and Table 6. 

Additionally, § 63.7540(a) does not appear to recognize the provisions set forth in § 63.7510 that 

exempt units that fire a single fuel from conducting fuel analyses during performance stack 

testing. Additional provisions should be included in this section to recognize the exemption from 

fuel analysis testing during performance stack testing in § 63.7510 for units that fire a single type 

of fuel. 

Response: EPA agrees with the commenter that supplemental fuels used during start-up, 

shutdown, or flame stability do not preclude a unit from qualifying as a unit that burns a “single 

type of fuel”. In the final rule, we have adjusted §63.7521(a) to clarify our intent and make the 

appropriate exemptions for these instances as long as the unit elects to demonstrate compliance 

with a performance test.

Commenter Name: Timothy Hunt

Commenter Affiliation: American Forest and Paper Association (AF&PA)

Document Control Number: EPA-HQ-OAR-2002-0058-3213.1

Comment Excerpt Number: 119

Comment: Although the emission limits for HCl and Hg as proposed are so low that this option 

may not be widely exercised, we support the inclusion of an option for compliance with emission 

limits through fuel analysis. 

Response: Thank you for the support. The fuel analysis for Hg and Cl is an alternative option 

and thus may not be appropriate for every source. 

Commenter Name: Timothy Hunt

Commenter Affiliation: American Forest and Paper Association (AF&PA)

Document Control Number: EPA-HQ-OAR-2002-0058-3213.1

Comment Excerpt Number: 120

Comment: We would like EPA to confirm that for single fuel units, the exemption from fuel 

analysis still applies for solid or liquid fueled boilers that startup on natural gas or that are 

burning process gases in a boiler for emissions control and not for heat value. Where EPA is 

requiring fuel analyses for multi-fuel boilers for determining fuel operating limits for Hg and 

HCl, EPA should not include gaseous fuels in the fuel testing requirements since collecting 

samples of these gases is dangerous and concentrations of chlorine and mercury in gaseous fuels 

will be very small and have virtually no effect on the total amount of mercury and chlorine being 

input to the boiler 
206

Response: EPA agrees with the commenter and we have clarified the final rule language to 

exclude fuel analysis for fuels used for only startup, unit shutdown, and transient flame stability 

purposes.

Commenter Name: Timothy Hunt

Commenter Affiliation: American Forest and Paper Association (AF&PA)

Document Control Number: EPA-HQ-OAR-2002-0058-3213.1

Comment Excerpt Number: 122

Comment: Table 6 to Subpart DDDDD of Part 63 lists several EPA and ASTM methods to be 

used for fuel sample collection, processing, and analysis. The phrase “or equivalent” has been 

added to all the methods listed in Table 6. The term “equivalent” is specifically defined in 

§63.7575 for sample collection procedure, sample compositing procedure, sample preparation 

procedure, heat content determination, fuel moisture determination, and mercury determination, 

but no definition is provided for HCl. This should be rectified by either adding a new section 

addressing HCl under the definition of “equivalent,” or by modifying the current definition for 

an “equivalent pollutant determinative or analytical procedure” (section (6) under the definition) 

to explicitly include HCl. 

Response: We have clarified section 6 under the definition of equivalent to note that it applies 

to mercury, H2S, and HCl.

Commenter Name: Timothy Hunt

Commenter Affiliation: American Forest and Paper Association (AF&PA)

Document Control Number: EPA-HQ-OAR-2002-0058-3213.1

Comment Excerpt Number: 123

Comment: Although use of an “equivalent” method does not require EPA approval, there are 

often questions as to whether a particular method meets EPA’s equivalency criteria. To 

circumvent such uncertainties, it would be extremely helpful for EPA to specifically include 

additional methods that EPA has previously determined to be “equivalent,” or has approved as 

acceptable “alternative” methods. EPA did publish a list of such methods for fuel sampling and 

analyses in a December 6, 2006 Federal Register (Table 1, page 70653) modification of the 2004 

Boiler MACT rule. EPA should add these previously approved methods for moisture analysis, 

higher heating value, digestion procedures, sample preparation, mercury, HCl, and chlorine to 

Table 6 if they do not already appear. 

Response: See response for EPA-HQ-OAR-2002-0058-2792.1, Comment Excerpt Number 184.
207

Commenter Name: Timothy Hunt

Commenter Affiliation: American Forest and Paper Association (AF&PA)

Document Control Number: EPA-HQ-OAR-2002-0058-3213.1

Comment Excerpt Number: 124

Comment: Besides the previously EPA-approved methods, we believe ASTM D3684-01 should 

be added to Table 6 as an equivalent method for mercury, and ASTM D2361-95 (2001) and 

D4208-02e1 as equivalent methods for hydrogen chloride. 

Response: See response for EPA-HQ-OAR-2002-0058-2792.1, Comment Excerpt Number 185.

Commenter Name: Timothy Hunt

Commenter Affiliation: American Forest and Paper Association (AF&PA)

Document Control Number: EPA-HQ-OAR-2002-0058-3213.1

Comment Excerpt Number: 125

Comment: Table 5 to Subpart JJJJJJ in Part 63 has fuel analysis requirements for mercury, and 

it would be appropriate to incorporate the additional methods pertinent to mercury into this table 

so that it will be compatible with Subpart DDDDD. 

Response: See response to EPA-HQ-OAR-2002-0058-2792.1 Comment Excerpt Number 184.

Commenter Name: Mike D. Craig

Commenter Affiliation: New Energy Corp.

Document Control Number: EPA-HQ-OAR-2002-0058-2695.1

Comment Excerpt Number: 4

Comment: Proposed 40 C.F.R. § 63.7510(a) states that sources that burn a single type of fuel are 

exempt from fuel analysis. However, proposed 40 C.F.R. § 63.7530(a) states that initial 

compliance must be demonstrated by conducting performance stack tests and fuel analysis. The 

fuel analysis requirement is aimed primarily at sources that regularly combust more than one 

type of fuel in order to determine the fuel with the highest HCl and Hg emission potential. 

However, fuel analysis is also used to screen an alternate fuel type if a source switches from one 

type of fuel to another (§63.7540(4) & (6)) so the intent may be that initial fuel analysis is 

necessary to provide a basis for comparing the fuels at a later time. NEC cannot burn anything 

but bituminous coal, so fuel analysis should be unnecessary. 

Response: See response to EPA-HQ-OAR-2002-0058-3137.1, Comment Excerpt Number 63. 
208

Commenter Name: Randall D. Quintrell

Commenter Affiliation: Georgia Paper and Forest Products Association, GPFPA

Document Control Number: EPA-HQ-OAR-2002-0058-2905

Comment Excerpt Number: 11

Comment: An example of the burdensome and unnecessary testing mandated by the proposed 

Rule is the requirement for mercury and hydrogen chloride testing on units firing cleaner fuels, 

in particular biomass boilers, both solid and liquid, and for mercury testing on liquid fuel oil 

boilers. Abundant data have been collected and reported to EPA on fuel sampling under the 

industry wide ICR in 2008 clearly demonstrating that biomass fuels are inherently low in both 

mercury and chloride and that the emissions levels are equally inherently low. The same is true 

for mercury in liquid fuels. Extremely low and often non-detectible levels of HCl were found in 

the testing where the differences between boiler units are due to natural variation in fuels and are 

not "technology-dependent" at all. The inordinately low emission standards that resulted for 

these cleaner fuels indicate in and of themselves that these constituents are not a concern for 

these fuels, even ignoring the incidental removal that would naturally occur in the boiler (e.g., 

HC1 in alkaline biomass units) and any ancillary PM/ SO2 control devices. It is clear from the 

low emission potential that HC1 testing is unnecessary and burdensome for low chloride fuels 

such as biomass and similarly, mercury testing is unnecessary and burdensome for low mercury 

fuels including biomass and liquid fuel oil. 

Response: For units firing fuels that are below the emission limits of the final rule, we have 

retained a reduced testing frequency for all pollutants. The final rule discusses the revised criteria 

to qualify for reduced testing. We have also provided a compliance option to use fuel analysis in 

lieu of stack testing. These flexibilities have reduced the burden on affected entities while 

ensuring continuous compliance with the final emission limits.

Commenter Name: William R. Ermatinger

Commenter Affiliation: Northrop Grumman

Document Control Number: EPA-HQ-OAR-2002-0058-2506.1

Comment Excerpt Number: 20

Comment: Because half of the measured values of any fuel component will exceed the average 

observed concentration by definition, the same fuel that was employed and analyzed during 

emissions compliance testing will not comply with subsequently derived fuel composition limits 

in half of all instances. Compliance with liquid fuel limitations could only be achieved under the 

proposed regulation by ensuring that fuel component levels, such as chloride and mercury, be 

maintained at levels far below those encountered during the emissions compliance testing (since 

only the lowest observed levels were utilized to establish the Boiler MACT limits), and this can 

only be accomplished by a facility revising its fuel specification for its fuel suppliers. 

Response: See response to EPA-HQ-OAR-2002-0058-1907.1, Comment Excerpt Number 4.
209

Commenter Name: Leonard W. Sandridge

Commenter Affiliation: University of Virginia

Document Control Number: EPA-HQ-OAR-2002-0058-2769.1

Comment Excerpt Number: 23

Comment: §63.7510(a) states that affected sources burning a single type of fuel are exempted 

from the initial compliance requirements of conducting a fuel analysis for each type of fuel 

burned in your boiler or process heater according to §63.7521 and Table 6 to this subpart. If a 

source burns coal or distillate oil with natural gas as a backup, can they be exempted from the 

fuel analysis requirements if they are demonstrating compliance through emissions monitoring? 

The procedures in Table 6 do not address gas sampling and liquid fuel sampling requirements are 

not completely addressed. We recommend updating §§63.7521 and 63.7530(b) to reference the 

exemption in §63.7510(a) from the fuel analysis requirement and calculation of maximum 

chlorine and mercury fuel input.

Response: For a clarification of single fuel source requirements, see response to DCN: EPAHQ-OAR-2002-0058-3137.1, Excerpt 63. For liquid fuels, see response to DCN: EPA-HQOAR-2002-0058-1869.1 Excerpt 6. 

Back-up fuels are not necessarily exempted from fuel analysis requirements unless the fuels are 

fired during start-up, shutdown or transient flame stability. EPA clarified these exemptions in 

§63.7521 and also edited §63.7521(a) such that only gaseous fuels that meet the definition of gas 

2 (other) are subject to fuel analysis requirements. This will prevent the need for fuel analysis on 

most gaseous fuels.

Commenter Name: David A. Buff

Commenter Affiliation: Golder Associates Inc

Document Control Number: EPA-HQ-OAR-2002-0058-2801.1

Comment Excerpt Number: 55

Comment: Comments on fuel sampling procedures: 

63.7521(c)(1)(i) – at many facilities it is not possible to stop the conveyor belt without severely 

disrupting operations of the boiler and the facility as a whole. Facilities such as sugar mills have 

equipment and procedures in place to obtain grab samples of bagasse directly from the moving 

conveyor belt, or as the bagasse is discharged from the mill. These options should be included in 

the rule language. 

Response: §63.7521(b)(2)(iii) provides the option for sources to detail the sampling location 

and specific procedures used to collect and prepare the samples if those procedures differ from 

the instructions in the final rule. EPA recognizes that sources will have unique situations and 

cannot account for every variation in the rule language. The option for providing these details in 

the fuel analysis plan accommodates these unique circumstances. EPA encourages sources to 
210

develop a comprehensive initial fuel plan that will cover most scenarios such that minimal edits 

to the plan will be required for subsequent plan submittals.

Commenter Name: Robert D. Bessette

Commenter Affiliation: Council of Industrial Boiler Owners (CIBO)

Document Control Number: EPA-HQ-OAR-2002-0058-2702.1

Comment Excerpt Number: 84

Comment: XIII. Fuel Analysis 

EPA Should Provide a Fuel Analysis Option for Gas and Liquid Fuels. 

EPA has provided in the Proposed Rule that boilers and process heaters may choose to 

demonstrate compliance with emission standards on the basis of fuel analysis. 75 FR 32014. 

While CIBO supports a fuel analysis option, there are additional units that should be able 

demonstrate compliance in this way and there is clarification that is needed. While CIBO 

supports a fuel analysis alternative, the methods provided in the Proposed Rule are 

predominantly geared towards solid fuels. EPA should provide a fuel analysis option for gas and 

liquid fuels to the extent the final rule imposes emission limits, recognizing the inherent 

differences between gas, liquid, and solid fuels. 

Response: For liquid fuels, see response to DCN: EPA-HQ-OAR-2002-0058-1869.1 Excerpt 6. 

Gaseous fuels are exempt from fuel analysis requirements with the exception of gaseous fuels 

trying to qualify as other gas 1 fuels through the H2S and mercury fuel specification. Liquid 

fuels are exempt from composite sampling requirements in table 6 given the homogenous nature 

of those fuels.

Commenter Name: Robert D. Bessette

Commenter Affiliation: Council of Industrial Boiler Owners (CIBO)

Document Control Number: EPA-HQ-OAR-2002-0058-2702.1

Comment Excerpt Number: 148

Comment: The Exemption for Sources that Burn a Single Type of Fuel Should Be Expanded. 

The Proposed Rule provides that "affected sources that burn a single type of fuel" are exempted 

from "the initial compliance requirements of conducting a fuel analysis for each type of fuel 

burned [in the] boiler or process heater. 75 FR 32051. This exemption should be included in the 

proposed § 63.7521. 75 FR 32052. For additional clarity, the proposed § 63.7540(a) should 

reflect the language in § 63.7510(a) exempting sources that burn single type of fuel from initial 

compliance requirements. 

Response: EPA disagrees with the commenter. § 63.7510(a) is intended to establish a maximum 

chlorine and mercury limit on the fuels used in the combustion unit, as well as corresponding 

operating parameters to ensure compliance with the emission limits under worst case scenarios.
211

Commenter Name: Robert D. Bessette

Commenter Affiliation: Council of Industrial Boiler Owners (CIBO)

Document Control Number: EPA-HQ-OAR-2002-0058-2702.1

Comment Excerpt Number: 149

Comment: Fuel Sampling and Analysis Requirements Should Apply Only to Solid or Liquid 

Fuels. 

EPA should amend the Proposed Rule so that it clearly states that fuel sampling and analysis 

requirements are applicable only to solid or liquid fuels. Furthermore, EPA should clarify under 

what circumstances liquid fuel analysis is required. 

Response: For a clarification of single fuel source requirements, see response to DCN: EPAHQ-OAR-2002-0058-3137.1. Where liquid fuel usage meets these criteria fuel analysis is not 

required. We also clarified that the composite sampling techniques described in 63.7521(b) and 

Table are not applicable to liquid fuels since liquid fuels are much more homogenous than solid 

fuels.

Commenter Name: Matthew Todd and David Friedman

Commenter Affiliation: American Petroleum Institute (API) and National Petrochemical and 

Refiners Association (NPRA)

Document Control Number: EPA-HQ-OAR-2002-0058-2960.1

Comment Excerpt Number: 186

Comment: Proposed 63.7510(a) and (b) require a fuel analysis for each type of fuel burned in 

your boiler or process heater for units subject to an emission limitation. While some gas-fired 

boilers and process heaters at a major source fire individual fuels, many do not. It is common 

practice to collect process off-gases and mix those with natural gas to create a fuel gas system 

that supplies many boilers and process heaters. At many sites, gases associated with startups, 

shutdowns, malfunctions and maintenance are collected by flare gas recovery systems and routed 

to the fuel gas system. Because these are large systems, this blending minimizes gas variability 

and fosters beneficial recovery of gases that otherwise would be flared. 

Recommendation: The Agency should make clear in 63.7510(a), that only one test, done when 

the fuel gas system is operating normally, is required for fuel gas systems and that each of the 

individual streams routed to the system is not a separate fuel and need not be tested. 

Response: EPA agrees with the commenter that the intent was to test the fuel fired in the boiler 

and not each individual gas stream feeding a common fuel line routed to the boiler. Rule 

language will be updated in the reconsideration package.
212

Commenter Name: Matthew Todd and David Friedman

Commenter Affiliation: American Petroleum Institute (API) and National Petrochemical and 

Refiners Association (NPRA)

Document Control Number: EPA-HQ-OAR-2002-0058-2960.1

Comment Excerpt Number: 187

Comment: Recommendation: It also would be useful for 63.7510(a) to specifically mention that 

the fuel analysis is for Cl- and Hg. The current language could be read to indicate other analyses 

are required. 

Response: § 63.7510(a) specifies that the fuel analysis is to be conducted according to Table 6 

and § 63.7521 of this subpart, which is specific to Hg and HCl and associated sampling 

requirements. Further EPA has edited § 63.7521 to clarify that composite sampling techniques 

do not apply to liquid fuels.

Commenter Name: Matthew Todd and David Friedman

Commenter Affiliation: American Petroleum Institute (API) and National Petrochemical and 

Refiners Association (NPRA)

Document Control Number: EPA-HQ-OAR-2002-0058-2960.1

Comment Excerpt Number: 189

Comment: The proposal treats the fuel analysis alternate as a performance test. [Footnote: For 

instance 63.7515(g) starts (g) You must report the results of performance tests (stack test and 

fuel analyses)... 63.3530(a) contains a similar parenthetical. 63.7521 contains requirements that 

parallel performance test notice and approval requirements.] Since these tests are monthly, 

treating them as performance tests causes impossible problems. For instance there are advance 

notice requirements for each performance test, requirements for a performance test plan and 

special reporting requirements. These requirements make no sense for a monthly fuel test and 

would impose tremendous burdens on sources and regulators that are not reflected in the record 

or the ICR. 

Recommendation: Treat fuel testing as an ongoing compliance demonstration and not as a 

performance test and require results to be reported in the periodic report, not in a special 

performance test report. 

Response: EPA agrees with the commenter and has edited the rule to remove these 

parenthetical notations. Reporting the results of the fuel analysis are allowed in the routine 

periodic compliance reports and no separate notifications or reports are required.

Commenter Name: Matthew Todd and David Friedman

Commenter Affiliation: American Petroleum Institute (API) and National Petrochemical and 

Refiners Association (NPRA)
213

Document Control Number: EPA-HQ-OAR-2002-0058-2960.1

Comment Excerpt Number: 191

Comment: Proposed 63.7521(c) and (d) call for composite samples and contain sample 

preparation procedures that are only suited for solids. Composite sampling is a waste of time and 

effort for gas and liquid samples when fuel analyses are being done monthly. 

Recommendations: Exempt gaseous and liquid fuels from the requirements of 63.7521(c) and 

(d). 

Response: See response to comment DCN EPA-HQ-OAR-2002-0058-2702.1 Excerpt 84 for 

composite sampling.

Commenter Name: John C. Hendricks

Commenter Affiliation: American Electric Power

Document Control Number: EPA-HQ-OAR-2002-0058-2703.1

Comment Excerpt Number: 5

Comment: EPA Should Amend the Coal Sampling Procedures. The proposed rule requires 

affected sources to conduct stop belt sampling or to pull samples from the coal piles during 

testing. Stop belt sampling is neither safe to conduct due to stored energy in the conveyor belts, 

nor is it representative of a units operation. A unit may have to reduce process rate due to a 

decrease or a lag in the time that the fuel is being delivered. 

Sampling from the coal pile will not gather coal samples that are representative of what is being 

burned. AEP has coal piles that are greater than 15 acres in area and gathering 5 samples 

uniformly spaced at a depth of 18 inches will not adequately represent what is being burned 

during the test period. 

AEP suggests that the EPA merely specify a number of representative fuel samples during the 

testing while allowing the sources the flexibility to safely and accurately determine the best 

method for collecting such a sample. 

Response: See the response to EPA-HQ-OAR-2002-0058-2801.1, Comment Excerpt Number 

55.

Commenter Name: Pamela F. Faggert

Commenter Affiliation: Dominion

Document Control Number: EPA-HQ-OAR-2002-0058-2908.1

Comment Excerpt Number: 6
214

Comment: We request that EPA provide clarification that fuel sampling and an associated fuel 

sampling plan is not required for gas-fired boilers and other boilers subject to work practice 

requirements. 

Response: Fuel analysis is only required on units subject to emission limits. It was not EPA’s 

intent to require fuel analysis on units subject to tune-up work practices in lieu of emission 

limits. EPA has clarified this in § 63.7510(a) of the final rule.

Commenter Name: Debra J. Jezouit

Commenter Affiliation: Class of '85 Regulatory Response Group

Document Control Number: EPA-HQ-OAR-2002-0058-2802.1

Comment Excerpt Number: 9

Comment: Fuel Based Compliance 

The Class of ‘85 believes that EPA should allow liquid-fired units, specifically distillate-oil fired 

units, to use fuel analyses to comply with the PM standards. EPA is proposing to allow sources 

to demonstrate compliance with HCl and mercury emissions through fuel analyses; it is 

reasonable for EPA to finalize a similar option for the PM standards. PM emissions directly 

correlate to fuel and combustion conditions and are expected to be relatively low for distillate-oil 

fired units. [Footnote: EPA recognizes this correlation in Sections IV.D and IV.H of the 

Proposed Rule, which address the MACT floor for fuel-related HAPs such as PM.] 

Response: See response for EPA-HQ-OAR-2002-0058-2759.1, Comment Excerpt Number 6.

Commenter Name: Douglas A. McWilliams

Commenter Affiliation: American Municipal Power

Document Control Number: EPA-HQ-OAR-2002-0058-2808.1

Comment Excerpt Number: 31

Comment: AMP supports EPA’s flexible compliance approach that permits sources to 

demonstrate compliance with mercury emission limits through fuel analysis. EPA has recognized 

that the concentration of mercury in fuel directly affects mercury emissions. 75 Fed. Reg. at 

32017. It is therefore appropriate to use the correlation between mercury fuel content and 

mercury emissions as a means of demonstrating compliance with mercury emission limits. 

In the Proposed Rule, EPA has appropriately acknowledged the high variability of mercury 

content in fuel and has provided the flexibility needed to address that variability in the fuel 

analysis provisions. This is particularly important to coal-fired sources, as mercury content may 

vary widely within a single seam of coal. Basing compliance on test results from a single point in 

time could cause even the best-controlled sources to register as non-compliant if that particular 

batch of coal had an unusually high mercury content. The Proposed Rule mitigates5 
215

that risk by using a statistical approach, requiring monthly composite samples, and determining 

compliance based on the annual average results. The proposed fuel analysis regulations provide 

needed regulatory flexibility without compromising implementation of mercury emission limits 

and should be adopted in the final rule. 

Response: Thank you for the support. The fuel analysis for Hg and Cl is an alternative option 

and thus may not be appropriate for every source. 

Commenter Name: Pamela F. Faggert

Commenter Affiliation: Dominion

Document Control Number: EPA-HQ-OAR-2002-0058-2908.1

Comment Excerpt Number: 34

Comment: In the 2004 rule, EPA required repeat fuel analysis only when a new type of fuel is 

combusted, and not later than 5 years after the lasts fuel analysis12. However, EPA now 

proposes to require new fuel analysis monthly, regardless of whether the type of fuel combusted 

has changed. The purpose of monthly analysis if the fuel or mixture of fuels has not changed is 

unclear. EPA should remove the reference in § 63.7515(f) to monthly analysis. If EPA retains the 

requirement, it should provide an explanation for it, make clear whether EPA is proposing use of 

an annual average, and allow further opportunity for comment. 

Response: A monthly frequency provides assurance of continuous compliance with the 

emission limits. We have retained the monthly frequency in the final rule.

Commenter Name: Russ A. Wozniak

Commenter Affiliation: Dow Chemical Company

Document Control Number: EPA-HQ-OAR-2002-0058-2632.1

Comment Excerpt Number: 46

Comment: EPA Should Reduce the Frequency of Fuel Analyses for Demonstration of 

Compliance for Mercury and HCl from Monthly to Semi-Annually. 

63.7515(f) of EPA’s proposed rule requires monthly fuel analyses where compliance for mercury 

and HCl is based on fuel analysis. That same subsection goes on to require reporting of results 

within 60 days of the analysis. 

EPA provides no insight or justification in the preamble or otherwise for requiring monthly fuel 

testing. Monthly fuel analysis is an unnecessary and burdensome requirement. Most fuels 

originate from large reservoirs and deposits where quality does not vary quickly over time. Fuels 

that are the result of controlled manufacturing processes are of a quality known to and controlled 

by the operators of that process. Most other EPA air pollution rules either do not require periodic 

testing of the fuel or have programs such that the fuel is tested on a semi-annual basis. 
216

Submitting fuel analyses each month (see Section 63.7515(g)) serves no purpose. EPA proposes 

no action to be taken based on the results of any one analysis. The rule proposes that compliance 

with emission limits based on fuel analysis is determined on an annual average. 

EPA’s final rule should replace the monthly fuel analysis with an analysis on a semi-annual basis 

or when the permittee has reason to believe that there has been a material change in the 

composition of the fuel being burned. In addition, the results of any such analysis should be 

documented via records versus reported to the agency. 

Response: A monthly frequency provides assurance of continuous compliance with the 

emission limits. Further, monthly fuel sampling is an alternative compliance mechanism to 

performance testing and affected sources are not required to conduct monthly sampling unless 

they select this compliance alternative.

Commenter Name: Russ A. Wozniak

Commenter Affiliation: Dow Chemical Company

Document Control Number: EPA-HQ-OAR-2002-0058-2632.1

Comment Excerpt Number: 48

Comment: EPA Should Revise the Requirement to Submit a Site-Specific Fuel Analysis Plan to 

the EPA Administrator. EPA proposes in 63.7521(b) that "you must develop and submit a sitespecific fuel analysis plan to the EPA Administrator for review and approval according to the 

following procedures and requirements in paragraphs (b)(1) and (b)(2) of this section." Section 

63.7521(b)(1) requires the submittal of the fuel analysis plan no later than 60 days before the 

date of the sampling. 

This requirement should be revised to require the owner/operator to prepare a site-specific fuel 

analysis plan, maintain the plan on-site, and to provide a copy of the plan to the EPA 

Administrator/permitting authority upon request. To require approval of such a plan gives 

industry no assurance that a plan would be approved in a timely manner and would also burden 

the agency with unnecessary reviews. The analytical methods are defined in Table 6, so they are 

defined in detail by EPA. In addition, the requirement to submit the plan 60 days in advance of 

gas sampling presents an unnecessary roadblock to collecting samples in a timely manner to 

meet regulatory requirements. As an alternative, EPA could also just require submittal of fuel 

analysis plans if the owner/operator wants to request an alternative analytical method other than 

those required by Table 6 (reference proposed 63.7521(b)(2)(v)). 

EPA should replace proposed 40 CFR 63.7521(b) and (b)(1) with the following text: 

You must maintain, and submit to the permitting authority for approval upon request, a sitespecific fuel analysis plan that includes the information contained in paragraphs (b)(2)(i) through 

(vi) of this section. Only requests for an alternative analytical method other than those required 

by Table 6 to this subpart should be submitted to the EPA administrator for review and approval. 
217

Response: We have edited 63.7521(b)(1) of the final rule to clarify that submittal of the fuel 

analysis plan is only required to be submitted for review and approval prior to demonstrating 

initial compliance. Plans are not required to be submitted before each monthly fuel analysis.

Commenter Name: Jeffrey O'Hearn

Commenter Affiliation: Panolam Industries International Inc

Document Control Number: EPA-HQ-OAR-2002-0058-2749.1

Comment Excerpt Number: 2

Comment: 63.7505(c): There is a question as to whether the detection limit for the analysis of 

chlorine in fuel oil is sufficiently low to be able to show compliance with the MACT 

requirement. There is also no specific test method included for liquid samples in Table 6. 

Response: Demonstration with the chlorine limit using fuel analysis is an alternative. Further, 

the MACT floor analysis for liquid fuels was established using a combination of data from fuel 

analysis sampling and performance stack testing. EPA will add additional test methods for 

chlorine analysis of liquid fuels in a later version of the rule since there was not sufficient time to 

incorporate these additional methods by reference.

Commenter Name: David O'Keefe

Commenter Affiliation: USEC, Inc

Document Control Number: EPA-HQ-OAR-2002-0058-3122

Comment Excerpt Number: 5

Comment: Fuel sampling. Fuel sampling requirements should be clarified. When fuel sampling 

is required, where is the sampling to occur — at the feed point, at the storage location, at the time 

of delivery? 

Fuel sampling requirements should be more flexible. Coal may be stored without additional 

deliveries over a several month period. If representative sampling has occurred during delivery, 

this should be adequate for monitoring purposes and no new sampling should be required. 

Supplier analytical data should be allowed to fulfill the sampling requirements. There are 

normally contractual requirements for coal quality and the supplier is responsible for supplying 

coal that meets the contract requirements. 

Another option is to allow using analytical coal data from either the supplier or facility and use 

this information as long as the source of the coal and processing method does not change. This 

option is preferred due to the reduced burden. With more frequent sampling comes the associated 

cost of sampling, analysis, and record keeping. 
218

Response: The final rule does allow affected sources to use supplier data or site-specific fuel 

analysis as long as the suppliers testing methods are equivalent to the methods listed in Table 6 

of the final rule. Regarding the commenter's request for more clarifications on the fuel analysis 

requirements, EPA recognizes that the exact location and timing of when sampling is to occur 

may vary depending on site specific operating conditions and these details should be outlined in 

your site-specific fuel monitoring plan in order to accommodate site-specific situations that 

cannot be fully anticipated and mandated within the regulatory text of this subpart.

Commenter Name: Richard Rosvold

Commenter Affiliation: Xcel Energy Services, Inc

Document Control Number: EPA-HQ-OAR-2002-0058-2955.1

Comment Excerpt Number: 6

Comment: EPA has proposed the use of particulate matter (PM) for use as a surrogate for nonmercury metallic HAPs. These HAP constituents are fuel-dependent, and are not affected by the 

combustion conditions in the boiler. As such, the EPA should allow the option of demonstrating 

compliance with the non-mercury HAP limits through the use of fuel sampling and analysis. This 

sampling and analysis could be done by either the end user or the fuel supplier. Relying on fuel 

analyses from the fuel suppliers would greatly reduce the compliance costs for many companies 

without compromising public health or environmental protection. 

Response: See response for EPA-HQ-OAR-2002-0058-2759.1 Comment Excerpt Number 6

Commenter Name: Barry Christensen

Commenter Affiliation: Occidental Chemical Corp

Document Control Number: EPA-HQ-OAR-2002-0058-2848.1

Comment Excerpt Number: 8

Comment: OCC requests codification of the fuel analysis methods for gaseous fuels. Methods to 

sample and analyze for mercury and chlorine in gaseous fuels are not specified in the proposed 

rule. OCC respectfully requests that EPA include such methods in the final rule. 

Response: Section 63.7521(a) has been modified in the final rule to exempt gaseous and liquid 

fuels from the composite sampling methods referenced in 63.7521(c) and (d). See response to 

comment DCN EPA-HQ-OAR-2002-0058-2702.1 Excerpt 84 for fuel analysis methods for 

gaseous fuels. EPA may need to add further clarification on the applicability of fuel analysis 

requirements in 63.7521 on certain gaseous fuels in a future reconsideration notice. 

Commenter Name: Gary Melow

Commenter Affiliation: Michigan Biomass

Document Control Number: EPA-HQ-OAR-2002-0058-2776.1
219

Comment Excerpt Number: 16

Comment: A biomass facility would typically use the continuous compliance option for mercury 

and hydrogen chloride based on the mercury and chlorine content of fuel. This is due to the fact 

that most biomass boilers are equipped with ESPs for particulate control and do not employ 

carbon injection due to minimal mercury emissions, nor are scrubbers typically used for HCL 

control. 

We note that mercury is sometimes not detectable in our biomass fuel and in that case it would 

not be straightforward to establish a maximum mercury content of the fuel. We would propose 

using the detection level as the assumed level of mercury in the fuel. 

Response: See response for EPA-HQ-OAR-2002-0058-1907.1, Comment Excerpt Number 4

Commenter Name: Paul N. Cicio

Commenter Affiliation: Industrial Energy Consumers of America

Document Control Number: EPA-HQ-OAR-2002-0058-2752.1

Comment Excerpt Number: 17

Comment: EPA should clarify that solid fuel units that require start-up or supplemental fuels are 

considered “single fuel sources”, and are exempt from fuel analysis requirements. 

EPA requires that solid fuel units that burn multiple fuels meet additional requirements. IECA 

requests that EPA clarify that sources that use an additional fuel for start-up are not multiple fuel 

boilers. These requirements are referenced in the proposed § 63.7510. 

§ 63.7510(a) For affected sources that elect to demonstrate compliance with any of the emission 

limits of this subpart through performance stack testing, your initial compliance requirements 

include conducting performance stack tests according to §63.7520 and Table 5 to this subpart, 

conducting a fuel analysis for each type offuel burned in your boiler or process heater according 

to §63.7521 and Table 6 to this subpart, establishing operating limits according to §63.7530 and 

Table 7 to this subpart, and conducting CMS performance evaluations according to §63.7525. 

For affected sources that burn a single type offuel, you are exemptedfrom the initial compliance 

requirements of conducting a fuel analysis for each type offuel burned in your boiler or process 

heater according to §63.7521 and Table 6 to this subpart. 

Most solid fuel boilers cannot start-up from a cold condition on their main fuel. Such units 

require an additional fuel source to initiate combustion until such time as the unit is warmed up 

and stable combustion with the solid fuel can be safely maintained. These start-up periods, often 

firing alternate fuels, are absolutely essential to maintain the structural integrity of the equipment 

and to protect the safety of plant personnel operating the equipment. For example, pulverized 

coal fired boilers typically start up by firing either Natural Gas or Fuel Oil. These start-up 

periods vary considerably for different types of units, typically lasting several hours 

(pulverized-coal boiler) to several days (circulating fluidized bed boilers) per equipment 

operating specifications recommendations, during which time coal combustion is started. When 

certain specified conditions are met (e.g., minimum steam temperature, minimum tube 

temperature, minimum flue gas temperature, minimum pulverizer temperature, elapsed time 
220

from light-off, etc.), the start-up fuel is shut down and the unit fires coal exclusively. Some 

pulverized coal units have additional equipment operating for flame stability controls that require 

the start up fuel to be fired on specific burners when a pulverizer is either being removed from 

service or put into service. Solid fueled units can also utilize the startup fuel to preserve unit 

capacity due to an unforeseen malfunction in the solid fuel feeding and/or firing system(s). 

Whether for startup, short-term flame stability when solid fuel feeding and/or firing systems are 

taken in-or out-of-service, or in reaction to unusual conditions, the startup or supplemental fuel is 

a transient fuel source. The start up or supplemental fuel represents a negligible percentage of the 

source’s total hours of operation, and thus has a negligible impact on overall emissions from the 

source. For example, if a source operates continuously on coal for 49 weeks per calendar year? 

and has three start ups per year, each of which requires firing Natural Gas for 8 hours? the annual 

source operating time on Natural Gas equals (3 x 8 hours = 24 hours) divided by (49 weeks x 7 

days per week x 24 hours per day = 8,232 hours) equaling 0.3% of the source’s operating hours 

on the startup fuel. 

IECA supports EPA’s intent to exempt units that fire a single type of fuel from the additional 

burden of conducting fuel analyses during performance stack testing as a reasonable 

accommodation to minimize unnecessary costs. EPA should clarify its intent in this matter by 

including language to explain that units which require a start-up fuel for initial startup, unit 

shutdown, or transient flame stability purposes, still qualify as “sources that burn a single type of 

fuel” and are exempt from the fuel analysis requirements under §63.7521 and Table 6. 

Response: See response to EPA-HQ-OAR-2002-0058-3137.1, Comment Excerpt Number 63. 

Commenter Name: Richard Rosvold

Commenter Affiliation: Xcel Energy Services, Inc

Document Control Number: EPA-HQ-OAR-2002-0058-2955.1

Comment Excerpt Number: 18

Comment: Monthly fuel sampling, as required in § 63.7515(t), is excessive for liquid fuels. 

These fuels are generally chemically homogenous and vary little. Monthly sampling would only 

add expense without a corresponding benefit to the environment. Monthly fuel sampling for fuels 

that are stored on-site in piles is excessive as well. That is, for boilers burning coal that is stored 

on-site in piles, the rule should allow for one sample from the coal shipment, and not require 

monthly samples of the coal from the same pile. 

Response: See the response to EPA-HQ-OAR-2002-0058-2801.1, Comment Excerpt Number 

55.

Commenter Name: Gary Melow

Commenter Affiliation: Michigan Biomass

Document Control Number: EPA-HQ-OAR-2002-0058-2776.1

Comment Excerpt Number: 18
221

Comment: We also read the proposed rule that we can use periodic stack testing for HCL and 

mercury for compliance demonstration, and are not required to use the methods described in 

63.7530(c)(3) Equation 10 and 11. The formulation in this section assumes all chlorine in the 

fuel is converted to HCL and all mercury in the fuel is emitted, which is not the case for our 

sources. 

We request that EPA confirm our understanding as the language in 63.7530 (75 FR pages 32056 

to 32058) is somewhat confusing. 63.7530(b) states that in addition to stack testing and 

establishment of site specific operating limits, you must also conduct fuel analyses according to 

63.7521 and establish maximum fuel pollutant input levels according to paragraphs (c)(1) 

through (c)(3), as applicable. Equation 10 and 11 assumes all chlorine is converted to HCL and 

all mercury is emitted is under section (c)(3) of this section. 

Response: The interpretation of §63.7530 described by the commenter is incorrect. Units 

demonstrating compliance with HCl and Hg emission limits using performance stack testing are 

still required to establish maximum chlorine and mercury fuel input parameters using the 

procedures in §63.7530. The commenter does not provide any documentation or data to back up 

their assertion of what percentage of chlorine and mercury in the fuel are converted to HCl and 

mercury emissions and so these equations have not been adjusted.

Commenter Name: Bill Wemhoff

Commenter Affiliation: National Rural Electric Cooperative Association

Document Control Number: EPA-HQ-OAR-2002-0058-2835.1

Comment Excerpt Number: 23

Comment: NRECA supports the use of stack testing and the fuel analysis option for Hg and 

HCl, but is concerned with EPA’s proposed implementing rules. 

Response: Thank you for the support. The fuel analysis for Hg and Cl is an alternative option 

and thus may not be appropriate for every source.

Commenter Name: Bill Wemhoff

Commenter Affiliation: National Rural Electric Cooperative Association

Document Control Number: EPA-HQ-OAR-2002-0058-2835.1

Comment Excerpt Number: 29

Comment: Supports the option to use fuel analysis to demonstrate compliance where possible, 

and does not object to a requirement to perform a new fuel analysis for Hg and chlorine when a 

new fuel is combusted. However, does not support EPA’s proposed requirement for monthly fuel 

analysis for sources that have not changed fuel type, or the agency’s proposal regarding how that 

analysis is used. 
222

Response: See response to EPA-HQ-OAR-2002-0058-2880.1, Comment Excerpt Number 30. 

Commenter Name: Lee B. Zeugin

Commenter Affiliation: Utility Air Regulatory Group

Document Control Number: EPA-HQ-OAR-2002-0058-2880.1

Comment Excerpt Number: 30

Comment: Sources that demonstrate compliance with the Hg or HCl limit through fuel analysis 

must 

conduct fuel analysis for each type of fuel combusted according to § 63.7521 and Table 6, and 

“establish operating limits according to § 63.7530 and Table 8.” Proposed § 63.7510(b). 

Proposed § 63.7530(c) provides procedures for calculating Hg and HCl emission rates. To 

demonstrate compliance, the calculated rate cannot exceed the applicable emission limit using 

the fuel analysis and based on an upper 90th percentile confidence interval. In the 2004 rule, 

EPA required repeat fuel analysis when a new type of fuel is combusted, and not later than 5 

years after the lasts fuel analysis. 69 Fed. Reg. 55,218, 55,256 (Sept. 13, 2004). However, EPA 

now proposes to require new fuel analysis monthly, regardless of whether the type or mixture of 

fuel combusted has changed. Proposed § 63.7515(f). 

UARG does not understand the purpose of monthly analysis if the fuel type or mixture of fuels 

has not changed. EPA provides no explanation in the rule or preamble. To the contrary, although 

EPA’s preamble does reference a requirement for monthly fuel analysis, EPA does not say why. 

Moreover, EPA’s preamble states that compliance is determined based on the “annual average” 

of those analyses. 75 Fed. Reg. at 32,033. That averaging period is not reflected in the rule. 

Other rule provisions shed no light on the requirement. The provisions that address continuous 

compliance for units that demonstrate compliance through fuel analysis only require new 

analysis when a new fuel is combusted. Proposed § 63.7540(a)(3) and (5). Equally confusing, 

proposed Table 4 (addressing operating limits) states under “6. Fuel analysis” that units must 

maintain the fuel type or fuel mixture such that the rates “calculated according to § 

63.7530(d)(3), (4) and/or (5)” are below the applicable emission limits. But, there are no such 

provisions in this proposed rule. Similarly, proposed Table 8 (addressing continuous compliance) 

requires units to combust fuel types and mixtures “used to demonstrate compliance with the 

applicable emission limit according to § 63.7530(c) or (d) as applicable.” Proposed 

§ 63.7530(d) does not address fuel analysis, and § proposed 63.7530(c) does not address the 

frequency of fuel analysis or reference any averaging procedure. 

EPA should remove the reference in proposed § 63.7515(f) to monthly analysis. If EPA retains 

the requirement, EPA must provide some explanation for it, make clear whether EPA is 

proposing use of an annual average, and allow further opportunity for comment. 

Response: See response for EPA-HQ-OAR-2002-0058-2632.1, Comment Excerpt Number 46.
223

Commenter Name: Lee B. Zeugin

Commenter Affiliation: Utility Air Regulatory Group

Document Control Number: EPA-HQ-OAR-2002-0058-2880.1

Comment Excerpt Number: 31

Comment: All fuel analysis under the rule must be conducted according to an approved sitespecific plan and according to specific procedures for sampling, preparation, and analysis. 

Proposed §§ 63.7510(a) and (b), 63.7521. Although UARG does not object to a requirement to 

submit a plan or to use standardized procedures, EPA’s proposed requirements are in many 

instances overly prescriptive. The primary objective should be to obtain fuel samples that are 

representative of the fuel that is being combusted. Because there is so much diversity in how fuel 

is received, stored, and processed at individual facilities, EPA needs to allow more flexible 

procedures to accomplish the primary objective. 

Under proposed § 63.7521(b)(1), the proposed fuel analysis plan must be submitted to the 

Administrator at least 60 days before the fuel analysis. Because some of the information required 

to be included may change from analysis to analysis, UARG assumes EPA intends sources to 

submit a new plan or update the existing approved plan if information changes. For example, the 

plan must include identification of all fuel types anticipated to be combusted and whether the 

source or fuel supplier will conduct the analysis. Proposed § 63.7521(b)(2). Although it might be 

possible to submit that information 60 days in advance of the initial demonstration and receive 

approval before conducting the analysis, it may not be possible for subsequent analysis in 

response to changes in fuel type or fuel mixtures (since those might occur with less notice or 

planning). The requirement to submit a new or revised plan also makes little sense if monthly 

analysis is required. UARG requests that EPA either remove the requirement for advance 

submittal and approval of a plan after the initial compliance demonstration, or remove the 

requirement to include in the plan information that might change. 

Proposed § 63.7521 also includes very specific requirements for collecting composite fuel 

samples. For belt sampling, the rule requires that the belt be stopped. Proposed 63.7521(c)(1)(i). 

This requirement is not reasonable and apparently would not allow for the use of continuous belt

samplers. In addition, many belts cannot be restarted with coal on them because the belt is too 

heavy for the motor to start. For sampling piles or trucks, the rule requires (among other things) 

use of a “square shovel,” collection of samples at a depth of exactly “18 inches,” collection at 

five locations “uniformly spaced over the surface of the pile,” and breaking of pieces larger that 

exactly 3 inches. Proposed § 63.7521(c)(2), (d). Although UARG does not object to the intent 

behind these requirements, representative samples can be taken with shovels of other shapes, at 

depths greater or less than 18 inches, and without measuring the actual size of individual coal 

pieces. UARG requests that EPA remove the prohibition on moving belt samplers, and 

reexamine and moderate the pile sampling requirements to provide more realistic criteria (e.g., 

use the same shovel for all samples, collect samples at a uniform depth of approximately 18 

inches, and break apart large pieces (e.g., pieces greater than 3 inches). 
224

Response: See the response to EPA-HQ-OAR-2002-0058-2801.1, Comment Excerpt Number 

55 for procedures used to collect and prepare the samples. See the response to EPA-HQ-OAR2002-0058-2632.1, Comment Excerpt Number 48 for a clarification of the fuel analysis plan 

submittals.

Commenter Name: Christopher S. Colman

Commenter Affiliation: Hovensa LLC

Document Control Number: EPA-HQ-OAR-2002-0058-2863.1

Comment Excerpt Number: 46

Comment: If a facility’s fuel consistently tests below the limit, for 12 consecutive months for 

example, the facility should be able to request a relaxation of the monthly requirement. Such 

tests have very low detection limits and can only be performed at a small number of labs, in 

HOVENSA’s case more than a thousand miles away from the facility. Monthly testing 

indefinitely seems onerous. 

Response: See response to EPA-HQ-OAR-2002-0058-2632.1, Comment Excerpt Number 46.

Commenter Name: Christopher S. Colman

Commenter Affiliation: Hovensa LLC

Document Control Number: EPA-HQ-OAR-2002-0058-2863.1

Comment Excerpt Number: 47

Comment: Proposed Rule Language §63.7521(c): 

”At a minimum, you must obtain three composite fuel samples for each fuel type according to 

the procedures in paragraph (c)(1) or (2) of this section.” 

Comments: 

Rule identifies procedures for collecting composite samples from belt or screw feeders and fuel 

piles or trucks; however the rule does not provide procedures for collecting a liquid composite 

sample from a tank system. The rule should include the procedures for collecting composite 

samples from tanks. 

Response: See the response to EPA-HQ-OAR-2002-0058-2801.1, Comment Excerpt Number 

55.

Commenter Name: Lee B. Zeugin

Commenter Affiliation: Utility Air Regulatory Group

Document Control Number: EPA-HQ-OAR-2002-0058-2880.1

Comment Excerpt Number: 72
225

Comment: Proposed § 63.7515(g) requires reporting of the “results of performance tests (stack 

test and fuel analyses)” and either verification that the operating limits for the unit have not 

changed, or documentation of revised operating parameters according to § 63.7530. It not clear 

whether a unit that has not changed fuel type or fuel mixture since the last performance test must 

perform a fuel analysis or can simply verify that the fuel has not changed. Requiring re-analysis 

if the fuel has not changed is inconsistent with proposed § 63.7540(a)(4) and (6). 75 Fed. Reg. at 

32,058-59. 

Response: See response to EPA-HQ-OAR-2002-0058-2880.1, Comment Excerpt Number 30. 

Commenter Name: Jim Griffin

Commenter Affiliation: American Chemistry Council

Document Control Number: EPA-HQ-OAR-2002-0058-2792.1

Comment Excerpt Number: 179

Comment: COMMENTS ON PROPOSED FUEL ANALYSIS REQUIREMENTS. Although 

the proposed emission limits for HCl and Hg are so low that this option may not be widely 

exercised, we support the inclusion of an option for compliance with emission limits through fuel 

analysis. We would like EPA to confirm that for single fuel units, the exemption from fuel 

analysis still applies for solid or liquid fueled boilers that startup on natural gas or that are 

burning process gases in a boiler for emissions control and not for heat value. Where EPA is 

requiring fuel analyses for multi-fuel boilers for determining fuel operating limits for Hg and 

HCl, EPA should not include gaseous fuels in the fuel testing requirements since collecting 

samples of these gases is dangerous and concentrations of chlorine and mercury in gaseous fuels 

will be very small and have virtually no effect on the total amount of mercury and chlorine being 

input to the boiler. We offer the following additional specific comments on the fuel analysis 

option. 

Response: See response for EPA-HQ-OAR-2002-0058-3213.1, Comment Excerpt Number 120.

Commenter Name: Jim Griffin

Commenter Affiliation: American Chemistry Council

Document Control Number: EPA-HQ-OAR-2002-0058-2792.1

Comment Excerpt Number: 180

Comment: Facilities Should Not Be Required To Perform Fuel Analysis For Each Fuel 

Supplier. EPA is proposing to require a fuel analysis from each supplier and to require monthly 

fuel analyses for facilities that can comply using a fuel analysis approach instead of stack testing 

for mercury and HCl. Some facilities purchase fuels from many different suppliers, and it is 

unreasonable to require a facility to perform fuel sampling for each and every supplier of a 

certain type of fuel. A representative sample from a fuel pile or fuel tank should be sufficient. 

EPA should revise the requirement to allow one fuel sample per fuel type not per fuel supplier. 
226

Response: See the response to EPA-HQ-OAR-2002-0058-2801.1, Comment Excerpt Number 

55.

Commenter Name: Jim Griffin

Commenter Affiliation: American Chemistry Council

Document Control Number: EPA-HQ-OAR-2002-0058-2792.1

Comment Excerpt Number: 183

Comment: The Methods for Fuel Sampling and Analysis That Were Approved Under The 2004 

Boiler Rule Need To Be Added To The Rule. Table 6 to Subpart DDDDD of Part 63 lists several 

EPA and ASTM methods to be used for fuel sample collection, processing, and analysis. The 

phrase "or equivalent" has been added to all the methods listed in Table 6. The term "equivalent" 

is specifically defined in section 63.7575 for sample collection procedure, sample compositing 

procedure, sample preparation procedure, heat content determination, fuel moisture 

determination, and mercury determination, but no definition is provided for HCl. This should be 

rectified by either adding a new section addressing HCl under the definition of "equivalent," or 

by modifying the current definition for an "equivalent pollutant determinative or analytical 

procedure" (section (6) under the definition) to explicitly include HCl. 

Response: NEED RESPONSE See response for EPA-HQ-OAR-2002-0058-3213.1, Comment 

Excerpt Number 122.

Commenter Name: Jim Eubank

Commenter Affiliation: Kentucky Division of Air Quality

Document Control Number: EPA-HQ-OAR-2002-0058-3176.2

Comment Excerpt Number: 8

Comment: There will be a significant increase in fuel sample analysis. EPA needs to clarify who 

or what entity is responsible for conducting these analysis and what role the Division plays in 

these analysis. 

Response: The affected source is responsible for conducting all necessary fuel analysis or 

ensuring that fuel suppliers conduct fuel analysis if affected sources opt to use a fuel supplier 

certification instead of conducting on-site sampling. The affected source is also required to 

submit a fuel analysis plan for review and approval by the delegated authority. This plan is 

supposed to be submitted to the delegated authority 60 days before the initial compliance 

demonstration.
227

Detection Levels

Commenter Name: Dwayne Arino

Commenter Affiliation: Jeld-Wen, Inc

Document Control Number: EPA-HQ-OAR-2002-0058-0856.1

Comment Excerpt Number: 1

Comment: The limits suggested in the proposed rule approach levels that are barely detectable 

by current acceptable testing methodology. For example, the proposed limit for particulate matter 

(PM) in the Biomass Subcategory is 0.02 1b/10^6 Btu. One of EPA’s recommended approved 

testing methods (Other Test Method 28) reports to be problematic and fraught with error when 

used in extracting both organic and inorganic particulate matter fractions. If this remains the 

case, the EPA must determine a suitable and repeatable method that accounts for process 

variability inherent in typical boilers. 

Response: Filterable particulate matter is a surrogate for metal hazardous air pollutants, and 

filterable particulate matter test results were used to develop the particulate matter emission 

limits. Therefore any concern with OTM 28, which measures condensable particulate matter, is 

not relevant to this rulemaking.

Commenter Name: Michael L. Steele

Commenter Affiliation: CraftMaster Manufacturing, Inc

Document Control Number: EPA-HQ-OAR-2002-0058-1907.1

Comment Excerpt Number: 24

Comment: How is non-detect stack test data treated for compliance purposes? 

Response: Regarding EPA’s guidance on reporting of non-detect values for compliance 

purposes, sources should use the guidance in Section 9.9 of Method 23 that all measurements 

below the detection limit (calculated as per Method 23) should be treated as zero for the purpose 

of calculating dioxins/furans emissions. 

Commenter Name: Kathryn M. Cunningham

Commenter Affiliation: Consumers Energy Company

Document Control Number: EPA-HQ-OAR-2002-0058-2904.1

Comment Excerpt Number: 2

Comment: The I ppm limit is not reliably measureable. The performance specification for CO 

Continuous Emissions Monitoring Systems ("CEMS") (PS 4A) allows up to 5ppmv difference in 

the relative accuracy. 
228

Response: See the preamble for revisions to the CO limitations and compliance demonstration 

methods. 

Commenter Name: Lee B. Zeugin

Commenter Affiliation: Utility Air Regulatory Group

Document Control Number: EPA-HQ-OAR-2002-0058-2880.1

Comment Excerpt Number: 2

Comment: The Proposed Rule Fails to Address in a Reasoned Manner HAP Emissions That Are 

At or Below the Method Detection Limit. EPA’s effort to set emission limits for all HAPs 

emitted by industrial boilers is greatly complicated by the fact that a number of HAPs are emitted 

at levels at or below the detection limit of the method used to collect and analyze HAP emissions 

during the IB MACT ICR. Detection limit issues have significant impacts on MACT standard 

setting as well as later compliance demonstrations. 

Any reasoned discussion of detection limit issues must begin with a clear definitional framework 

for two important terms -- “detection limit” and “quantitation limit.” The detection limit defines 

the threshold below which a test method cannot distinguish whether a substance is present or not. 

In EPA’s prior efforts to implement the Clean Water Act, the Agency defined the term “detection 

limit” to mean “the minimum concentration of an analyte (substance) that can be measured and 

reported with a 99% confidence that the analyte concentration is greater than zero.” 40 C.F.R. § 

136.2(f). Stated differently, a measured value at the detection limit has an error band as large as 

the value being reported. One does not have great confidence in the quantity of material 

measured because the error band is so large; one simply knows it is more likely than not that the 

substance is actually present. 

By contrast, the “quantitation limit” is the smallest detectable concentration of analyte greater 

than the detection limit where the accuracy, including both precision and bias, achieves the 

objectives of the intended purpose of the measurement. Target objectives are generally stated in 

terms of the precision of the measurement expressed as a relative standard deviation (“RSD”). 

There is no single agreed approach for determining the quantitation limit of a method. The 

quantitation limit for a given method can be three to ten times higher than that method’s 

detection limit depending on method-specific factors such as matrix effects and purity of 

reagents. One does not have confidence in the accuracy of a measured value unless that value is 

at or above the quantitation limit for the method. 

Testing accuracy, reliability, and representativeness are vital in setting MACT standards because 

those limits must reflect the level of performance “achieved in practice” by the best performing 

units. They are also vital to permittees because test results, once they are sworn to be “accurate” 

on a monitoring report, are virtually unassailable in an enforcement action. See Sierra Club v. 

Union Oil Co. of Cal., 813 F.2d 1480,1492 (9th Cir. 1987) (“We conclude that when a 

permittee’s reports indicate that the permittee has exceeded permit limitations, the permittee may 

not impeach its own reports by showing sampling error.”); see also Conn. Fund for the Env’t, 

Inc. v. Upjohn Co., 660 F. Supp. 1397, 1416-17 (D. Conn. 1987); NRDC v. Texaco Refining & 
229

Mktg., Inc., 906 F.2d 934, 936 (3rd Cir. 1990); and United States v. ALCOA, 824 F. Supp. 640, 

648-49 (E.D. Tex. 1993). 

The court in Amoco Oil Co. v. EPA, 501 F.2d 722, 743 (D.C. Cir. 1974), grappled with the 

accuracy of analytical methods in compliance demonstrations. There, the court stated: The 

possibility of statistical measurement error, which is often unavoidable where regulations set 

quantitative standards, does not detract from an agency’s power to set such standards. It merely 

deprives the agency of the power to find a violation of the standards, in enforcement 

proceedings, where the measured departure from them is within the boundaries of probable 

measurement error. Furthermore, if the test methods eventually adopted raise a greater potential 

for error than is practical or necessary, a reviewing court may order revisions. 501 F.2d at 743. 

The important point from this legal history is that an emission limit must not be set below the 

quantitation limit of the method chosen for demonstrating compliance. If an emission standard is 

set below the quantitation level, then as the court in Amoco Oil cautioned, the standard would 

not be enforceable. 

Response: Test method measurement imprecision is a contributor to the variability of a set of 

emissions data. One element is associated with method detection capabilities and a second is a 

function of the measurement value. Measurement imprecision is proportionally highest for 

values measured below or near a method’s detection level and proportionally decreasing for 

values measured above the method detection level. 

Probability procedures applied in calculating the floor or an emissions limit inherently and 

reasonably account for emissions data variability including measurement imprecision when the 

database represents multiple tests from multiple emissions units for which all of the data are 

measured significantly above the method detection level. That is less true when the database 

includes emissions occurring below method detection capabilities and are reported as the method 

detection level values.

We applied the following procedures to account for the effect of measurement imprecision 

associated with a database that includes method detection level data. The first step was to define 

a method detection level that is representative of the data used in establishing the floor or 

emissions limit and that also minimizes the influence of an outlier test-specific method detection 

level value. We reviewed each pollutant-specific data set to identify the highest test-specific 

method detection level reported that was also equal to or less than the average emissions level 

(i.e., unadjusted for probability confidence level) calculated for the data set. We believe that this 

approach is representative of the data collected to develop the floor or emissions limit while to 

some degree minimizes the effect of a test(s) with an inordinately high method detection level 

(e.g., the sample volume was too small, the laboratory technique was insufficiently sensitive, or 

the procedure for determining the detection level was other than that specified).

The second step in the process is to calculate three times the representative method detection 

level and compare that value to the calculated floor or emissions limit. If three times the 

representative method detection level were less than the calculated floor or emissions limit 
230

calculated from the UPL, we would conclude that measurement variability was adequately 

addressed. The calculated floor or emissions limit would need no adjustment. If, on the other 

hand, the value equal to three times the representative method detection level were greater than 

the UPL, we would conclude that the calculated floor or emissions limit does not account 

entirely for measurement variability. If indicated, we substituted the value equal to three times 

the representative method detection level to apply as the adjusted floor or emissions limit. This 

adjusted value would ensure measurement variability is adequately addressed in the floor or the 

emissions limit. 

Commenter Name: Steve Zika

Commenter Affiliation: Hampton Lumber Mills, Inc

Document Control Number: EPA-HQ-OAR-2002-0058-2817.1

Comment Excerpt Number: 3

Comment: The proposed Mercury limits for boilers that burn only biomass have been 

demonstrated in the literature to approach levels that can barely be detected by state of the art 

source testing equipment. The laboratory test methods used to analyze mercury in our biomass 

cannot detect mercury at the levels required to demonstrate compliance. The proposed limits also 

do not reflect the wide variability of boilers that burn biomass, the quantity of mercury that may 

naturally be found in biomass and the costs to remove the Mercury. We urge the agency to 

consider, as they mention in the proposed rules, that a facility could avoid installing controls 

where there is a reasonable case that emissions are safe. 

Response: Probability procedures applied in calculating the floor or an emissions limit 

inherently and reasonably account for emissions data variability including measurement 

imprecision when the database represents multiple tests from multiple emissions units for which 

all of the data are measured significantly above the method detection level. That is less true 

when the database includes emissions occurring below method detection capabilities and are 

reported as the method detection level values.

We applied the following procedures to account for the effect of measurement imprecision 

associated with a database that includes method detection level data. The first step was to define

a method detection level that is representative of the data used in establishing the floor or 

emissions limit and that also minimizes the influence of an outlier test-specific method detection 

level value. We reviewed each pollutant-specific data set to identify the highest test-specific 

method detection level reported that was also equal to or less than the average emissions level 

(i.e., unadjusted for probability confidence level) calculated for the data set. We believe that this 

approach is representative of the data collected to develop the floor or emissions limit while to 

some degree minimizes the effect of a test(s) with an inordinately high method detection level 

(e.g., the sample volume was too small, the laboratory technique was insufficiently sensitive, or 

the procedure for determining the detection level was other than that specified).

The second step in the process is to calculate three times the representative method detection 

level and compare that value to the calculated floor or emissions limit. If three times the 
231

representative method detection level were less than the calculated floor or emissions limit 

calculated from the UPL, we would conclude that measurement variability was adequately 

addressed. The calculated floor or emissions limit would need no adjustment. If, on the other 

hand, the value equal to three times the representative method detection level were greater than 

the UPL, we would conclude that the calculated floor or emissions limit does not account 

entirely for measurement variability. If indicated, we substituted the value equal to three times 

the representative method detection level to apply as the adjusted floor or emissions limit. This 

adjusted value would ensure measurement variability is adequately addressed in the floor or the 

emissions limit. 

Commenter Name: Richard L. Killion

Commenter Affiliation: Babcock and Wilcox Power Generation Group

Document Control Number: EPA-HQ-OAR-2002-0058-2722.1

Comment Excerpt Number: 8

Comment: B&W is concerned that continuous CO emissions monitoring systems (CEMS) 

equipment may not have sufficient accuracy, resolution, and repeatability to reliably demonstrate 

compliance at the proposed limits. 

Response: See the preamble for revisions to the CO limitations and compliance demonstration 

methods. 

Commenter Name: Nilaksh Kothari

Commenter Affiliation: Manitowoc Public Utilities

Document Control Number: EPA-HQ-OAR-2002-0058-2810.1

Comment Excerpt Number: 8

Comment: MPU recommends that EPA increase the proposed limits on CO to allow margin for 

the existing CEM technology. The proposed CO limits are so low that the zero shift that 

currently occurs in CEM grade equipment will become a significant factor. Attached, please find 

calibration detail for a CO CEMs documenting the typical CO zero shift. 

Response: See the preamble for revisions to the CO limitations and compliance demonstration 

methods. 

Commenter Name: Steve Zika

Commenter Affiliation: Hampton Lumber Mills, Inc

Document Control Number: EPA-HQ-OAR-2002-0058-2817.1

Comment Excerpt Number: 9
232

Comment: Hampton is concerned that the proposed HCL, Mercury and Dioxin/Furan standards 

may be so low that demonstrating compliance may not be possible where the standard is less 

than the method detection limit of the source test. In other words, the proximity of the standard 

to the detection limit makes testing for compliance technically impossible. Spending more 

money on source testing at these extremely low levels will not resolve the problem of arbitrarily 

setting a standard at the method detection limit An example of this is that when Hampton 

collected fuel samples, the detection levels in the EPA test protocols were higher than the 

proposed limits for Mercury and HCL. 

Response: We applied the following procedures to account for the effect of measurement 

imprecision associated with a database that includes method detection level data. The first step 

was to define a method detection level that is representative of the data used in establishing the 

floor or emissions limit and that also minimizes the influence of an outlier test-specific method 

detection level value. We reviewed each pollutant-specific data set to identify the highest testspecific method detection level reported that was also equal to or less than the average emissions 

level (i.e., unadjusted for probability confidence level) calculated for the data set. We believe 

that this approach is representative of the data collected to develop the floor or emissions limit 

while to some degree minimizes the effect of a test(s) with an inordinately high method detection 

level (e.g., the sample volume was too small, the laboratory technique was insufficiently 

sensitive, or the procedure for determining the detection level was other than that specified).

The second step in the process is to calculate three times the representative method detection 

level and compare that value to the calculated floor or emissions limit. If three times the 

representative method detection level were less than the calculated floor or emissions limit 

calculated from the UPL, we would conclude that measurement variability was adequately 

addressed. The calculated floor or emissions limit would need no adjustment. If, on the other 

hand, the value equal to three times the representative method detection level were greater than 

the UPL, we would conclude that the calculated floor or emissions limit does not account 

entirely for measurement variability. If indicated, we substituted the value equal to three times 

the representative method detection level to apply as the adjusted floor or emissions limit. This 

adjusted value would ensure measurement variability is adequately addressed in the floor or the 

emissions limit. 

The final rule will clarify and reiterate the need to report D/F emissions concentration as 

prescribed in Method 23, on a mass basis and to follow the method's procedures for reporting 

values measured below the test-specific minimum detectable limit. 

Commenter Name: American Crystal Sugar Company and Michigan Sugar Company

Commenter Affiliation: Patricia Hansen and Steven Smock

Document Control Number: EPA-HQ-OAR-2002-0058-2970.1

Comment Excerpt Number: 11

Comment: It is extremely important to understand the quantification limit and apply it properly. 

The 

agency indicates this concept in the preamble to the Boiler MACT and then appears to have not 

applied it in determination of the MACT floor. If the limits are set below the true quantification 
233

limits then the result will be that every source will violate the limit. The frequency of the 

violations will be determined by the actual emissions to the limit ratio. If the actual value is at 

the MDL then 99.9% of the test results will be between zero and twice the MDL with half of 

them being above the MDL. 

Response: Probability procedures applied in calculating the floor or an emissions limit 

inherently and reasonably account for emissions data variability including measurement 

imprecision when the database represents multiple tests from multiple emissions units for which 

all of the data are measured significantly above the method detection level. That is less true when 

the database includes emissions occurring below method detection capabilities and are reported 

as the method detection level values.

We applied the following procedures to account for the effect of measurement imprecision 

associated with a database that includes method detection level data. The first step was to define 

a method detection level that is representative of the data used in establishing the floor or 

emissions limit and that also minimizes the influence of an outlier test-specific method detection 

level value. We reviewed each pollutant-specific data set to identify the highest test-specific 

method detection level reported that was also equal to or less than the average emissions level 

(i.e., unadjusted for probability confidence level) calculated for the data set. We believe that this 

approach is representative of the data collected to develop the floor or emissions limit while to 

some degree minimizes the effect of a test(s) with an inordinately high method detection level 

(e.g., the sample volume was too small, the laboratory technique was insufficiently sensitive, or 

the procedure for determining the detection level was other than that specified).

The second step in the process is to calculate three times the representative method detection 

level and compare that value to the calculated floor or emissions limit. If three times the 

representative method detection level were less than the calculated floor or emissions limit 

calculated from the UPL, we would conclude that measurement variability was adequately 

addressed. The calculated floor or emissions limit would need no adjustment. If, on the other 

hand, the value equal to three times the representative method detection level were greater than 

the UPL, we would conclude that the calculated floor or emissions limit does not account 

entirely for measurement variability. If indicated, we substituted the value equal to three times 

the representative method detection level to apply as the adjusted floor or emissions limit. This 

adjusted value would ensure measurement variability is adequately addressed in the floor or the 

emissions limit. 

Commenter Name: Douglas A. McWilliams

Commenter Affiliation: ArcelorMittal USA, Inc

Document Control Number: EPA-HQ-OAR-2002-0058-2811.1

Comment Excerpt Number: 11

Comment: Detection limits and quantitation limits are critical indicators of the ability of test 

methods to quantify a measurement. Limit of detection, method detection limit and instrument 
234

detection limit are generally considered the minimum concentration that can be distinguished 

from zero by a test method, and the quantitation limit is considered the minimum level that can 

be quantified with acceptable uncertainty. These terms have statistical definitions designed to 

determine the level near zero where the measurement response becomes indistinct. 

A common definition of the limit of detection for environmental measurements is based on the 

results measured in "blank" samples. [Footnote: Keith, L.H., Crummet, W., Deegan, J., Libby, 

R.A., Taylor, J.K. and Wentler, G., "Principles of Environmental Analysis," Anal. Chem. 1983, 

55, 2210-2218.] Blanks are samples that are handled and treated in exactly the same manner as 

test samples, and are otherwise similar in composition, but which do not contain the pollutant of 

interest. The limit of detection is commonly defined as the lowest concentration that can be 

statistically different from a blank. Statistically at the 99% confidence level, this limit of 

detection is equal to three times the standard deviation (recommended definition for 

environmental measurements). Id. 

The limit of quantitation is defined as the level above which quantitative results may be obtained 

with a specified degree of confidence. Id. Uncertainty of a measurement value decreases as the 

value increases above the limit of detection. Statistically, the limit of quantitation is equal to ten 

times the standard deviation at the 99% confidence level and uncertainty of ±30% 

(recommended definition for environmental measurements). Id. Measurement results between 

the limit of detection and limit of quantitation are greater than zero but cannot be quantified with 

less than 30% uncertainty at the 99% confidence level. It has been recommended that 

quantitative interpretation, decision-making, and regulatory actions should be limited to data at 

or above the limit of quantitation. Id. 

An example may illustrate these concepts. Consider a group of people attempting to measure the 

thickness of the same toothpick using a common ruler. The smallest graduation on the ruler is 

1/32 inches and the true thickness of the toothpick is about 2.5/32 inches. This value appears to 

be near but greater than "zero" as measurable by the ruler. Each individual measures the 

toothpick three times. More than likely, each individual will report a different average of the 

three results. For our purposes, we assume the mean of these results is 2.6/32 inches and the 

standard deviation is 0.25/32 inches. The limit of detection therefore would be 3x 0.25/32 = 

0.75/32 inches and the limit of quantitation would be 2.5/32 inches. Thus, the mean toothpick 

measurement of 2.6/32 inches is considered greater than zero and accurate to at least ±30% at the 

99% confidence level. 

Laboratories routinely report analytical detection limits with sample analysis results. These are 

generally determined using similar definitions as noted above, but may be based on other 

definitions. For integrated, manual stack test methods, analytical detection limits can be 

expressed as in-stack equivalent concentrations by applying a sample volume. 

Using the average analytical method detection limits reported by the laboratories and typical 

sample volumes from the recent tests of coke oven gas-fired boilers, the in-stack analytical 

method limit of detection (A-LOD) and analytical method limit of quantitation (ALOQ) were 

calculated for HCI, mercury, dioxins/furans and filterable particulate matter measurements (see 

table below). The proposed Gas-2 emission limits are less than the A-LOQ except for filterable 
235

particulate matter. Emission rates from these boilers at or near the Gas-2 emission limits cannot 

be reliably quantified with the available analytical methods. 

[ See submittal for a comparison of uncontrolled (inlet) and hypothetical controlled (outlet) HAP 

concentrations, proposed Gas-2 emission limits, analytical method limit of detection (A-1,0D) 

and total method limit of detection based on field blanks (FB-LOD). Data are based on tests of 

four coke oven gas-fired boilers.] 

The test results from the coke oven gas-fired stack testing indicate that measurement 

methodology is insufficient to enforce the proposed Gas-2 emission standards. First, the average 

dioxin emission rate for all four boilers is below the A-LOQ and, therefore, cannot be reliably 

quantified. Since the average emissions from all four boilers exceed the proposed Gas-2 emission 

limits for HC1, mercury and CO, coke oven gas-fired units would be expected to install control 

measures to try and reduce emissions below the Gas-2 emission standards. Assuming emission 

controls for HC1 and mercury with optimistic emission reduction efficiencies (unproven, as 

discussed elsewhere in these comments), the controlled levels would be far lower than the ALOQ. See table above. These emission levels are essentially immeasurable in any statistically 

reliable way. 

Response: Test method measurement imprecision is a contributor to the variability of a set of 

emissions data. One element is associated with method detection capabilities and a second is a 

function of the measurement value. Measurement imprecision is proportionally highest for 

values measured below or near a method’s detection level and proportionally decreasing for 

values measured above the method detection level. 

Probability procedures applied in calculating the floor or an emissions limit inherently and 

reasonably account for emissions data variability including measurement imprecision when the 

database represents multiple tests from multiple emissions units for which all of the data are 

measured significantly above the method detection level. That is less true when the database 

includes emissions occurring below method detection capabilities and are reported as the method 

detection level values.

We applied the following procedures to account for the effect of measurement imprecision 

associated with a database that includes method detection level data. The first step was to define 

a method detection level that is representative of the data used in establishing the floor or 

emissions limit and that also minimizes the influence of an outlier test-specific method detection 

level value. We reviewed each pollutant-specific data set to identify the highest test-specific 

method detection level reported that was also equal to or less than the average emissions level 

(i.e., unadjusted for probability confidence level) calculated for the data set. We believe that this 

approach is representative of the data collected to develop the floor or emissions limit while to 

some degree minimizes the effect of a test(s) with an inordinately high method detection level 

(e.g., the sample volume was too small, the laboratory technique was insufficiently sensitive, or 

the procedure for determining the detection level was other than that specified).
236

The second step in the process is to calculate three times the representative method detection 

level and compare that value to the calculated floor or emissions limit. If three times the 

representative method detection level were less than the calculated floor or emissions limit 

calculated from the UPL, we would conclude that measurement variability was adequately 

addressed. The calculated floor or emissions limit would need no adjustment. If, on the other 

hand, the value equal to three times the representative method detection level were greater than 

the UPL, we would conclude that the calculated floor or emissions limit does not account 

entirely for measurement variability. If indicated, we substituted the value equal to three times 

the representative method detection level to apply as the adjusted floor or emissions limit. This 

adjusted value would ensure measurement variability is adequately addressed in the floor or the 

emissions limit. 

Commenter Name: Douglas A. McWilliams

Commenter Affiliation: ArcelorMittal USA, Inc

Document Control Number: EPA-HQ-OAR-2002-0058-2811.1

Comment Excerpt Number: 12

Comment: Previous studies have shown that analytical detection limits typically represent only 

a small portion of the total measurement error inherent in stack test methods, with errors 

associated with equipment and sampling media preparation, sample collection, recovery, 

handling and preparation also contributing significantly to total measurement error. Using the 

definitions above, detection and quantitation limits also can be calculated from field blank results 

obtained during stack tests. One complete sample train field blank was obtained for each 

integrated manual measurement method (i.e., Method 23, 26A, 29 and 101A sampling trains) at 

each boiler generating a total of four field blank results during the test program. Because Method 

5B measurements were included with the Method 26A, 29 and 101 A measurements, a total of 

12 field blank results were generated. The limit of quantitation based on field blank results (FBLOQ) is much greater than the A-LOQ as expected from previous studies. The proposed Gas-2 

emission limits are less than the FB-LOQ for all compounds except filterable particulate matter. 

For all of these compounds, the measurement methodology is insufficient to reliably quantify 

emissions at or near the proposed Gas-2 emission levels, which makes them impractical and 

infeasible to enforce for COG-fired boilers. 

Response: We agree that test method measurement imprecision is a contributor to the variability 

of a set of emissions data. One element is associated with method detection capabilities and a 

second is a function of the measurement value. Measurement imprecision is proportionally 

highest for values measured below or near a method’s detection level and proportionally 

decreasing for values measured above the method detection level. 

Probability procedures applied in calculating the floor or an emissions limit inherently and 

reasonably account for emissions data variability including measurement imprecision when the 

database represents multiple tests from multiple emissions units for which all of the data are 

measured significantly above the method detection level. That is less true when the database 
237

includes emissions occurring below method detection capabilities and are reported as the method 

detection level values.

We applied the following procedures to account for the effect of measurement imprecision 

associated with a database that includes method detection level data. The first step was to define 

a method detection level that is representative of the data used in establishing the floor or 

emissions limit and that also minimizes the influence of an outlier test-specific method detection 

level value. We reviewed each pollutant-specific data set to identify the highest test-specific 

method detection level reported that was also equal to or less than the average emissions level 

(i.e., unadjusted for probability confidence level) calculated for the data set. We believe that this 

approach is representative of the data collected to develop the floor or emissions limit while to 

some degree minimizes the effect of a test(s) with an inordinately high method detection level 

(e.g., the sample volume was too small, the laboratory technique was insufficiently sensitive, or 

the procedure for determining the detection level was other than that specified).

The second step in the process is to calculate three times the representative method detection 

level and compare that value to the calculated floor or emissions limit. If three times the 

representative method detection level were less than the calculated floor or emissions limit 

calculated from the UPL, we would conclude that measurement variability was adequately 

addressed. The calculated floor or emissions limit would need no adjustment. If, on the other 

hand, the value equal to three times the representative method detection level were greater than 

the UPL, we would conclude that the calculated floor or emissions limit does not account 

entirely for measurement variability. If indicated, we substituted the value equal to three times 

the representative method detection level to apply as the adjusted floor or emissions limit. This 

adjusted value would ensure measurement variability is adequately addressed in the floor or the 

emissions limit. 

Commenter Name: Ann W. McIver

Commenter Affiliation: Citizens Energy Group

Document Control Number: EPA-HQ-OAR-2002-0058-2875.1

Comment Excerpt Number: 12

Comment: Citizens is also concerned with the practicality of CO CEMs at such low emission 

levels. The nature of the relative accuracy testing is such that the accuracy of the facility’s CEM 

and the reference method could interfere with the ability of a system to pass the relative accuracy 

test. Citizens recommends that the EPA develop certification protocols for facilities with 

emissions less than 100 parts per million to ensure that the ability to certify a CEMs is not 

influenced by the statistical testing procedures. 

Response: See the preamble for revisions to the CO limitations and compliance demonstration 

methods. 

Commenter Name: Douglas A. McWilliams
238

Commenter Affiliation: ArcelorMittal USA, Inc

Document Control Number: EPA-HQ-OAR-2002-0058-2811.1

Comment Excerpt Number: 13

Comment: Instrument methods, like Method 10 for measuring CO, also have levels of 

imprecision that affect the reliability of the measurements. A stack gas sample is extracted, dried 

and filtered, and analyzed for CO concentration using a calibrated gas analyzer. Analytical 

precision, accuracy, linearity and electrical noise contribute to error associated with the analyzer, 

typically on the order of ±2% of the full scale measurement range. The oxygen content also is 

measured to correct the CO concentration to 3% 02, often using a similar instrumental test 

method (Method 3A). The analyzer range selected for a particular test must consider both the 

regulatory limit and the potential for short term excursions during a test period. For a source that 

has relatively steady CO concentrations near the regulatory limit, a range of 2 to 3 times the 

regulatory limit may be selected. If the CO concentration varies significantly above the 

regulatory limit, a range much higher than the regulatory limit may be chosen. In the recent test 

program on coke oven gas-fired boilers, the analyzer range varied from 0-10 to 0-900 ppm to 

capture the range of emissions. At 0-900 ppm, the A-LOD is 18 ppm, which means the 1 ppm 

CO emission limit for Gas-2 cannot be reliably detected when the range is this wide. Assuming a 

narrower range of 0-50 ppm, the A-LOD is 1 ppm assuming the detection limit is ±2% of range 

(which neglects other sources of error that are probably of equal or greater significance). The 

ALOQ would therefore be 3 ppm, which means CO levels that approach the emission limit of 1 

ppm cannot be reliably quantified. 

Response: See the preamble for revisions to the CO limitations and compliance demonstration 

methods. 

Commenter Name: Gordon M. Smith

Commenter Affiliation: Mitsubishi Polyester Film, Inc

Document Control Number: EPA-HQ-OAR-2002-0058-2912

Comment Excerpt Number: 16

Comment: A 1 ppm limit is below the accuracy level of most if not all existing CO CEMS and 

stack test methods. Calibrations are done with an allowable drift for most standards that is 

greater than 1 ppm (5 ppm is allowed by Part 60 Performance Specification 4 for a CO CEM 

spanned at 100 ppm[2 100 ppm is a typical CO CEMS span and allows the instrument to monitor 

the most common range of CO concentrations with reasonable accuracy ]). For CO monitoring, 

there are no CEMS commercially available that can accurately and predictably measure sub-1 

ppmv concentrations in the flue gas, thus it is impossible to accurate determine is a source is 

complying with a 1 ppm or even a two ppm standard and there is no way sources can provide a 

compliance margin.. The accuracy of CO CEMS is limited by the equipments ability to precisely 

remove measurement bias and interference, which includes CO2 which is the major component 

of exhaust gas. EPA needs to consider true real world monitoring schemes and recognize 

measurement limitations. 
239

In addition to CO CEMS having an allowable drift of 5%, calibration gases typically have an 

accuracy of ±2% and there is an accuracy band for sampling and conditioning. Thus, 

measurement uncertainty for a CO CEMS adds up to several percent. Furthermore, the EPA 

Methods used for units without CEMS and for calibrating CO CEMS do not define their 

detection limits, but experience shows that they are not accurate in the low ppm range, adding 

more uncertainty. While people read and report CO results below 1 or 2 ppm, there is little 

certainty associated with the accuracy of those reports. 

A CO measurement system typically consists of a sample probe, heated sample lines, a pump, a 

conditioning system, CO and O2 analyzers, calibration systems, calibration gases and a data 

acquisition system. Each of these components and systems contributes error to the CO 

measurement. Normal CO reference measurement systems such as those used for EPA Method 

10 applied to boiler/heater tests generally are not designed/tuned to achieve acceptable 

measurement performance at 1 ppm because there has been no requirement to accurately 

measure CO at these levels. Typically measurements are made on a 100 ppm analyzer range or 

perhaps 50 ppm range, to assure that any excursions in CO are captured during the test. Under 

these conditions, CO accuracy falls off dramatically as you approach single digit ppm levels. 

This strongly suggests that the accuracy of data in the ICR database at below perhaps 3 or 4 ppm 

does measurement error increases beyond the level acceptable for regulatory decision making 

(interpreting accuracy as being the 95% confidence bounds, and the acceptable level of error 

being +/- 30%). Although an earlier study[Widmer et al., Low Level Carbon Monoxide 

Monitoring for Gas Turbine Applications, presented at AWMA Symposium on Air Quality 

Measurement Methods and Technology, San Francisco, November 2002] suggests it may be 

possible to design and optimize measurement systems for better performance at single digit ppm 

CO levels, that study showed that measurement error at 1 ppm approaches 20% at 1 ppm and 

reaches the unacceptable level (30%) between 0.5 and 1 ppm. This earlier study was directed 

toward gas turbine applications, where the exhaust gas typically contains much lower 

concentrations of CO2 than boilers and process heaters. Since CO2 is a known interferent when 

using infrared absorption CO analyzers (the most common type used for reference method 

testing), achieving these levels of performance in stack gases from boilers and process heaters 

may be even more challenging. 

Response: See the preamble for revisions to the CO limitations and compliance demonstration 

methods. 

Commenter Name: Gordon M. Smith

Commenter Affiliation: Mitsubishi Polyester Film, Inc

Document Control Number: EPA-HQ-OAR-2002-0058-2912

Comment Excerpt Number: 17

Comment: These considerations clearly suggest that EPA’s reliance on CO test data of 

undocumented quality at single digit ppm levels and lower to establish CO emission limits fails 

to adequately consider uncertainty (variability) in the measurement process. The reliability of 

these data is highly questionable. A study of CO measurement errors and reproducibility by 
240

different test organizations and systems for boiler and process heater applications is required to 

quantify minimum CO levels that can be measured with acceptable uncertainty. Further, even if 

reference measurement systems and CEMS are optimized for single digit CO levels, it is likely 

that measurements at the 1 ppm level and lower have errors that are too large for regulatory 

enforcement. Therefore, the CO limits established by EPA lack scientific basis and it is 

technically infeasible to enforce a 1 ppm emission limit. 

Response: See the preamble for revisions to the CO limitations and compliance demonstration 

methods. 

Commenter Name: Jim Eubank

Commenter Affiliation: Kentucky Division of Air Quality

Document Control Number: EPA-HQ-OAR-2002-0058-3176.2

Comment Excerpt Number: 20

Comment: The MDLs are discussed a little in the major source MACT, but it does not identify 

the use of data below a MDL or how a facility should report data below a MDL. There is also no 

discussion if the testing methods were statistically challenged to meet the emission limits 

identified. 

Response: Regarding EPA’s guidance on reporting of non-detect values for compliance 

purposes, sources should use the guidance in Section 9.9 of Method 23 that all measurements 

below the detection limit (calculated as per Method 23) should be treated as zero for the purpose 

of calculating dioxins/furans emissions. 

The final rule will clarify and reiterate the need to report D/F emissions concentration as 

prescribed in Method 23, on a mass basis and to follow the method's procedures for reporting 

values measured below the test-specific minimum detectable limit. 

Commenter Name: Michael Hutcheson

Commenter Affiliation: Ameren Services

Document Control Number: EPA-HQ-OAR-2002-0058-2803.1

Comment Excerpt Number: 22

Comment: Compliance with the emission standard that results from such a MACT floor 

analysis, then becomes a mere test of the stack tester’s ability to test in a way that the resulting 

method detection limit is less than the emission standard for the source category. If the tester is 

unable to obtain a test run (or runs) that result in a method detection limit below the standard, 

then compliance with the standard can not be shown even if the results of the test are below 

detection limits. The result will be sources being unable to show compliance with a standard 

even if the actual levels of the pollutant in the exhaust is below any levels actually detected at 
241

sources used to establish the MACT Floor and associated MACT standard. In these cases, 

sources would have to repeat costly stack testing even though they should be shown to be in 

compliance. 

In addition, Ameren questions how sources can show with any confidence that any test data 

(even at the method detection limit) is representative of an actual emission rate below the MACT 

floor and below the resulting standards set. If as US EPA asserts, the method detection limit is 

the lowest value at which one is assured that a analyte has been detected then statistically, any 

result at the MDL really reflects a value anywhere from 0 to 2 times the MDL. For several 

source categories and pollutants, including liquid fuel fired sources and Hg, dioxin, and HCL 

standards, the MACT standard proposed is below the practical quantification limit of the stack 

test methods and also below several BDL test results reported in the US EPA’s Boiler MACT 

ICR stack test database (EPAHQ-OAR-2002-0058-0789). In essence, US EPA has data in the 

docket showing that several sources who could not detect these pollutants in stack exhaust for 

their affected source would not be able to comply with the standards set. 

Response: We agree that test method measurement imprecision is a contributor to the variability 

of a set of emissions data. One element is associated with method detection capabilities and a 

second is a function of the measurement value. Measurement imprecision is proportionally 

highest for values measured below or near a method’s detection level and proportionally 

decreasing for values measured above the method detection level. 

Probability procedures applied in calculating the floor or an emissions limit inherently and 

reasonably account for emissions data variability including measurement imprecision when the 

database represents multiple tests from multiple emissions units for which all of the data are 

measured significantly above the method detection level. That is less true when the database 

includes emissions occurring below method detection capabilities and are reported as the method 

detection level values.

We applied the following procedures to account for the effect of measurement imprecision 

associated with a database that includes method detection level data. The first step was to define 

a method detection level that is representative of the data used in establishing the floor or 

emissions limit and that also minimizes the influence of an outlier test-specific method detection 

level value. We reviewed each pollutant-specific data set to identify the highest test-specific 

method detection level reported that was also equal to or less than the average emissions level 

(i.e., unadjusted for probability confidence level) calculated for the data set. We believe that this 

approach is representative of the data collected to develop the floor or emissions limit while to 

some degree minimizes the effect of a test(s) with an inordinately high method detection level 

(e.g., the sample volume was too small, the laboratory technique was insufficiently sensitive, or 

the procedure for determining the detection level was other than that specified).

The second step in the process is to calculate three times the representative method detection 

level and compare that value to the calculated floor or emissions limit. If three times the 

representative method detection level were less than the calculated floor or emissions limit 

calculated from the UPL, we would conclude that measurement variability was adequately 
242

addressed. The calculated floor or emissions limit would need no adjustment. If, on the other 

hand, the value equal to three times the representative method detection level were greater than 

the UPL, we would conclude that the calculated floor or emissions limit does not account 

entirely for measurement variability. If indicated, we substituted the value equal to three times 

the representative method detection level to apply as the adjusted floor or emissions limit. This 

adjusted value would ensure measurement variability is adequately addressed in the floor or the 

emissions limit. 

Commenter Name: Jim Griffin

Commenter Affiliation: American Chemistry Council

Document Control Number: EPA-HQ-OAR-2002-0058-2792.1

Comment Excerpt Number: 187

Comment: EPA Should Address Detection Limit and Non-Detect Reporting Issues. In its Phase 

II ICR instructions, EPA requested facilities to report analytical method detection limits and 

report all values below the method detection limit at the method detection limit. Most analytical 

laboratories, however, do not use their method detection limits as cut-off points for reporting 

data. Instead, recognizing that any measurements below the method quantitation limit (or limit of 

quantitation, LOQ), which is a multiplier of MDL, are not quantifiable, most analytical 

laboratories only report measurements above the LOQ as measured values and measurements 

below the LOQ as less than the LOQ. EPA should make its reporting requirements consistent 

with laboratory practices. 

Response: EPA does not agree that it is necessary for a method to specify how to determine a 

method detection limit; a quality laboratory will determine the method detection limit using a 

suitable approach. In the longer term, it is still under consideration whether it makes sense to 

specify one or more standard Agency practices for method detection limit determination. 

Commenter Name: Jim Griffin

Commenter Affiliation: American Chemistry Council

Document Control Number: EPA-HQ-OAR-2002-0058-2792.1

Comment Excerpt Number: 188

Comment: EPA has failed to develop and promulgate a procedure for determining method 

detection and quantitation limits, has not published quantitation limits for air test methods, and, 

contrary to scientific methods, and has used data below estimated method quantitation limits as 

real values in developing the proposed standards. EPA should develop method detection and 

quantitation limit information, correct the data in its database, and repropose revised standards 

based on proper data analysis. 
243

In its proposal EPA has stated: "In our guidance for reporting pollutant emissions used to support 

this rule, we specified the criteria for determining test-specific method detection levels. These 

criteria insure that there is about a 1 percent probability of error in deciding that the pollutant 

measured at the method detection level is present when in fact it was absent.”[75 Fed. Reg. at 

32020.] The facts associated with EPA’s data gathering effort related to this rule, however, do 

not support EPA’s claim. As noted earlier, in developing the proposed standard EPA used two 

sets of data. The first set was obtained through the Phase I ICR in 2008. This data solicitation did 

not even mention the term "method detection limits." The second set of data was obtained as a 

result of the Phase II ICR in 2009. This ICR required facilities to conduct tests and report all the 

results below the method detection limits at the method detection limits. Furthermore, facilities 

were asked to provide the details of the procedures used to establish method detection limits. 

However, contrary to EPA’s claim, the ICR instructions did not provide any procedure for 

determining method detection limits, and it should be noted that the current EPA air emission 

test methods do not include procedures for determining method detection limits. 

Response: EPA does not agree that it is necessary for a method to specify how to determine a 

method detection limit; a quality laboratory will determine the method detection limit using a 

suitable approach. In the longer term, it is still under consideration whether it makes sense to 

specify one or more standard Agency practices for method detection limit determination. 

Probability procedures applied in calculating the floor or an emissions limit inherently and 

reasonably account for emissions data variability including measurement imprecision when the 

database represents multiple tests from multiple emissions units for which all of the data are 

measured significantly above the method detection level. That is less true when the database 

includes emissions occurring below method detection capabilities and are reported as the method 

detection level values.

We applied the following procedures to account for the effect of measurement imprecision 

associated with a database that includes method detection level data. The first step was to define 

a method detection level that is representative of the data used in establishing the floor or 

emissions limit and that also minimizes the influence of an outlier test-specific method detection 

level value. We reviewed each pollutant-specific data set to identify the highest test-specific 

method detection level reported that was also equal to or less than the average emissions level 

(i.e., unadjusted for probability confidence level) calculated for the data set. We believe that this 

approach is representative of the data collected to develop the floor or emissions limit while to 

some degree minimizes the effect of a test(s) with an inordinately high method detection level 

(e.g., the sample volume was too small, the laboratory technique was insufficiently sensitive, or 

the procedure for determining the detection level was other than that specified).

The second step in the process is to calculate three times the representative method detection 

level and compare that value to the calculated floor or emissions limit. If three times the 

representative method detection level were less than the calculated floor or emissions limit 

calculated from the UPL, we would conclude that measurement variability was adequately 

addressed. The calculated floor or emissions limit would need no adjustment. If, on the other 

hand, the value equal to three times the representative method detection level were greater than 

the UPL, we would conclude that the calculated floor or emissions limit does not account 
244

entirely for measurement variability. If indicated, we substituted the value equal to three times 

the representative method detection level to apply as the adjusted floor or emissions limit. This 

adjusted value would ensure measurement variability is adequately addressed in the floor or the 

emissions limit. 

Commenter Name: Jim Griffin

Commenter Affiliation: American Chemistry Council

Document Control Number: EPA-HQ-OAR-2002-0058-2792.1

Comment Excerpt Number: 190

Comment: Facilities Need Clear Guidance On Handling Of Non-Detect Values. The proposed 

regulation requires the use of Method 23 for demonstrating compliance with the dioxin/furan 

limits, but is silent on the treatment of measurements below their detection limits. This should be 

clarified in the final rule. EPA should clearly state that Method 23 should be followed in its 

entirety, including the requirement to report measurements below the DL as zero. 

Response: Sources should use the guidance in Section 9.9 of Method 23 that all measurements 

below the detection limit (calculated as per Method 23) should be treated as zero for the purpose 

of calculating dioxins/furans emissions. 

The preamble reiterates the need to report D/F emissions concentration as prescribed in Method 

23, on a mass basis and to follow the method's procedures for reporting values measured below 

the test-specific minimum detectable limit as zero. 

Commenter Name: Jim Griffin

Commenter Affiliation: American Chemistry Council

Document Control Number: EPA-HQ-OAR-2002-0058-2792.1

Comment Excerpt Number: 191

Comment: EPA Method 29 Provides No Guidance On Calculating The Detection Limits Of The 

Sub-Samples Which Are Below The Instrument Detection Limit. This Deficiency Of The Test 

Method Must Be Corrected Prior To Promulgating A Final Rule. EPA Method 29 is a complex 

test method that requires extreme care in source testing and sample recovery. This complexity is 

further compounded when multiple sample fractions are processed in the laboratory resulting in 

five sub-samples which have to be analyzed separately. Since the sub-samples have different 

matrices, their instrument detection limits need to be established separately using appropriate 

samples. Many analytical laboratories do not develop detection limit data for different matrices 

but choose to analyze one sample blank and incorrectly use the DL value obtained from such 

analysis for all the sub-samples. 

EPA should revise Method 29 to specify that DLs need to be established for each sub-sample 

using appropriate matrices. Since the mercury sub-sample does not utilize the entire volume of 

the sub-sample, the determination of the detection limit of the sub-samples requires a volume 

correction just as it is needed to report sub-sample mercury content when the results are above 
245

the detection limit. However, due to a lack of guidance in Method 29, some laboratories fail to 

correct the detection limit for the sub-sample volume. EPA should write detailed calculation 

procedures for determining sub-sample detection limits to ensure that the calculations are carried 

out correctly. 

Response: EPA does not agree that it is necessary for a method to specify how to determine a 

method detection limit; a quality laboratory will determine the method detection limit using a 

suitable approach. In the longer term, it is still under consideration whether it makes sense to 

specify one or more standard Agency practices for method detection limit determination. 

Commenter Name: Kerry Flick

Commenter Affiliation: Metso Power

Document Control Number: EPA-HQ-OAR-2002-0058-2388.1

Comment Excerpt Number: 8

Comment: Some of the measurement and test methods are unable to reliably or accurately 

measure tile proposed low-level emissions on a consistent basis with repeatability. We 

recommend that the EPA make modifications to the proposed ruling to ensure an accurate and 

reliable means is available to measure these low-level emissions. Measurement tolerances should 

be established to account for variability III testing as well as given biases. 

It is imperative that one can accurately measure and consistently prove compliance with all air 

regulations. The proposed ruling for new boilers would mandate emission limits that have yet to 

be demonstrated on a consistent and repeatable basis. We have questioned the ability to 

accurately and consistently measure these emissions at these limits. For this reason we sought the 

advice of the Energy & Environmental Research Center (EERC). Attached is a formal response 

from EERC addressing these issues. The EERC is a former National Laboratory that currently 

operates as a private research center located at the University of North Dakota. In 1992, the USEPA established EERC as the Center of Excellence for Air Toxic Metals (CATM). Their input 

provides great insight into the relevancy of the proposed ruling. 

In summarizing the EERC letter, we have been advised that: 

There are no EPA approved methods (such as Method 26A. or 13B) that are appropriate III 

measuring the proposed HCl limit. Values less than 5 ppm will lack precision and accuracy. 

Similarly, for mercury, neither the Ontario Hydro (OH) nor Method 29 should be considered 

relevant as their reliable detection limits are well above the proposed emission limit. There is an 

alternative method, Method 30B, which has demonstrated accurate measurement of mercury at 

the proposed levels. However, for biomass applications, compliance using continuous 

monitoring methods has not been validated and is still in the developmental/testing stage. Early 

results are not promising. 
246

For the measurement of dioxins/furans, using Method 23 could prove to be problematic 

depending on how the regulations are implemented and what is allowed or not allowed. There 

are two potential issues with the low level measurements required -detection limits and sample 

contamination. Regarding detection limits, non-detect values must be replied as “zero” values, as 

stated in the method. However, if regulatory bodies start to require that non-detects be assigned 

the detection limit value, the summation of the numerous dioxin/furan compounds will be greater 

than the proposed emission limit. As for sample contamination, simply put –one person smoking 

a cigarette in the vicinity of a test program could contaminate the sample with enough dioxin to 

put the facility out of compliance. 

In addition to the comments received from EERC, it has been learned that the emission level 

proposed for dioxin/furans (which is significantly below the 0.1 ng/nm3 level established in the 

European Union) will be extremely difficult, if not impossible, to measure with accuracy and 

reliability. 

To aid in this measurement issue, as a minimum, emission limits should recognize and allow for 

measurement variance within a given test method and the instruments used. This is currently not 

the case in the United States. In Europe for example, acceptable testing tolerances for given 

pollutants have been established to account for these variances. For clarity, please reference 

Annex III contained in the DIRECTIVE 2000/76/EC OF THE EUROPEAN PARLIAMENT 

AND OF THE COUNCIL of 4 December 2000. 

Further, testing at these low levels will require testing contractors who are extremely familiar 

with the stated methods and their inherent biases and/or interferences. There are a very limited 

number of testing contractors that fit this criterion. 

The Energy and Environmental Research Center (EERC) assessed the ability of several U.S. 

Environmental Protection Agency (EPA) – approved methods for measuring low levels of 

mercury, HCl, and dioxin/furans that METSO Power may be asked to guarantee for newly 

constructed biomass combustors in response to the recently proposed EPA Industrial Boiler 

MACT (maximum achievable control technology) regulations, with limits as shown in the table 

below. It should be clearly noted that EERC did not assess whether the emission limits are 

achievable but only as to whether appropriate methods can be used for accurate measurement at 

or below the stated limits. [See submittal for Table of methods analyzed] 

To compare to method detection limits, based on fuel properties and calculated flue gas flow 

rates, the above emission limits are presented on a dry volumetric basis, corrected to standard 

conditions, as follows. [See submittal for Table with ppmv values] 

HCl 

Based on this assessment, accurate measurement of HCI at or below the proposed emission limit 

of 0.004 Ib/MMBtu, 3.31 ppmv (dry), will be problematic and not possible using M26A, or other 

methods. Considering the uncertainties and errors associated with sample collection and known 

biases, values less than 5 ppm will lack precision and accuracy. To account for error associated 

with all known biases and have a high degree of confidence and accuracy, a limit of20 ppmv 
247

should be considered. At a minimum, the emission limit should recognize and allow for variance 

within the methods as discussed in Enclosure A. Additionally, to obtain accurate low-level 

values, the EERC believes that it will require contractors who are extremely familiar with the 

methods and their inherent biases and/or interferences. 

From a sampling standpoint, and for the methods that are available, there are not any 

EPA-approved methods (such as Method [M] 26 or MI3B) that are appropriate for measuring 

HCI at or below the emission limits ofO.004IbIMMBtu, 3.31 ppmv (dry). 

The EERC would not recommend using M26A (Determination of Hydrogen Halide and Halogen 

Emissions from Stationary Sources Isokinetic Method) for HCI measurements in the range 

needed to verify compliance with these low-level emission limits. The emission limit for HCL is 

below the ability ofM26A to reliably and accurately determine the stack gas concentrations. 

Although the M26A laboratory detection limit using ion chromatography for F detection is 0.2 

mg/m), compared to the M13B ion-specific electrode detection limit of 0.02 mg/m), the levels to 

be measured in a sample at the emission limit would still be approximately 20 times above the 

detection limit. 

This value, however, does not address the uncertainty and errors associated with sample 

collection and possible biases. It should be recognized that M26A has a potential high bias for 

HCI in the presence of volatile materials, such as chlorine dioxide and ammonium chloride. 

There is also a potential measurable low bias for HCI under 20 ppmv, caused by moisture in the 

flue gas. This bias can be reduced by operating the probe at temperatures at the upper limits of 

the specified temperature and insuring that no water droplets are collected on probe surfaces. 

However, there is still likely to be some associated error or bias. The issue of low bias can be 

especially problematical if the samples are taken after a wet scrubber and at high-moisture levels. 

Low-level halogen measurements, taken after a wet scrubber or at high-moisture levels, should 

be assumed to be biased low, and this would also be true when using the optional cyclone at the 

probe inlet. Some of this bias can be reduced by elevating sample train temperatures, but this 

may lead to a high bias if ammonia is present in the flue gas. At this point, the EERC is not 

aware of any proposed alternative sampling methods that resolve the low-bias issue. 

A short discussion follows of the biases associated with M26A, as outlined in the EPA document 

“Stack Sampling Methods for Halogens and Halogen Acids.” [Footnote: Johnson, L.D. Stack 

Sampling Methods for Halogens and Halogen Acids. Presented at the EPA/AWMA International 

Symosium on Measurement of Toxic and Related Air Pollutants, Research Triangle Park, NC, 

May 1996.] As stated in this document, the low bias associated with the method was not 

consistent from test to test but can be roughly correlated with the moisture content of the flue 

gas. Tests at 4.8 ppm HCI indicated a low bias of 50%. Another test indicated that spiked 

impinger recoveries were reasonable but that full-train spikes were low by a factor of 3 to 5. The 

presence of NH4Cl was found to produce a positive bias in all cases, and any attempt to mitigate 

this bias aggravated the moisture bias. In flue gases containing ammonia slip, it could be 

assumed that the high bias for HCI due to NH4CI could be as high as the ammonia slip value in 

the flue gas if the ammonia reacted with available cr ions. Since the emission limit for ammonia 
248

is over 10 ppm, the potential high bias using M26A could be several times the above-stated 

emission limit; certainly, it could be as high as 10 ppm. 

The validation status discussed in this document indicates that the method is valid from “a few” 

ppm to 500 ppm but does not address the high bias potential and does not define what is meant 

by “a few” ppm; certainly, the proposed limit of 3.31 ppm would not be considered “a few.” The 

precision of the method was evaluated from 3.9 to 15.3 ppm HCI, and the stated precision was 

up to 0.49 ppm. 

The test for the precision of this method did not challenge the method with worst-case scenarios: 

high moisture and ammonia. Since, this test did not include ammonia, which is known to cause a 

higher bias, the 0.49 ppm precision could easily be 10 ppm in the presence of a 10 ppm or 

greater ammonia slip. One final note, EPA M0050 is nearly identical to M26A; it uses the same 

sampling probe, filter housing, and impinger configuration. Yet M0050 very clearly states the 

method SHOULD NOT BE USED FOR HCI CONCENTRATION LESS THAN 20 ppm. 

In summary, there are methods to measure HCI with a stated method detection limit of 0.04 ppm 

in the stack gas, which taken by itself should provide values that are within emission limits of I 

to 2 ppm in the flue gas. However, when considering uncertainties and errors associated with 

sample collection and known biases as documented by EP A (1), the methods will not likely 

provide reliable values that are accurate and repeatable below 5 ppm (1), and even values below 

20 ppm have shown bias values as much as 20%. 

This is consistent with the conclusion from EPA’s Method Branch Office; a quote taken from the 

EPA’s “Stack Sampling Methods for Halogens and Halogen Acids” document states that “good 

precision and accuracy become difficult to achieve with these methods (M26 and M26A) at 

concentrations below 5 ppm” (l). Similar methods, such as EPA M0050, further state that the 

accurate measurement of HCI should be limited to 20 ppm or higher. 

Mercury 

Low-level measurement of total mercury at the proposed mercury limit of 0.0000002IbIMMBtu 

(approximately 0.35 ug/m3, depending on the heating value of the biomass) is possible but not 

with the proposed methods or with continuous monitoringinstruments. Neither the Ontario Hydro 

(OH) method nor M29 should be considered as the compliance method for mercury 

measurement at these low levels. These methods lack the ability to provide good consistent 

results and repeatable background blanks at these levels. Increasing sampling time with these 

methods does not improve (lower) detection limits or provide higher quality data because of 

other factors that interfere with the measurements, for example, S02 interference, dilution of the 

sample because of condensate, and other factors. The detection limit for M29 is 0.59 ug/m3 and 

0.5 ug/m3 for the OH method. These numbers are optimistic based on existing data quality and 

are above the limit of 0.35 ug/m3 (0.0000002 IbIMMBtu). 

An alternative method that has demonstrated accurate measurement of mercury at low levels is 

M30B. The detection limit for M30B is extremely good, and most testers have had good success 

making low-level measurements in the range of the proposed limit. Yearly compliance testing to 
249

prove compliance even at these low values can be done without many complications using 

M30B. The problem with low-level mercury testing arises when continuous monitoring is 

required such as installation of continuous mercury monitors (CMMs) or when long-term 

Appendis K-type samples are required. 

Continuous long-term measurement using Appendix K-type traps to measure low-level mercury 

concentrations have also run into problems. The Appendix K-type traps are sensitive to flue gas 

compositions; high moisture, high S02, and other acid gases can cause breakthrough of Section I 

to Section 2 and also create problems for spike recoveries in Section 3. Originally, the Appendix 

K-type traps were intended to continuously collect mercury for 1 to 2 weeks. Recent data 

indicated that in some cases the traps may need to be changed daily or at a minimum every few 

days. At this point, for biomass applications, it is impossible to predict with certainty how long 

the traps will work. Any permit that required the use of these traps as the compliance 

measurement would have to be very broadly written to cover the possibility that these 

measurements may be unreliable and inconsistent from test to test. When applied to biomass 

facilities, some sort of validation testing is needed before Appendix K should be generally 

accepted for compliance purposes. 

Dioxins/Furans 

The measurement of dioxins/furans using M23 to demonstrate compliance at 0.007 ngldsm3 (7 

pgl dsm3) is possible but could prove to be problematic. There are two potential problematic 

areas when attempting to make low-level measurements that are at or below 0.007 ng/dsm3 The 

first has to do with detection limits, and the second is related to sample contamination. Both are 

discussed in more detail as follows. 

Detection Limit. The detection limit issue revolves around the fact that the laboratory detection 

limit for each of the dioxin/furan compounds is approximately 2 pg, 0.002 ngldsm3 The family 

of regulated dioxins/furans include seven of the polychlorinated dibenzo dioxins, ten of the 

polychlorinated dibenzo furans, and twelve of the polychlorinated biphenyls, which each have an 

approximate detection limit of 2 pg, 0.002 ng/dsm3. 

In many cases, the values that are measured are below the laboratory detection limit, or 

nondetects. These nondetects are not an issue if the method is followed as written. That is, the 

method specifically states that nondetect values are to be reported as ZERO values. However, the 

problem arises when regulatory bodies start to require that nondetects be assigued the detection 

limit value (approximately 2 pg) rather than zero. Since there are numerous dioxin/furans 

compounds (as shown above), this could equate to an accumulative detection limit of well over 

0.007 ng/dsm3 (7 pg/ dsm3) should all compounds be assigned a value equal to their detection 

limit or a lower value after applying a toxic equivalency factor. Consequently, if nondetects are 

not treated as zeros, it might not be possible for a facility to demonstrate compliance at a limit of 

at 0.007 ng/dsm3 (7 pgldsm3). Some relief from the method detection limit issue can be obtained 

by increasing the volume of gas sampled, but this does not always work. In some cases, the 

additional sample volume can create problems with the analytical and actually increase detection 

limits because of interference issues or problems separating peaks. 
250

Sample Contamination. Since the value of 0.007 ng/dsm3 (7 pg/dsm3) is extremely low, it is 

critical to the accurate measurement of dioxins/furans that any potential for sample 

contamination be minimized/eliminated. For example, even one person smoking a cigarette in 

the vicinity of a test program could contaminate the sample with enough dioxin to put the facility 

out of compliance. Extreme care must be taken, and in some cases, retesting may be required and 

should be allowed to ensure that samples are not contaminated. 

M23 does not have any provisions that allow for subtracting background blank values from 

sample values. This may cause problems at some sites as background contamination may exist. 

Therefore, it is important that any permit or limit value allow for subtracting field blank values 

from sampled values. At a minimum, permit language should allow for retesting should 

contamination can be identified and isolated. Field blanks should be allowed to be used in way of 

subtraction and also to identify possible site contamination for each dioxin/furan compound. 

Should field blanks indicate that one or more compounds show possible contamination, retesting 

should be allowed. Field blank sample trains must be assembled, taken to the sample location, 

leak checked, left at the sample location for the duration of the test run, leak checked after the 

run, and recovered in the same manner as test samples. For laboratory analysis, field blank 

samples must be treated exactly as test samples. That is, if dilutions or other procedures 

including filter ingare performed on test samples, then the same dilutions or procedures must be 

applied to the field blank samples. It is extremely important to identify a testing agency and 

laboratory that can provide consistent data that is free from contamination, and it is equally 

important that each individual test run include a field blank to verify that measured values in that 

sample are from process sources and not from outside and/or background contamination. 

Response: We agree that test method measurement imprecision is a contributor to the variability 

of a set of emissions data. One element is associated with method detection capabilities and a 

second is a function of the measurement value. Measurement imprecision is proportionally 

highest for values measured below or near a method’s detection level and proportionally 

decreasing for values measured above the method detection level. 

Probability procedures applied in calculating the floor or an emissions limit inherently and 

reasonably account for emissions data variability including measurement imprecision when the 

database represents multiple tests from multiple emissions units for which all of the data are 

measured significantly above the method detection level. That is less true when the database 

includes emissions occurring below method detection capabilities and are reported as the method 

detection level values.

We applied the following procedures to account for the effect of measurement imprecision 

associated with a database that includes method detection level data. The first step was to define 

a method detection level that is representative of the data used in establishing the floor or 

emissions limit and that also minimizes the influence of an outlier test-specific method detection 

level value. We reviewed each pollutant-specific data set to identify the highest test-specific 

method detection level reported that was also equal to or less than the average emissions level 

(i.e., unadjusted for probability confidence level) calculated for the data set. We believe that this 

approach is representative of the data collected to develop the floor or emissions limit while to 
251

some degree minimizes the effect of a test(s) with an inordinately high method detection level 

(e.g., the sample volume was too small, the laboratory technique was insufficiently sensitive, or 

the procedure for determining the detection level was other than that specified).

The second step in the process is to calculate three times the representative method detection 

level and compare that value to the calculated floor or emissions limit. If three times the 

representative method detection level were less than the calculated floor or emissions limit 

calculated from the UPL, we would conclude that measurement variability was adequately 

addressed. The calculated floor or emissions limit would need no adjustment. If, on the other 

hand, the value equal to three times the representative method detection level were greater than 

the UPL, we would conclude that the calculated floor or emissions limit does not account 

entirely for measurement variability. If indicated, we substituted the value equal to three times 

the representative method detection level to apply as the adjusted floor or emissions limit. This 

adjusted value would ensure measurement variability is adequately addressed in the floor or the 

emissions limit. 

Commenter Name: Timothy Hunt

Commenter Affiliation: American Forest and Paper Association (AF&PA)

Document Control Number: EPA-HQ-OAR-2002-0058-3213.1

Comment Excerpt Number: 70

Comment: In its proposal and in its 2009 ICR EPA has specified the use of either Method 29 or 

ASTM Method D6784-02 for measuring stack emissions of mercury and has used data obtained 

with either of the two methods to set the proposed MACT standards for mercury. In doing this, 

EPA has failed to recognize the differences between the two methods as described below: 

(a) In its 2009 ICR, EPA also specified a 4-hour run and a sample volume of 4 m3. However, 

the ASTM method specifies that the sampling duration should not exceed 3 hours and a 

maximum sample volume of 2.5 m3 is specified. It is known that as the averaging period for a 

standard goes down, the emission profile changes and gives higher peaks. Consequently, it 

would not be appropriate to use ASTM Method 6784-02 to demonstrate compliance with a 4-

hour mercury emission standard. 

(b) An examination of the two methods would show that the resulting volumes of the subsamples obtained with the two methods are different. Thus if one follows the EPA 2009 ICR 

protocol for reporting values below the method detection limit as being equal to the detection 

limit, one would get different results when sample fractions are non-detect. For example, in 

Method 29 when the contents of the KMnO4 impingers are processed, one obtains two 500 mL 

sub-samples for mercury analysis. In the case of ASTM Method D6784-02, the processing of the 

KMnO4 impinger solution would result in a single 500-600 mL sample. Thus, if the detection 

limits of the analyzers used with the two methods are the same, the emission rate reported for 

non-detect measurements when Method 29 is used would be nearly twice that reported for the 

ASTM method. 

Based on the above inconsistencies between the two methods, we recommend that EPA should 

either use the results of only one of the two methods or conduct simultaneous tests on sources to 

determine whether or not the two methods give the same results. Additionally, EPA should 
252

reexamine its requirement to test sources for 4 hours and a 4 m3 volume, since this cannot be 

achieved when ASTM D6784-02 is utilized for source testing. 

Response: The final rule includes EPA Methods 30 A and 30B for mercury.

Also, we agree with commenters that the rule must clarify minimum sample volumes and assure 

that the specifications are consistent between test methods and with the method capabilities. See 

the response to EPA-HQ-OAR-2002-0058-1907.1, Comment Excerpt Number:8.

Commenter Name: Timothy Hunt

Commenter Affiliation: American Forest and Paper Association (AF&PA)

Document Control Number: EPA-HQ-OAR-2002-0058-3213.1

Comment Excerpt Number: 89

Comment: The use of a TSM makes more sense, but EPA should include in the rule instructions 

on how to treat non-detects since there is no guidance in Method 29. A scientifically defensible 

method for addressing the handling of non-detect test results will need to be developed by EPA. 

This methodology will need to provide assurance to facilities that test results which are below 

measurable levels (e.g. non-detects) will not put sources in a situation of being non-compliant 

with the standard. 

Response: EPA does not agree that it is necessary for a method to specify how to determine a 

method detection limit; a quality laboratory will determine the method detection limit using a 

suitable approach. In the longer term, it is still under consideration whether it makes sense to 

specify one or more standard Agency practices for method detection limit determination. 

Regarding EPA’s guidance on reporting of non-detect values for compliance purposes, sources 

should use the guidance in Section 13 of Method 29 that all measurements below the detection 

limit (calculated as per Method 29) should be treated as zero for the purpose of calculating 

dioxins/furans emissions. 

&&&The final rule will clarify and reiterate the need to report D/F emissions concentration as 

prescribed in Method 23, on a mass basis and to follow the method's procedures for reporting 

values measured below the test-specific minimum detectable limit. 

Commenter Name: Arthur N. Marin

Commenter Affiliation: NESCAUM

Document Control Number: EPA-HQ-OAR-2002-0058-2893.1

Comment Excerpt Number: 3
253

Comment: For oil boilers, EPA’s proposed limit of 1 part per million (ppm) CO for new oil 

boilers falls below reference test method variability. Additionally, the 1 ppm limit would likely 

require use of CO continuous emission monitoring systems (CEMS) for all oil units. 

Response: See the preamble for revisions to the CO limitations and compliance demonstration 

methods. 

Commenter Name: Michael Bradley

Commenter Affiliation: The Clean Energy Group

Document Control Number: EPA-HQ-OAR-2002-0058-2466.1

Comment Excerpt Number: 4

Comment: To assess the feasibility of meeting the CO standards for existing liquid- and gasfired boilers, we contacted testing contractors, who indicated that the standards for CO proposed 

in this rule for liquid- and gas-fired subcategories are at or near the non-detect level of testing 

equipment. As such, accurately determining compliance may be difficult or impossible.[footnote 

3: “Current CO testing using a continuous emission monitor (CEM) would follow Performance 

Specification 4, which was developed primarily for CEMs having span values of 1,000 ppmv 

CO. As such, accuracy below 10 ppm would be considered the lower detection threshold. Stack 

testing would be done using EPA Method 10, which has an instrument sensitivity of 2 percent of 

the calibration span. Performance specifications dictate that the span be 1.5 to 2 times the 

standard. For a CO emission limit of 1 ppm, the span would be 1.5 ppm to 2 ppm. In this 

situation, the calibration gases, which need to include concentrations at 30%, 50% and 80% of 

span, would necessitate calibration gases to be available in concentrations ranging from 0.5 ppm 

for the low calibration, 0.75 ppm for the mid calibration and 1.2 ppm for the high span. These 

calibration gases are not currently available with the Method 10 requirement for Protocol I 

traceability. Use of a “zero” gas is often substituted for the low calibration point; however, 

certified zero gas could contain an impurity concentration of CO above 1 ppm.”] The Clean 

Energy Group recommends that EPA verify with National Institute of Standards and Technology 

(NIST) that testing for these very low standards can be accurate (considering the error range, 

e.g., “plus-minus”). We recommend that EPA not finalize any emission standard set lower than 

can reasonably be expected to be detected using continuous emission monitoring equipment. As 

an alternative, EPA could reduce the monitoring requirement to an annual stack test rather than a 

continuous monitoring requirement. 

Response: See the preamble for revisions to the CO limitations and compliance demonstration 

methods. 

Commenter Name: Arthur N. Marin

Commenter Affiliation: NESCAUM

Document Control Number: EPA-HQ-OAR-2002-0058-2893.1

Comment Excerpt Number: 8
254

Comment: As with CO emission limits, the proposed mercury and hydrogen chloride emission 

limits are set too close to the detection limits for their respective specified test methods. 

Response: See the preamble for revisions to the CO limitations and compliance demonstration 

methods. 

Commenter Name: Britt S. Fleming

Commenter Affiliation: Auto Group

Document Control Number: EPA-HQ-OAR-2002-0058-2775.1

Comment Excerpt Number: 32

Comment: Another significant concern with the EPA data for the Gas 2 units relates to the CO 

data. Specifically, by setting the proposed MACT floor limit for CO at 1 ppm for the Gas 2 

subcategory, EPA is basically setting a standard at the limits of detection for the test method. 

Monitoring CO to a limit of 1 ppm could be considered at the limits of detection because of 

technical issues related to calibration drift and relative accuracy. Performance Specification (PS) 

4A, developed primarily for CEMs that comply with low emission standards (less than 200 

ppmv), requires dual range capability. For the low range scale, the high-level value must be 

between 1.5 times the pollutant concentration corresponding to the emission standard level and 

the span value. For the high-range scale, the high-level value shall be set at 2000 ppm, as a 

minimum, and the range shall include the level of the span value. There must be no concentration 

gap between the low-and high-range scales. PS 4A also requires that the CEMs calibration not 

drift or deviate from the reference value by more than 5 percent of the established span value. If 

the low range monitor uses 10 ppm as span gas for calibration, the allowable calibration drift is 

0.5 ppm. This amount of drift is 50 percent of the proposed limit and could result in calculated 

emission exceedances when have not actually occurred. 

The allowable calibration drift for the high-range scale is 5 percent of 2000 ppm which equals 

100 ppm. If a boiler has CO greater than the low range during startup, the emissions averaging 

will be relying on data from the high-range instrument. A CEM could produce measured values 

ranging from 0 to 115 ppm when the actual emissions are 15 ppm as measured by Reference 

Method 10 and the CEM would be meeting the performance specification criteria. This could 

result in calculated averages that are much greater than actual emissions and result in a falsely 

calculated emission exceedance. 

Response: See the preamble for revisions to the CO limitations and compliance demonstration 

methods. 

Commenter Name: Timothy Hunt

Commenter Affiliation: American Forest and Paper Association (AF&PA)

Document Control Number: EPA-HQ-OAR-2002-0058-3213.1
255

Comment Excerpt Number: 52

Comment: If stack testing will be used to determine compliance with emission limits in the 

future, the methods, data handling protocols, and data reporting procedures should be specified 

with sufficient detail. Such details are essential so that stack testing firms and facility operators 

know how to determine method detection levels and minimum reporting levels for each sampling 

method, and how data falling below these levels should be reported. Unless EPA clarifies these 

issues, the current confusion will continue and will create compliance uncertainty in the future. 

Response: EPA does not agree that it is necessary for a method to specify how to determine a 

method detection limit; a quality laboratory will determine the method detection limit using a 

suitable approach. In the longer term, it is still under consideration whether it makes sense to 

specify one or more standard Agency practices for method detection limit determination. 

Regarding EPA’s guidance on reporting of non-detect values for compliance purposes, sources 

should use the guidance in Section 9.9 of Method 23 that all measurements below the detection 

limit (calculated as per Method 23) should be treated as zero for the purpose of calculating 

dioxins/furans emissions. 

The final rule will clarify and reiterate the need to report D/F emissions concentration as 

prescribed in Method 23, on a mass basis and to follow the method's procedures for reporting 

values measured below the test-specific minimum detectable limit. 

Commenter Name: Timothy Hunt

Commenter Affiliation: American Forest and Paper Association (AF&PA)

Document Control Number: EPA-HQ-OAR-2002-0058-3213.1

Comment Excerpt Number: 104

Comment: The proposed dioxin/furan emission standards for biomass boilers are so low and the 

detection limits of dioxin/furan isomers are so variable that many boilers are likely to exceed the 

proposed emission limits for dioxins/furans even though the tests show that all the isomers are 

present below the detection limits for the 17 congeners. Given that the detection limit is used to 

differentiate between a blank and presence of an analyte, the above outcome is unreasonable and 

borders on absurdity. Consequently, we recommend that EPA should replace the proposed 

numerical standards for dioxins/furans with work practice standards. 

The detection limits for Method 23 are based on the variation in the baseline and have high 

variability, even between samples from the same source that were also analyzed by the same 

laboratory. In general, if the baseline of the sample matrix is inconsistent, the detection limits of 

the sample will be higher. 

An example of high variability of data from a single source is provided in the submitted table. 

The data are from Foster Wheeler Boiler (EU43) at NDCargillWestFargo. For simplicity, only 

the data for congeners with Toxicity Emission Factors of one are shown. 
256

The above boiler has a Fluidized Bed design and therefore would be subject to the proposed 

emission limit of 0.02 TEQ (ng/dscm). For this source even if the non-detects are reported at the 

detection limit, run 1 would exceed the emission limit based on summing the non-detect values 

for the two congeners for which data are shown. 

To examine the impact of the high variability in the dioxin and furan congener detection limits 

upon the ability to comply with the proposed emission standards, we extracted from EPA’s 

database the 95th, 75th and 50th percentile values of the detection limits provided for each 

PCDD/F isomer corresponding to all the Boiler MACT test runs that yielded in non-detects. 

These are tabulated in the submittal Table 6.1. Also shown in Table 6.1 are the WHO-TEF/2005 

TEQs resulting from these data when all the NDs are assumed at the detection limit. The data 

show that at 95th, 75th, and 50th percentiles, the TEQs for tests with all non-detect values would 

be 4.15E-02, 7.91E-03 and 3.30E-03, respectively. We then compared these values to the 

proposed standards to determine whether or not a facility reporting all non-detects in a 

subcategory would be able to comply with the standards. These results are tabulated in the 

submittal Table 6.2. 

The results in Table 6.2 show that if the analytical laboratory achieved dioxin/furan isomer 

detection limits equal to the 95th percentile of the observed detection limits in EPA’s dataset and 

all the measurements were below their respective detection limits, the resulting emission rate 

estimate would cause boilers in all source categories to exceed the proposed emission standard. 

If an analytical laboratory achieved detection limits at the 75th percentile level and all the 

measurements were non-detect, the resulting dioxin/furan emission rate would cause 7 out of 9 

boiler types in the new source category and 4 out of 9 boiler types in the existing boiler category 

to exceed the proposed standard. At the 50th percentile level, the failure rate for all non-detect 

measurements for new and existing sources would still be 6 out of 9 boiler subcategories and 3 

out of 9 boiler subcategories, respectively. 

The results of the comparison of the dioxin/furan PQL values to the proposed boiler MACT 

standards are shown in the submittal Table 6.4. Table 6.4 shows that for laboratories achieving 

the TCDD/F practical quantitation limit in terms of TEQ at the 95th percentile level, the 

proposed standards for all subcategories of boilers are below the practical quantitation limit; for 

laboratories achieving the TCDD/F practical quantitation limit in terms of TEQ at the 75th 

percentile level, the proposed standards for 8 out of 9 subcategories for new or existing boilers 

are below the PCDD/F analytical method practical quantitation limit; and for laboratories 

achieving the TCDD/DF practical quantitation limit in terms of TEQ at the 50th percentile level, 

the proposed standards for 8 out of 9 new boiler subcategories and 6 out of 9 existing boiler 

subcategories are below the PCDD/F analytical method PQL. 

As an additional examination of the data, when we compared the above 95th percentile PQL 

value to the reported D/F measurements in EPA’s database, it showed that only 17 out of 313 

runs exceeded this value, which is only about 5 percent of the available data. 

Given the high cost associated with dioxin testing and the extremely low boiler dioxin emission 

levels which in most cases cannot be quantified or even measured by the currently available 

methods and the fact that there are no clear control technologies that EPA can identify to assure 
257

compliance, should EPA even set numerical dioxin/furan emission standards for boilers? Since 

testing isn’t really feasible our recommendation to EPA is to not set numeric standards but 

establish work practice standards for industrial boilers based on good combustion practices. 

Response: We agree that test method measurement imprecision is a contributor to the variability 

of a set of emissions data. One element is associated with method detection capabilities and a 

second is a function of the measurement value. Measurement imprecision is proportionally 

highest for values measured below or near a method’s detection level and proportionally 

decreasing for values measured above the method detection level. 

Probability procedures applied in calculating the floor or an emissions limit inherently and 

reasonably account for emissions data variability including measurement imprecision when the 

database represents multiple tests from multiple emissions units for which all of the data are 

measured significantly above the method detection level. That is less true when the database 

includes emissions occurring below method detection capabilities and are reported as the method 

detection level values.

We applied the following procedures to account for the effect of measurement imprecision 

associated with a database that includes method detection level data. The first step was to define 

a method detection level that is representative of the data used in establishing the floor or 

emissions limit and that also minimizes the influence of an outlier test-specific method detection 

level value. We reviewed each pollutant-specific data set to identify the highest test-specific 

method detection level reported that was also equal to or less than the average emissions level 

(i.e., unadjusted for probability confidence level) calculated for the data set. We believe that this 

approach is representative of the data collected to develop the floor or emissions limit while to 

some degree minimizes the effect of a test(s) with an inordinately high method detection level 

(e.g., the sample volume was too small, the laboratory technique was insufficiently sensitive, or 

the procedure for determining the detection level was other than that specified).

The second step in the process is to calculate three times the representative method detection 

level and compare that value to the calculated floor or emissions limit. If three times the 

representative method detection level were less than the calculated floor or emissions limit 

calculated from the UPL, we would conclude that measurement variability was adequately 

addressed. The calculated floor or emissions limit would need no adjustment. If, on the other 

hand, the value equal to three times the representative method detection level were greater than 

the UPL, we would conclude that the calculated floor or emissions limit does not account 

entirely for measurement variability. If indicated, we substituted the value equal to three times 

the representative method detection level to apply as the adjusted floor or emissions limit. This 

adjusted value would ensure measurement variability is adequately addressed in the floor or the 

emissions limit. 

The final rule will clarify and reiterate the need to report D/F emissions concentration as 

prescribed in Method 23, on a mass basis and to follow the method's procedures for reporting 

values measured below the test-specific minimum detectable limit. 
258

Commenter Name: Timothy Hunt

Commenter Affiliation: American Forest and Paper Association (AF&PA)

Document Control Number: EPA-HQ-OAR-2002-0058-3213.1

Comment Excerpt Number: 276

Comment: The proposed regulation requires the use of Method 23 for demonstrating 

compliance with the dioxin/furan limits, but is silent on the treatment of measurements below 

their detection limits. This should be clarified in the final rule. EPA should clearly state that 

Method 23 should be followed in its entirety, including the requirement to report measurements 

below the DL as zero. 

Response: The final rule will clarify and reiterate the need to report D/F emissions concentration 

as prescribed in Method 23, on a mass basis and to follow the method's procedures for reporting 

values measured below the test-specific minimum detectable limit. 

Commenter Name: Timothy Hunt

Commenter Affiliation: American Forest and Paper Association (AF&PA)

Document Control Number: EPA-HQ-OAR-2002-0058-3213.1

Comment Excerpt Number: 277

Comment: EPA Method 29 is a complex test method that requires extreme care in source testing 

and sample recovery. This complexity is further compounded when multiple sample fractions are 

processed in the laboratory resulting in five sub-samples which have to be analyzed separately. 

Since the sub-samples have different matrices, their instrument detection limits need to be 

established separately using appropriate samples. Many analytical laboratories do not develop 

detection limit data for different matrices but choose to analyze one sample blank and incorrectly 

use the DL value obtained from such analysis for all the sub-samples. 

EPA should rewrite Method 29 to specify that DLs need to be established for each sub-sample 

using appropriate matrices. Since the mercury sub-sample does not utilize the entire volume of 

the sub-sample, the determination of the detection limit of the sub-samples requires a volume 

correction just as it is needed to report sub-sample mercury content when the results are above 

the detection limit. However, due to a lack of guidance in Method 29, some laboratories fail to 

correct the detection limit for the sub-sample volume. EPA should write detailed calculation 

procedures for determining sub-sample detection limits to ensure that the calculations are carried 

out correctly. 

Response: EPA does not agree that it is necessary for a method to specify how to determine a 

method detection limit; a quality laboratory will determine the method detection limit using a 

suitable approach. In the longer term, it is still under consideration whether it makes sense to 

specify one or more standard Agency practices for method detection limit determination. 

Commenter Name: Ashok K. Jain

Commenter Affiliation: National Council for Air and Stream Improvement
259

Document Control Number: EPA-HQ-OAR-2002-0058-2804.1

Comment Excerpt Number: 8

Comment: In its proposal and in its 2009 ICR, EPA has specified the use of either Method 29 or 

ASTM Method D6784-02 for measuring stack emissions of mercury and has used data obtained 

with either of the two methods to set the proposed MACT standards for mercury. In doing this, 

EPA has failed to recognize the differences between the two methods as described below: 

(a) In its 2009 ICR, EPA also specified a 4-hour run and a sample volume of 4 m3. However, the 

ASTM method specifies that the sampling duration should not exceed 3 hours, and a maximum 

sample volume of 2.5 m3 is specified. Consequently, it would not be appropriate to use ASTM 

Method 6784-02 to demonstrate compliance with a 4-hour mercury emission standard. 

(b) An examination of the two methods would show that the resulting volumes of the subsamples obtained with the two methods are different. Thus if one follows the EPA 2009 ICR 

protocol for reporting values below the method detection limit as being equal to the detection 

limit, one would get different results when sample fractions are non-detect. For example, in

Method 29 when the contents of the KMnO4 impingers are processed, one obtains two 500 mL 

sub-samples for mercury analysis. In the case of ASTM Method D6784-02, the processing of the 

KMnO4 impinger solution would result in a single 500- 600 mL sample. Thus, if the detection 

limits of the analyzers used with the two methods are the same, the emission rate reported for 

non-detect measurements when Method 29 is used would be nearly twice that reported for the 

ASTM method. 

Based on the above inconsistencies between the two methods, we recommend that EPA use 

either the results of only one of the two methods or conduct simultaneous tests on sources to 

determine whether or not the two methods give the same results. Additionally, EPA should 

reexamine its requirement to test sources for 4 hours and collect a 4 m3 volume, since this cannot 

be achieved when ASTM D6784-02 is utilized for source testing. 

Response: 

The final rule includes EPA Methods 30 A and 30B for mercury.

Also, we agree with commenters that the rule must clarify minimum sample volumes and assure 

that the specifications are consistent between test methods and with the method capabilities. See 

the response to EPA-HQ-OAR-2002-0058-1907.1, Comment Excerpt Number:8.

Commenter Name: Randall D. Quintrell

Commenter Affiliation: Georgia Paper and Forest Products Association, GPFPA

Document Control Number: EPA-HQ-OAR-2002-0058-2905

Comment Excerpt Number: 6
260

Comment: Many of the limits have been set at or below the practical quantitation limit (PQL) of 

the analysis, so the emissions test value is not even reliably quantifiable at the compliance levels, 

much less below them. Thus, such a compliance margin may be unachievable and any 

"opportunity" for such relief is exceedingly low. 

Response: Probability procedures applied in calculating the floor or an emissions limit 

inherently and reasonably account for emissions data variability including measurement 

imprecision when the database represents multiple tests from multiple emissions units for which 

all of the data are measured significantly above the method detection level. That is less true when 

the database includes emissions occurring below method detection capabilities and are reported 

as the method detection level values.

We applied the following procedures to account for the effect of measurement imprecision 

associated with a database that includes method detection level data. The first step was to define 

a method detection level that is representative of the data used in establishing the floor or

emissions limit and that also minimizes the influence of an outlier test-specific method detection 

level value. We reviewed each pollutant-specific data set to identify the highest test-specific 

method detection level reported that was also equal to or less than the average emissions level 

(i.e., unadjusted for probability confidence level) calculated for the data set. We believe that this 

approach is representative of the data collected to develop the floor or emissions limit while to 

some degree minimizes the effect of a test(s) with an inordinately high method detection level 

(e.g., the sample volume was too small, the laboratory technique was insufficiently sensitive, or 

the procedure for determining the detection level was other than that specified).

The second step in the process is to calculate three times the representative method detection 

level and compare that value to the calculated floor or emissions limit. If three times the 

representative method detection level were less than the calculated floor or emissions limit 

calculated from the UPL, we would conclude that measurement variability was adequately 

addressed. The calculated floor or emissions limit would need no adjustment. If, on the other 

hand, the value equal to three times the representative method detection level were greater than 

the UPL, we would conclude that the calculated floor or emissions limit does not account 

entirely for measurement variability. If indicated, we substituted the value equal to three times 

the representative method detection level to apply as the adjusted floor or emissions limit. This 

adjusted value would ensure measurement variability is adequately addressed in the floor or the 

emissions limit. 

Commenter Name: Leonard W. Sandridge

Commenter Affiliation: University of Virginia

Document Control Number: EPA-HQ-OAR-2002-0058-2769.1

Comment Excerpt Number: 11

Comment: Table 5 of the rule requires CO to be measured by Method 10 (or by CEM if the heat 

input capacity of the unit is >100 MMBTU/hr.) As stated above, the regulatory limit of 1 ppm is 
261

smaller than the allowable calibration error tolerance of the method or of a CEM QA/QC 

requirement. Therefore, it will be impossible to reliably demonstrate compliance with an 

emission limit of 1 ppm. 

Response: See the preamble for revisions to the CO limitations and compliance demonstration 

methods. 

Commenter Name: Randall D. Quintrell

Commenter Affiliation: Georgia Paper and Forest Products Association, GPFPA

Document Control Number: EPA-HQ-OAR-2002-0058-2905

Comment Excerpt Number: 12

Comment: Testing at or near the detection limit produces unreliable data that are often an 

artifact of the testing and is not necessarily indicative that the material is present at all. Also, as 

any competent analyst knows, results below the practical quantitation limit (PQL) may indicate 

the presence of a compound but the concentration is not quantifiable and thus cannot legitimately 

be used as an indication of compliance status. Requiring facilities to spend hundreds of 

thousands of dollars a year to generate suspect data on sources known to have very low 

emissions of the target chemicals is not only an unreasonable burden on the regulated community 

but is counterproductive to EPA’s stated purpose of generating meaningful data. As the old 

adage goes "bad data is worse than no data." EPA has not even provided a scientifically valid 

basis for determining the MDL or PQL, or even how to handle the data in this realm. Further, 

while results below the practical quantitation limit (PQL) may indicate the presence of a 

compound, the concentration is not quantifiable and thus cannot legitimately be used as an 

indication of compliance status! The Rule must specify that any test result below the quantitation 

limit is deemed to be in compliance. 

Response: Addressed in response to EPA-HQ-OAR-2002-0058-2905, Comment Excerpt 

Number: 6. 

Commenter Name: Randall D. Quintrell

Commenter Affiliation: Georgia Paper and Forest Products Association, GPFPA

Document Control Number: EPA-HQ-OAR-2002-0058-2905

Comment Excerpt Number: 14

Comment: An unreasonable testing requirements is the dioxin/furan testing mandate with no 

opportunity for relief no matter how well the unit performs. The available data show that the 

emissions of dioxin/furans from industrial boilers are very low and the data are seriously 

impacted by non-detectible results and high variability in method detection limits. Under the 

current proposal, a boiler unit could conceivably have tests that are non-detect for all congeners 
262

and still be out of compliance with the standards. As detailed in other’s comments, prior to 

promulgating compliance standards for dioxin/furans, EPA has an obligation to develop 

acceptable method detection levels and practical quantitation limits for this testing procedure (as 

well as for all other stack tests with low emissions results) and to develop protocols for handling 

non-detect data and data below PQL before establishing performance testing requirements. This 

is fundamental and essential so that (i) test results are handled consistently and reported properly, 

and (ii) to ensure that no source with emissions below PQL levels can be considered noncompliant. Until that occurs, the dioxin/furan test method is unacceptable as a compliance 

measure and this testing requirement should be deleted from the final Boiler MACT as a 

regulatory requirement. The Federal Register did not even list the testing procedure to use for 

Dioxin/Furan. It was omitted on page 32070 Table 5. 

Response: Regarding EPA’s guidance on reporting of non-detect values for compliance 

purposes, sources should use the guidance in Section 9.9 of Method 23 that all measurements 

below the detection limit (calculated as per Method 23) should be treated as zero for the purpose 

of calculating dioxins/furans emissions. 

The final rule will clarify and reiterate the need to report D/F emissions concentration as 

prescribed in Method 23, on a mass basis and to follow the method's procedures for reporting 

values measured below the test-specific minimum detectable limit. 

Commenter Name: Ashok K. Jain

Commenter Affiliation: National Council for Air and Stream Improvement

Document Control Number: EPA-HQ-OAR-2002-0058-2804.1

Comment Excerpt Number: 20

Comment: (g)PS-11 requires sources to conduct a minimum of 15 manual reference test 

methods. 

Section 2.4(7) of PS-11 states: “Because the manual reference method testing for this correlation 

test is not for compliance reporting purposes, you may conduct the reference method test runs for 

less than the typical minimum test run duration of 1 hour.” 

EPA has, however, failed to recognize that at the proposed PM standards, even a 1-hour run will 

not collect a PM mass above the quantitation limit of Method 5. Since results obtained with data 

below method quantitation limits are not valid, EPA should make technical amendments to 

Section 2.4(7) and clarify that measurements below the method quantitation limits should not be 

used to calibrate monitors used to demonstrate compliance with emission standards. 

Response: EPA agrees that it is important to collect sufficient particulate mass. We estimate a 

mass of 3 to 5 mg is required per run for this rule, and that will take more than one hour. Section 

2.4(7) allows shorter run times if sufficient particulate matter is collected, but is not relevant 

when longer run times are required.
263

Commenter Name: David A. Buff

Commenter Affiliation: Golder Associates Inc

Document Control Number: EPA-HQ-OAR-2002-0058-2801.1

Comment Excerpt Number: 60

Comment: How to treat non-detects when doing compliance test. Suggest if all 3 runs are nondetect, treat result as zero. 

Response: Regarding EPA’s guidance on reporting of non-detect values for compliance 

purposes, sources should use the guidance included in each promulgated test method. In the 

longer term, it is still under consideration whether it makes sense to specify one or more standard 

Agency practices for method detection limit determination. 

The final rule will clarify and reiterate the need to report D/F emissions concentration as 

prescribed in Method 23, on a mass basis and to follow the method's procedures for reporting 

values measured below the test-specific minimum detectable limit. Section 9.9 of Method 23 

states that all measurements below the detection limit (calculated as per Method 23) should be 

treated as zero for the purpose of calculating dioxins/furans emissions.

Commenter Name: Matthew Todd and David Friedman

Commenter Affiliation: American Petroleum Institute (API) and National Petrochemical and 

Refiners Association (NPRA)

Document Control Number: EPA-HQ-OAR-2002-0058-2960.1

Comment Excerpt Number: 136

Comment: Recommendation: As discussed in Comment IV.A.2, EPA should undertake a study 

to quantify the limit of quantitation, repeatability and reproducibility for CO measurements using 

EPA Methods 10 and 3A to determine the lowest concentrations that can be measured with 

reasonable certainty. 

Response: See the preamble for revisions to the CO limitations and compliance demonstration 

methods. 

Commenter Name: Matthew Todd and David Friedman

Commenter Affiliation: American Petroleum Institute (API) and National Petrochemical and 

Refiners Association (NPRA)

Document Control Number: EPA-HQ-OAR-2002-0058-2960.1

Comment Excerpt Number: 258
264

Comment: What is the availability and accuracy of CO monitors that can measure in the 500-

1,000ppb range? 

Response: See the preamble for revisions to the CO limitations and compliance demonstration 

methods. 

Commenter Name: S. Lewis Ebert

Commenter Affiliation: North Carolina Chamber

Document Control Number: EPA-HQ-OAR-2002-0058-2890.1

Comment Excerpt Number: 2

Comment: Due to the methodology the EPA is using, the Boiler MACT emission limits will be 

extremely stringent, imposing levels that can barely be detected.

Response: Probability procedures applied in calculating the floor or an emissions limit 

inherently and reasonably account for emissions data variability including measurement 

imprecision when the database represents multiple tests from multiple emissions units for which 

all of the data are measured significantly above the method detection level. That is less true when 

the database includes emissions occurring below method detection capabilities and are reported 

as the method detection level values.

We applied the following procedures to account for the effect of measurement imprecision 

associated with a database that includes method detection level data. The first step was to define 

a method detection level that is representative of the data used in establishing the floor or 

emissions limit and that also minimizes the influence of an outlier test-specific method detection 

level value. We reviewed each pollutant-specific data set to identify the highest test-specific 

method detection level reported that was also equal to or less than the average emissions level 

(i.e., unadjusted for probability confidence level) calculated for the data set. We believe that this 

approach is representative of the data collected to develop the floor or emissions limit while to 

some degree minimizes the effect of a test(s) with an inordinately high method detection level 

(e.g., the sample volume was too small, the laboratory technique was insufficiently sensitive, or 

the procedure for determining the detection level was other than that specified).

The second step in the process is to calculate three times the representative method detection 

level and compare that value to the calculated floor or emissions limit. If three times the 

representative method detection level were less than the calculated floor or emissions limit 

calculated from the UPL, we would conclude that measurement variability was adequately 

addressed. The calculated floor or emissions limit would need no adjustment. If, on the other 

hand, the value equal to three times the representative method detection level were greater than 

the UPL, we would conclude that the calculated floor or emissions limit does not account 

entirely for measurement variability. If indicated, we substituted the value equal to three times 

the representative method detection level to apply as the adjusted floor or emissions limit. This 
265

adjusted value would ensure measurement variability is adequately addressed in the floor or the 

emissions limit. 

Commenter Name: Glenn C. England

Commenter Affiliation: Environ

Document Control Number: EPA-HQ-OAR-2002-0058-2809.1

Comment Excerpt Number: 6

Comment: EPA shoud re-assess test method performance capabilities at low concentrations and 

revise the proposed emission limits to assure that they are not less than the limit of quantitation 

for their respective measurement methods. Many of the proposed performance test methods for 

demonstrating compliance with the proposed emission limits were conceived, developed and 

evaluated in the 1980’s and 1990’s for application to waste incinerators, municipal waste 

combustors and coal-fired boilers. They have not been similarly evaluated for concentrations as 

low as many of the proposed emission limits. The fact that a method produces a number does not 

necessarily mean that number is a reliable indication of the true value. The range of detection 

limits reported in EPA’s database indicates the need for a full evaluation of method performance 

at low concentrations, including precision, accuracy and reproducibility. 

Response: We agree that test method measurement imprecision is a contributor to the variability 

of a set of emissions data. One element is associated with method detection capabilities and a 

second is a function of the measurement value. Measurement imprecision is proportionally 

highest for values measured below or near a method’s detection level and proportionally 

decreasing for values measured above the method detection level. 

Probability procedures applied in calculating the floor or an emissions limit inherently and 

reasonably account for emissions data variability including measurement imprecision when the 

database represents multiple tests from multiple emissions units for which all of the data are 

measured significantly above the method detection level. That is less true when the database 

includes emissions occurring below method detection capabilities and are reported as the method 

detection level values.

We applied the following procedures to account for the effect of measurement imprecision 

associated with a database that includes method detection level data. The first step was to define 

a method detection level that is representative of the data used in establishing the floor or 

emissions limit and that also minimizes the influence of an outlier test-specific method detection 

level value. We reviewed each pollutant-specific data set to identify the highest test-specific 

method detection level reported that was also equal to or less than the average emissions level 

(i.e., unadjusted for probability confidence level) calculated for the data set. We believe that this 

approach is representative of the data collected to develop the floor or emissions limit while to 

some degree minimizes the effect of a test(s) with an inordinately high method detection level 

(e.g., the sample volume was too small, the laboratory technique was insufficiently sensitive, or 

the procedure for determining the detection level was other than that specified).
266

The second step in the process is to calculate three times the representative method detection 

level and compare that value to the calculated floor or emissions limit. If three times the 

representative method detection level were less than the calculated floor or emissions limit 

calculated from the UPL, we would conclude that measurement variability was adequately 

addressed. The calculated floor or emissions limit would need no adjustment. If, on the other 

hand, the value equal to three times the representative method detection level were greater than 

the UPL, we would conclude that the calculated floor or emissions limit does not account 

entirely for measurement variability. If indicated, we substituted the value equal to three times 

the representative method detection level to apply as the adjusted floor or emissions limit. This 

adjusted value would ensure measurement variability is adequately addressed in the floor or the 

emissions limit. 

Commenter Name: Jacquelyn Taylor

Commenter Affiliation: South Carolina Pulp and Paper Association

Document Control Number: EPA-HQ-OAR-2002-0058-3154.1

Comment Excerpt Number: 6

Comment: Metso has also stated that Energy and Environmental Research Center (EERC) has 

advised them that the measurement methods for the hazardous air pollutants HCl, Hg and 

dioxin/furans are extremely problematic. For example, if non-detects are assigned a non-zero 

value, the dioxin/furan limits will be exceeded; or, if someone smokes a cigarette near a test, it 

could contaminate the test with enough dioxin to put the facility out of compliance. These are 

conditions that SCPPA member facilities are unwilling to accept. 

Response: Regarding EPA’s guidance on reporting of non-detect values for compliance 

purposes, sources should use the guidance in Section 9.9 of Method 23 that all measurements 

below the detection limit (calculated as per Method 23) should be treated as zero for the purpose 

of calculating dioxins/furans emissions. 

Commenter Name: Christy Sammon

Commenter Affiliation: Southeast Lumber Manufacturers Association

Document Control Number: EPA-HQ-OAR-2002-0058-2727.1

Comment Excerpt Number: 9

Comment: There is a lack of published demonstrated detection limits for the constituents of 

concern in the EPA standard methods that must be used to demonstrate compliance. This issue 

can be observed in the floor data itself, where the detection limits vary by two or more orders of 

magnitude for a single constituent during multiple runs at a single facility. Given the diverse 

universe of facilities, stack testing contractors, and analytical laboratories, attempting to set a 
267

numerical standard based on non-detect values from only one or two sources is clearly 

technically incorrect. Facilities may find themselves in "non-compliance" even though their 

compliance test results may have been non-detect when using EPA standard methods. 

Response: Test method measurement imprecision is a contributor to the variability of a set of 

emissions data. One element is associated with method detection capabilities and a second is a 

function of the measurement value. Measurement imprecision is proportionally highest for 

values measured below or near a method’s detection level and proportionally decreasing for 

values measured above the method detection level. 

Probability procedures applied in calculating the floor or an emissions limit inherently and 

reasonably account for emissions data variability including measurement imprecision when the 

database represents multiple tests from multiple emissions units for which all of the data are 

measured significantly above the method detection level. That is less true when the database 

includes emissions occurring below method detection capabilities and are reported as the method 

detection level values.

We applied the following procedures to account for the effect of measurement imprecision 

associated with a database that includes method detection level data. The first step was to define 

a method detection level that is representative of the data used in establishing the floor or 

emissions limit and that also minimizes the influence of an outlier test-specific method detection 

level value. We reviewed each pollutant-specific data set to identify the highest test-specific 

method detection level reported that was also equal to or less than the average emissions level 

(i.e., unadjusted for probability confidence level) calculated for the data set. We believe that this 

approach is representative of the data collected to develop the floor or emissions limit while to 

some degree minimizes the effect of a test(s) with an inordinately high method detection level 

(e.g., the sample volume was too small, the laboratory technique was insufficiently sensitive, or 

the procedure for determining the detection level was other than that specified).

The second step in the process is to calculate three times the representative method detection 

level and compare that value to the calculated floor or emissions limit. If three times the 

representative method detection level were less than the calculated floor or emissions limit 

calculated from the UPL, we would conclude that measurement variability was adequately 

addressed. The calculated floor or emissions limit would need no adjustment. If, on the other 

hand, the value equal to three times the representative method detection level were greater than 

the UPL, we would conclude that the calculated floor or emissions limit does not account 

entirely for measurement variability. If indicated, we substituted the value equal to three times 

the representative method detection level to apply as the adjusted floor or emissions limit. This 

adjusted value would ensure measurement variability is adequately addressed in the floor or the 

emissions limit. 

Commenter Name: John Hopewell

Commenter Affiliation: American Coatings Association
268

Document Control Number: EPA-HQ-OAR-2002-0058-2886.1

Comment Excerpt Number: 16

Comment: EPA should address detection limit and non -detect reporting issues. 

Response: Probability procedures applied in calculating the floor or an emissions limit 

inherently and reasonably account for emissions data variability including measurement 

imprecision when the database represents multiple tests from multiple emissions units for which 

all of the data are measured significantly above the method detection level. That is less true when 

the database includes emissions occurring below method detection capabilities and are reported 

as the method detection level values.

We applied the following procedures to account for the effect of measurement imprecision 

associated with a database that includes method detection level data. The first step was to define 

a method detection level that is representative of the data used in establishing the floor or 

emissions limit and that also minimizes the influence of an outlier test-specific method detection 

level value. We reviewed each pollutant-specific data set to identify the highest test-specific 

method detection level reported that was also equal to or less than the average emissions level 

(i.e., unadjusted for probability confidence level) calculated for the data set. We believe that this 

approach is representative of the data collected to develop the floor or emissions limit while to 

some degree minimizes the effect of a test(s) with an inordinately high method detection level 

(e.g., the sample volume was too small, the laboratory technique was insufficiently sensitive, or 

the procedure for determining the detection level was other than that specified).

The second step in the process is to calculate three times the representative method detection 

level and compare that value to the calculated floor or emissions limit. If three times the 

representative method detection level were less than the calculated floor or emissions limit 

calculated from the UPL, we would conclude that measurement variability was adequately

addressed. The calculated floor or emissions limit would need no adjustment. If, on the other 

hand, the value equal to three times the representative method detection level were greater than 

the UPL, we would conclude that the calculated floor or emissions limit does not account 

entirely for measurement variability. If indicated, we substituted the value equal to three times 

the representative method detection level to apply as the adjusted floor or emissions limit. This 

adjusted value would ensure measurement variability is adequately addressed in the floor or the 

emissions limit. 

Regarding EPA’s guidance on reporting of non-detect values for compliance purposes, sources 

should use the guidance included in each promulgated test method.

Commenter Name: Pamela F. Faggert

Commenter Affiliation: Dominion

Document Control Number: EPA-HQ-OAR-2002-0058-2908.1

Comment Excerpt Number: 29
269

Comment: The proposed rule has several new and existing boiler types with CO limits proposed 

at 1 ppm and one new boiler type at 7 ppm. The current Performance Standard 4A is applicable 

for CO levels less than 200 ppm, but it is clearly recognized that these monitors are not accurate 

or intended for very low levels as proposed by these rules. PS4A has a number of QA 

requirements, such as Calibration Gas Audit (CGA) and Relative Accuracy (RA) audits to insure 

accuracy, however, the most stringent acceptable level of error is 5 ppm. Clearly you cannot 

demonstrate compliance with a 7 or 1 ppm limit with a monitoring system that is only capable of 

5 ppm accuracy. In addition, we are not aware of any available calibration gas standards that 

would be required for a system spanned at greater than 20 ppm. Therefore, CO CEMS would 

only be applicable to monitor limits of 10 ppm and higher.

Response: See the preamble for revisions to the CO limitations and compliance demonstration 

methods. 

Commenter Name: Russ A. Wozniak

Commenter Affiliation: Dow Chemical Company

Document Control Number: EPA-HQ-OAR-2002-0058-2632.1

Comment Excerpt Number: 37

Comment: Comments on Reference Method Testing - EPA Method 10. Demonstrating 

compliance with a 1 ppmv CO limit by conducting testing via EPA Reference Method 10 will be 

very difficult, and may not be possible, to demonstrate as noted by the comments below: 

Dow’s interpretation of Methods 10 and 7E is that the span of the CO analyzer cannot be greater 

than 5 ppmv as Section 3.4 of Method 10 notes that the measured emissions should be between 

20-100 percent of the calibration span. So, even if measured emissions were 1 ppmv, the span 

could not exceed 5 ppmv. Section 9.0 of EPA Method 7E has a QA/QC table that states that the 

analyzer and calibration gas performance must be within 2% of the calibration span of the 

analyzer (2% of 5 ppmv = 0.1 ppmv) or alternatively 0.5 ppmv. Using the 2% criteria means that 

the acceptable result of the span calibration verification would have to be within 2% or within 

0.1 ppmv of the calibration gas, which borders on the reasonable detection capabilities of a CO 

emission analyzer. 

Thus, one would be forced to use the alternative 0.5 ppmv for QA/QC purposes. This level is 

troubling in that the uncertainty of the measurement is 50% of the proposed emission standard in 

this case, thus further contributing to the challenges of meeting a 1 ppmv standard on a 

consistent basis. 

In addition, EPA Method 7E requires the use of three calibration gases between the 0 to 5 ppmv 

level in order to meet the QA/QC requirements for the analysis. Dow comments that obtaining 

and using three different calibration gas standards in this range is a requirement that is excessive 

in this case and that the QA/QC requirements should be modified to require only a single point 

calibration at these low concentrations. 
270

Similar to the calibration concerns, allowable drift would also have to meet the same alternative 

criteria of 0.5 ppmv, which again is 50% of the allowable CO concentration. 

Response: See the preamble for revisions to the CO limitations and compliance demonstration 

methods. 

Commenter Name: Jim Griffin

Commenter Affiliation: American Chemistry Council

Document Control Number: EPA-HQ-OAR-2002-0058-2792.1

Comment Excerpt Number: 36

Comment: EPA has specified that ASTM Method D6784-02 (2008) may be used as an 

alternative to Method 29 to demonstrate compliance with the Hg standard. This ASTM method is 

similar to EPA Method 29 in using a probe and filter assembly to capture any mercury present in 

the solid phase. 

In this proposal and in its Phase II ICR EPA specified the use of either Method 29 or ASTM 

Method D6784-02 for measuring stack emissions of mercury and has used data obtained with 

both methods to set the proposed MACT standards for mercury. In doing this, EPA has failed to 

recognize some significant differences between the two methods. For example: 

* In the Phase II ICR, EPA also specified a 4-hour run and a sample volume of 4 m3. However, 

the ASTM method specifies that the sampling duration should not exceed 3 hours and a 

maximum sample volume of 2.5 m3 is specified. It is known that as the averaging period for a 

standard goes down, the emission profile changes and gives higher peaks. Consequently, it 

would not be appropriate to use ASTM Method 6784-02 to demonstrate compliance with a 4-

hour mercury emission standard.

* An examination of the two methods would show that the resulting volumes of the sub-samples 

obtained with the two methods are different. Thus if one follows the Phase II ICR protocol for 

reporting values below the method detection limit as being equal to the detection limit, one 

would get different results when sample fractions are non-detect. For example, in Method 29 

when the contents of the KMnO4 impingers are processed, one obtains two 500 mL sub-samples 

for mercury analysis. In the case of ASTM Method D6784-02, the processing of the KMnO4 

impinger solution would result in a single 500- 600 mL sample. Thus, if the detection limits of 

the analyzers used with the two methods are the same, the emission rate reported for non-detect 

measurements using Method 29 is used would be nearly twice that reported for the ASTM 

method. 

Based on the above inconsistencies between the two methods, we recommend that EPA should 

either utilize the results of only one of the two methods to set emission limits or should conduct 

simultaneous emissions tests using both methods on sources to determine whether or not the two 
271

methods give equivalent results. Additionally, EPA should reexamine its proposed requirement 

for sources to test for 4 hours and a 4 m3 volume, since this cannot be achieved when ASTM 

D6784-02 is utilized for source testing. 

Response: The final rule includes EPA Methods 30 A and 30B for mercury.

Also, we agree with commenters that the rule must clarify minimum sample volumes and assure 

that the specifications are consistent between test methods and with the method capabilities. See 

the response to EPA-HQ-OAR-2002-0058-1907.1, Comment Excerpt Number:8.

Measurement Methodology Impractical

Commenter Name: G. Vinson Hellwig

Commenter Affiliation: Michigan Department of Natural Resources and Environment

Document Control Number: EPA-HQ-OAR-2002-0058-2837.1

Comment Excerpt Number: 3

Comment: Regarding the feasibility of designing sampling ports for boiler stacks with small 

diameters (less than 12 inches) we consider such testing to be unnecessary due to the minimal 

expected impact on air quality from boilers that operate with small diameter stacks. The 

proposed work practice standards will provide adequate emission control for small boilers 

without the addition of a testing requirement. 

A representative search of 30 Michigan air permits for small boilers identified eight boilers, rated 

at 3.35 million British thermal units per hour (MMBtu/hr) or less, with stack diameters less than 

12 inches. For comparison, some of the same facilities also operate emergency generators 

(reciprocating internal combustion engines) rated up to 1000 kilowatts (kW) with exhaust stacks 

less than 12 inches in diameter. A generator output of 1000 kW is equivalent to 3.4 MMBtu/hr or 

1341 horsepower. On March 3, 2010, EPA published final revisions to the NESHAP for 

Reciprocating Internal Combustion Engines (RICE) (40 CFR Part 63 Subpart ZZZZ), which 

includes performance testing requirements for carbon monoxide (CO) and formaldehyde on a 

concentration basis, using established test methods applicable to small diameter stacks. If EPA 

includes a performance test requirement for boilers with small diameter stacks, perhaps an 

approach similar to that taken for the RICE NESHAP would be more suitable for the small 

boilers. 

Response: We agree with commenters that there are some practical limitations for applying 

isokinetic sampling procedures for small pipes and ducts. Method 1A, though, applies between 

12 inch and 4 inch diameter pipes but not smaller.

Commenter Name: Robert G. Hedden
272

Commenter Affiliation: Oilheat Manufacturers Association

Document Control Number: EPA-HQ-OAR-2002-0058-3188

Comment Excerpt Number: 7

Comment: It is our understanding that the proposed test procedure requires at least a 12-inch 

diameter flue pipe. The flue pipes on less than 3 MMBtu/h boilers are 4 to 8 inches. Increasing 

the flue pipe size to perform the test will increase condensing of the flue gasses in the flue pipe 

and heat exchanger and result in decreased efficiency, and increased fuel consumption. 

Response: We agree with commenters that there are some practical limitations for applying 

isokinetic sampling procedures for small pipes and ducts, Method 1A ,though, applies between 

12 inch and 4 inch diameter pipes but not smaller.

Commenter Name: N/A

Commenter Affiliation: Sierra Club, Clean Air Task Force, Earthjustice, and Natural Resources 

Defense Council

Document Control Number: EPA-HQ-OAR-2002-0058-3187.1

Comment Excerpt Number: 42

Comment: The limitations identified by EPA do not make measurement methodology 

impracticable. EPA does not claim that any measurement method other than method 5 raises any 

technical issues at all for stacks less than twelve inches in diameter. Method 5, as EPA points 

out, is a method for measuring emissions of PM. Thus, the alleged technical limitation on 

measuring emissions in stacks with diameters less than twelve inches are not even relevant to 

emissions of other HAPs. Even if valid, such concerns would lend no support to setting work 

practice standards in lieu of emission standards for pollutants other than PM. 

EPA’s alleged concerns about the absence of sampling ports and platforms are unsupported by 

record evidence and unconnected to the statutory standard. EPA does not say how many major 

source boilers with less than 10 MMBtu/hr heat input capacity do not have sampling ports or 

platforms, and thus gives no indication about whether the absence of such equipment is even an 

issue for a significant portion of the population. Moreover, EPA does not even claim that it 

would be impracticable to install sampling ports or platforms on boilers that currently lack them, 

far less provide record evidence to support such a claim. Absent showings that boilers do not 

have and cannot install sampling ports or platforms, EPA’s bare assertion that some boilers 

currently lack them is statutorily irrelevant. Notably, the record for EPA’s area source boilers 

rule includes discussion of a study in which the majority of emissions data for the study was 

from boilers smaller than 10 MMBtu/hr. [EPA-HQ-OAR-2006-0790-0048.] Stack tests were 

taken for PM10, PM2.5, and condensable PM. The document containing that study notes that 

many state permitting authorities require “a number of technical analyses” which can include 

emissions tests, from these small boilers. Id. at 1. If small boilers must provide this information 

to state regulatory agencies, boiler operators must have developed ways to test emissions from 

small boilers. 
273

Response: There are some practical limitations for applying isokinetic sampling procedures for 

small pipes and ducts, Method 1A applies between 12 inch and 4 inch diameter pipes but not 

smaller.

Commenter Name: Matthew Todd and David Friedman

Commenter Affiliation: American Petroleum Institute (API) and National Petrochemical and 

Refiners Association (NPRA)

Document Control Number: EPA-HQ-OAR-2002-0058-2960.1

Comment Excerpt Number: 138

Comment: Another measurement issue revolves around measuring and thus controlling the 

excess air level in large boilers and process heaters. Members have reported CO spikes in large 

boilers and process heaters with multiple burners that may be due to one or more individual 

burners being starved for air while the remaining burners have excess air. This is not uncommon, 

especially in large natural draft process heaters where the differential pressure between the 

furnace and the external air at the burner level may vary across the furnace, leading to a 

maldistribution of air flow. An objective of tune-ups is to minimize these maldistributions via 

visual inspection of burner flames. However, it can be difficult to eliminate them entirely. For 

example, diurnal cycles in prevailing wind direction can shift the air distribution from one side to 

the other. In these cases, the stack or bridgewall O2 reading appears normal, but it may not 

represent the true O2 level at each burner. This is another case, where the need to run with an 

extra margin of excess air is critical. 

Recommendation: Do not establish numerical emission limitations for CO for gases or liquids, 

since the measurement technology is not available to demonstrate compliance. 

Response: See the preamble for revisions to the CO limitations and compliance demonstration 

methods. 

Reduced Testing Allowance

Commenter Name: Thomas J. Christofk

Commenter Affiliation: Placer County Air Pollution Control District

Document Control Number: EPA-HQ-OAR-2002-0058-1598.1

Comment Excerpt Number: 5
274

Comment: PCAPCD does not support the requirement for annual source testing for mercury, 

HCl, or 

dioxin. PCAPCD requests that a testing frequency of at the most every three (3) years, with an 

option of every four (4) years if test results are < 75% of the standard, or every five (5) years if 

results are < 50% of the standard. 

Response: EPA has eliminated the requirement for annual testing of dioxin/furan emissions. 

The final rule maintains the remaining provisions of the reduced testing provisions as proposed, 

balancing the need to demonstrate ongoing compliance with the burdens associated with these 

provisions. 

Commenter Name: Michael L. Steele

Commenter Affiliation: CraftMaster Manufacturing, Inc

Document Control Number: EPA-HQ-OAR-2002-0058-1907.1

Comment Excerpt Number: 36

Comment: §63.751S(b),(c) 

Why does the reduced stack testing option discussed in this section not apply to dioxin! furan 

emissions? 

Response: EPA has eliminated the requirement for annual testing of dioxin/furan emissions.

Commenter Name: Richard Krock

Commenter Affiliation: The Vinyl Institute

Document Control Number: EPA-HQ-OAR-2002-0058-2944.1

Comment Excerpt Number: 9

Comment: The proposed rule requires annual emissions testing, i.e., once every 10 to 12 

months, with only a limited option for testing every 3 years if emissions of certain regulated 

pollutants are below seventy-five percent (75%) of the applicable emission limit. The reduced 

testing frequency is not proposed for dioxin/furan or for facilities using emissions averaging. As 

the dioxin/furan testing is the most expensive testing requirement, this will be a significant 

annual cost for facilities. VI does not believe these restrictions are justified, and believes that 

testing should be required once every five (5) years. The rule requires continuous monitoring of 

operating parameters and fuel input that are meant to provide an ongoing assurance of 

compliance with the emission limits. As long as the facility can demonstrate that this compliance 

has been met and the facility operation (product manufacture) has not changed from its originally 

certified initial performance test and maintains operating parameters and fuel inputs within the 

established operating ranges, annual stack testing for all pollutants is not necessary. 
275

Response: EPA has eliminated the requirement for annual testing of dioxin/furan emissions.

Commenter Name: Wayne J. Galler and Deborah A. Phillips

Commenter Affiliation: Georgia Industry Environmental Coalition, Inc

Document Control Number: EPA-HQ-OAR-2002-0058-2882.1

Comment Excerpt Number: 9

Comment: The Boiler MACT Rule does allow for some relief for all of the HAPs, except for 

dioxins/furans, but only if three consecutive years of testing indicates values that are 75% or less 

than the permit limits. However, it will be difficult, if not impossible for companies to meet this 

threshold since the emission standards have been set very low to begin with. 

Response: Regarding the assertion that the margin for reduced testing is too high to be 

effective, we disagree and note that the intent of this provision is to provide an incentive for 

better performers. By specifying the less than 75 percent of the emission standard margin, we 

are providing such an incentive for good performance, and not rewarding units that just barely 

meet the standard for a pollutant.

Commenter Name: Wayne J. Galler and Deborah A. Phillips

Commenter Affiliation: Georgia Industry Environmental Coalition, Inc

Document Control Number: EPA-HQ-OAR-2002-0058-2882.1

Comment Excerpt Number: 11

Comment: With over 10,000 affected boilers in the US that will need to be tested, all within a 

short period of time it is highly questionable whether or not there will be a sufficient number of 

qualified stack testing firms available to test all of the units. EPA’srequirement for annual testing 

does not seem to take this fact into account. With the extended time for stack testing that EPA 

has proposed, the demands of time placed on all testing firm’s personnel will be extremely 

burdensome. in addition, it:is even more questionable if there are a sufficient number of qualified 

laboratories available to perform the analytical testing required for dioxin/furans. 

Response: The requirement for annual testing of dioxin/furan emissions is no longer applicable 

under the final rule, which addresses part of the commenter’s concerns. We have also removed 

the minimum run time provisions. EPA believes that there will be adequate stack test resources 

to comply with the rule.

Commenter Name: Gary W. Kruger

Commenter Affiliation: Morton Salt

Document Control Number: EPA-HQ-OAR-2002-0058-2883.1

Comment Excerpt Number: 13
276

Comment: Although EPA has included a provision to reduce testing to a 3-year frequency if a 

source passes three tests in a row with at least a 25% margin, very few if any units are likely to 

qualify given the very stringent limits EPA has proposed. 

Response: See the response to EPA-HQ-OAR-2002-0058-2882.1, Comment Excerpt Number 9.

Commenter Name: Richard Rosvold

Commenter Affiliation: Xcel Energy Services, Inc

Document Control Number: EPA-HQ-OAR-2002-0058-2955.1

Comment Excerpt Number: 17

Comment: The same testing frequency flexibility that is written into the rule for PM, mercury, 

acid gases, and CO should be extended to dioxins and furans. This type of testing flexibility is 

allowed under the Section 129 rules for waste combustors. There is no technical reason this type 

of flexibility cannot be employed here. 

Response: The final rule does not require annual testing for dioxin/furan emissions.

Commenter Name: Trina L. Vielhauer

Commenter Affiliation: Florida Department of Environmental Protection, Division of Air 

Resource Management

Document Control Number: EPA-HQ-OAR-2002-0058-2527.1

Comment Excerpt Number: 1

Comment: We are concerned that allowing reduced testing for mercury (and hydrochloric acid) 

will reduce the amount of data available regarding these hazardous air pollutants. In addition, we 

have realized that in some industries, mercury emissions are cyclical such that one stack test does 

not always represent daily emissions throughout the year. See the Division’s comments on 

EPA’s proposed mercury MACT, OAR-2002-0051. 

Response: The reduced testing applies only if the source demonstrates a significant margin of 

compliance in a series of tests. Based on the data available, EPA believes that this incentive for 

good performers is waraanted.

Commenter Name: Trina L. Vielhauer

Commenter Affiliation: Florida Department of Environmental Protection, Division of Air 

Resource Management

Document Control Number: EPA-HQ-OAR-2002-0058-2527.1

Comment Excerpt Number: 2
277

Comment: Furthermore, this reduced testing frequency is based upon a facility not making any 

operational changes or changes that impact emissions. In the Division’s experience, there is not 

always agreement between the regulatory agency and the facility about what constitute 

"operational changes" and "changes that impact emissions." At the very least, any reduced 

testing should be subject to review and approval by the regulatory agency to ensure all parties 

have the same expectations and understanding. 

Response: This is an issue for discussion with the source and would be grounds for requiring a 

retest if the agency identifies such changes.

Commenter Name: Stephen R. Gossett

Commenter Affiliation: Eastman Chemical Company

Document Control Number: EPA-HQ-OAR-2002-0058-3137.1

Comment Excerpt Number: 8

Comment: Annual stack tests required when using emissions averaging is excessive and 

unnecessary. 

Proposed §63.7515(c) does not allow stack testing frequency to skip to three years. As discussed 

below, annual performance testing in general is excessive and burdensome and not justified. 

Beyond these fundamental arguments, we see no reason to single out emissions averaging and 

require more restrictive performance testing for sources selecting this alternative. By definition, a 

source using emissions averaging must have a unit(s) which has superior performance over and 

beyond the emission standard. This superior performance will be proven by a performance test, 

the results of which have no more uncertainty than for a non-emission averaged unit. The 

emissions averaged units will have the same continuous monitoring requirements as the nonemissions averaged units to ensure the air pollution control devices are operated properly. Other 

MACT rules which incorporate emissions averaging do not require annual performance tests and 

we see no reason to vary from this precedent for boilers and process heaters. 

Response: The annual tests are an important component for providing a recent test result used in 

the monthly analysis of compliance with the averaging plan required under section 63.7522.

Commenter Name: Jack Carter

Commenter Affiliation: Weyerhaeuser Company

Document Control Number: EPA-HQ-OAR-2002-0058-2797.1

Comment Excerpt Number: 22

Comment: We appreciate that EPA’s proposal does offer the potential for reduction from the 

annual testing frequency to every three years if three consecutive tests fall below 75% of the 

emission standard. However, in reality this will bring little relief since it is unlikely to be 

achieved simultaneously for each of the eligible HAPs and therefore testing will have to continue 
278

for those HAPs not meeting the relief criterion. EPA does not apply reduced testing to 

dioxin/furan or to compliance test under the emissions averaging provisions. There is no valid 

reason for this limitation. 

Response: See the response to EPA-HQ-OAR-2002-0058-2882.1, Comment Excerpt Number 9. 

Also, annual testing for dioxin/furan is not required under the final rule. For emissions 

averaging, see the response to EPA-HQ-OAR-2002-0058-3137.1, Comment Excerpt Number 8.

 

Commenter Name: Arthur N. Marin

Commenter Affiliation: NESCAUM

Document Control Number: EPA-HQ-OAR-2002-0058-2893.1

Comment Excerpt Number: 29

Comment: In the proposed rules, EPA indicates that once a facility has demonstrated 

compliance with the emission limit, it can reduce the frequency of stack testing. There is, 

however, a lack of clarity on the percentage a facility must fall below the emission limit to 

qualify for this reduction. In section 63.7515(b), EPA specifies that a facility must fall below 

75% of the emission standard, whereas sections 63.7555 (c) (5) and 63.7555 (d) (6) refer to a 

90% threshold. The NESCAUM states request EPA to clarify its intent. 

Response: The final rule uses 75% consistently.

Commenter Name: Stephen R. Gossett

Commenter Affiliation: Eastman Chemical Company

Document Control Number: EPA-HQ-OAR-2002-0058-3137.1

Comment Excerpt Number: 54

Comment: We recognize EPA has included a provision to skip to a three year frequency (for all 

pollutants except D/F), but a source must pass three tests in a row with at least a 25 percent 

margin. Given the very stringent limits EPA has proposed, very few units are likely to qualify for 

this provision, so we are not sure of its value. 

Response: See the response to EPA-HQ-OAR-2002-0058-2882.1, Comment Excerpt Number 9.

Commenter Name: Britt S. Fleming

Commenter Affiliation: Auto Group

Document Control Number: EPA-HQ-OAR-2002-0058-2775.1

Comment Excerpt Number: 60
279

Comment: Proposed 63.7515 Subsection (b) – The 75% threshold for allowing less frequent 

performance testing is too stringent. Requiring a source to demonstrate emissions are less than 

75% of the emission limit creates a more stringent standard that may not be achievable by any 

source. Since emission limits are based on MACT floors, a source demonstrating compliance 

with the MACT limit should be allowed to perform testing on a less frequent schedule. At the 

very least, the 90% threshold identified at § 63.7555(d)(6) is a more appropriate threshold than 

the 75% threshold. This also needs to be considered for pollutants that have an emission limit 

that is close to the detection limit for the test method. See discussion above regarding how other 

standards allow skipping periodic monitoring without demonstrating compliance with a lower 

threshold. 

Proposed 63.7515 Subsections (b) and (c) – These provisions also should include less frequent 

performance demonstrations for D/F if it is demonstrated that the D/F limit is being met. EPA 

does not articulate a reason why a source should not have the same flexibility with D/F as with 

the other pollutants. 

Response: See the response to EPA-HQ-OAR-2002-0058-2882.1, Comment Excerpt Number 9. 

Also, the final rule does not require annual testing for dioxin/furan emissions.

Commenter Name: Britt S. Fleming

Commenter Affiliation: Auto Group

Document Control Number: EPA-HQ-OAR-2002-0058-2775.1

Comment Excerpt Number: 66

Comment: Proposed § 63.7555 Subsection (d)(6) – This provision requires that if consistent 

with § 63.7555(b) and (c), a source chooses to stack test less frequently than annually, the source 

must keep annual records that document that the emissions in the previous stack test(s) were less 

than 90 percent of the applicable emission limit, and document that there was no change in 

source operations including fuel composition and operation of air pollution control equipment 

that would cause emissions of the relevant pollutant to increase within the past year. The Auto 

Group recommends that EPA eliminate the 10% discount given that a source will demonstrate 

compliance with the MACT standard, which is what is required. 

Response: EPA disagrees. First, the applicable percentage has been corrected to read “75 

percent.” The subsection is integral to implementing the reduced testing frequency allowance 

provisions in section 63.7515.

Commenter Name: Timothy Hunt

Commenter Affiliation: American Forest and Paper Association (AF&PA)

Document Control Number: EPA-HQ-OAR-2002-0058-3213.1

Comment Excerpt Number: 281
280

Comment: The reduced testing frequency is not proposed for dioxin/furan or for facilities using 

emissions averaging, and emissions of the other regulated pollutants must be below 75 percent of 

the applicable emission limit to qualify for testing every 3 years. We do not believe these 

restrictions are justified, and as stated above, we believe that testing should be on a 5-year 

frequency. The rule requires continuous monitoring of operating parameters and fuel input that 

are meant to provide an ongoing assurance of compliance with the emission limits. As long as 

the facility continues to operate in a similar mode following the initial performance test and 

maintains operating parameters and fuel inputs within the established operating ranges, annual 

stack testing for all pollutants is not necessary. As the dioxin/furan testing is the most expensive 

testing requirement, this will be a significant annual cost for facilities. In addition, there is no 

basis provided for including the requirement that emissions during 3 consecutive stack tests be 

less than 75 percent of the emission limit in order to qualify for a reduced testing frequency. 

Therefore, we believe that the rule should allow for testing every 5 years for all pollutants as 

long as facilities are meeting the emission and operating parameter limits and have not made 

operational or air pollution control changes that could increase emissions above the limits. 

Response: See the response to EPA-HQ-OAR-2002-0058-2882.1, Comment Excerpt Number 9. 

Also, annual testing for dioxin/furan is not required under the final rule. For emissions 

averaging, see the response to EPA-HQ-OAR-2002-0058-3137.1, Comment Excerpt Number 8.

Commenter Name: Randall D. Quintrell

Commenter Affiliation: Georgia Paper and Forest Products Association, GPFPA

Document Control Number: EPA-HQ-OAR-2002-0058-2905

Comment Excerpt Number: 4

Comment: The proposed Rule would allow for some reduction in testing frequency for some 

parameters, but only after three years of extensive testing. For other parameters the testing 

frequency remains annual with no relief whatsoever, no matter how well the unit is shown to 

perform. Even for those units with an opportunity for relief in the Rule, the compliance margin 

required would have to be significantly increased. Emissions must be 75% or less of the standard 

to qualify for the relaxation in testing and if subsequent testing slips even slightly above 75% of 

the allowed level, the relief is revoked. However, even this "opportunity" for relief is not 

meaningful because the standards proposed in the Rule are so stringent that they have not been 

shown to be achievable in practice by the best performers. 

Response: See the response to EPA-HQ-OAR-2002-0058-2882.1, Comment Excerpt Number 9. 

Also, annual testing for dioxin/furan is not required under the final rule. 

Commenter Name: Robert D. Morrison

Commenter Affiliation: Abbott Laboratories

Document Control Number: EPA-HQ-OAR-2002-0058-2764.1

Comment Excerpt Number: 21
281

Comment: The requirement for annual emission testing and fuel analysis is unreasonable and 

overly burdensome (63.7510, 75 FR 32051). The requirement of annual emission testing for 

compliance demonstration is excessive, and should be reduced for all parameters. Allowances to 

skip two of three years for units that have demonstrate maintenance levels less than or equal to 

75 percent of emission limit provide some help, but are distinctly less useful if testing for D/F, 

the most costly and difficult test procedure, must be conducted annually irrespective of emission 

rates. Annual testing costs will be reduced, but testing will still require a major mobilization. In 

addition, it should not be necessary to require extensive fuel testing in addition to performance 

stack testing, as these data are redundant. 

Response: See the response to EPA-HQ-OAR-2002-0058-2882.1, Comment Excerpt Number 9. 

Also, annual testing for dioxin/furan is not required under the final rule. The fuel analysis 

requirements are an alternative to the use of stack tests to demonstrate compliance.

Commenter Name: Leonard W. Sandridge

Commenter Affiliation: University of Virginia

Document Control Number: EPA-HQ-OAR-2002-0058-2769.1

Comment Excerpt Number: 22

Comment: §63.7515(b) provides criteria for converting from annual performance testing to 

testing every three years, for all pollutants except D/F. Why is D/F singled out to be handled 

differently? 

Response: Annual testing for dioxin/furan emissions is not required in the final rule.

Commenter Name: Donald R. Schregardus

Commenter Affiliation: Department of Defense

Document Control Number: EPA-HQ-OAR-2002-0058-2763.1

Comment Excerpt Number: 24

Comment: EPA should revise §63.7515(b)-(d) and §63.7555(d)(6) to more clearly state the 

intent of §63.7515(d), use a 90 percent threshold for reducing the frequency of performance 

stack tests as stated in §63.7555(d)(6), and correct the referenced citation in §63.7555(d)(6) to 

cite §63.7515(b) and (c). 

The intent of §63.7515(b)-(d) appears to direct any regulated facility to re-test for a particular 

emission limit should the test results for that pollutant exceed 75 percent of the emission limit. 

Additionally, it appears as though the rule will allow less frequent performance testing for a 

pollutant which exceeded the 75 percent threshold once testing again shows results for three 

consecutive yearsless than 75 percent. However, confusion could arise for both the testing 

facilities and the enforcement agencies over the latter language in the regulation. Specifically, 
282

...until all performance tests over a consecutive 3-year period show compliance." A plausible 

reading of the proposed rule could be interpreted to mean when every pollutant meets the less 

frequent monitoring threshold, the facility may utilize less frequency monitoring. This is clearly 

not the intent of EPA as is provided in §63.7515(b). 

Based on §63.7555(d)(6), it also appears that EPA was considering changing the threshold for 

reducing the frequency of testing from 75 percent to 90 percent of the emission limit. DoD 

supports the higher threshold. There also appear to be some cross-reference errors in 

§63.7555(d)(6). The reference to §63.7555(b) and (c) does not relate to reducing the frequency 

of testing. We believe the correct references should be §63.7515(b) and (c). 

To eliminate any confusion, insert the words "for that pollutant" at the end of the proposed 

§63.7515(d), change the 75 percent threshold to 90 percent to be consistent with §63.7555(d)(6), 

and correct the cross-reference errors in §63.7555(d)(6). A suggested re-write of the rule would 

be: 

63.75 I 5(b) You can conduct performance stack tests less often for a given pollutant if your 

performance stack tests for the pollutant for at least 3 consecutive years show that your 

emissions are at or below 75 to 90 percent of the emission limit, and if there are no changes in 

the operation of the affected source or air pollution control equipment that could increase 

emissions. In this case, you do not have to conduct a performance test for that pollutant for the 

next 2 years. You must conduct a performance test during the third year and no more than 36 

months after the previous performance test. This reduced testing option does not apply to 

performance stack tests for dioxin/furan. If you elect to demonstrate compliance using emission 

averaging under §63.7522, you must continue to conduct performance stack tests annually. 

63.7515(c) If your boiler or process heater continues to meet the emission limit for the pollutant, 

you may choose to conduct performance stack tests for the pollutant every third year if your 

emissions are at or below 75 90 percent of the emission limit, and if there are no changes in the 

operation of the affected source or air pollution control equipment that could increase emissions, 

but each such performance test must be conducted no more than 36 months after the previous 

performance test. This reduced testing option does not apply to performance stack tests for 

dioxin/furan. If you elect to demonstrate compliance using emission averaging under §63.7522, 

you must continue to conduct performance stack tests annually. 

63.7515(d) If a performance test shows emissions exceeded 75 90 percent of the emission limit, 

you must conduct annual performance tests for that pollutant until all performance tests over a 

consecutive 3-year period show compliance for that pollutant. 

63.7555(d)(6) If consistent with 63.755563.7315’b) and (c), you choose to stack test less 

frequently than annually, you must keep annual records that document that your emissions in the 

previous stack test(s) were less than 90 percent of the applicable emission limit, and document 

that there was no change in source operations including fuel composition and operation of air 

pollution control equipment that would cause emissions of the relevant pollutant to increase 

within the past year. 
283

Response: The reduced testing frequency is on a per pollutant basis. The final rule has corrected 

the reference to 90 percent to read 75 percent.

Commenter Name: Donald R. Schregardus

Commenter Affiliation: Department of Defense

Document Control Number: EPA-HQ-OAR-2002-0058-2763.1

Comment Excerpt Number: 25

Comment: EPA should allow reduced stack testing for D/F in addition to the currently allowed 

pollutants when testing provides that emissions are at or below 75 percent of the emission limit 

and if there are no changes in the operation of the affected source or air pollution control 

equipment that could increase emissions. 

EPA proposes to allow less frequent stack testing for each pollutant with the exception of D/F. 

This will provide little if any cost savings to affected facilities that still must conduct these 

annual tests for D/F. EPA should allow for reduced testing for every pollutant in the boiler rule. 

EPA provides in background document "DRAFT Methodology for Estimating Impacts from 

Industrial, Commercial, Institutional Boilers and Process Heaters at Major Sources of Hazardous 

Air Pollutant Emissions" the cost to conduct stack testing for boilers and process heaters 

designed to burn solid and gaseous fuels. The estimates of these costs range from 

$37,000$44,000 for testing of PM, HC1, Hg, D/F, and CO (depending on boiler size). 

Theoretically, some costs savings may be realized due to less emissions analysis, such as from 5 

pollutants to 1 pollutant; however, testing for only D/F does not dramatically reduce testing costs 

as contractors must continue to mobilize to the site, set-up equipment and produce a test report 

with costs similar to annual stack testing. 

EPA should allow for less frequent performance testing for each pollutant meeting the 

requirements of §63.7515(b)-(d) including D/F. 

Response: Annual testing of dioxin/furan emissions is not required under the final rule.

Commenter Name: Leonard W. Sandridge

Commenter Affiliation: University of Virginia

Document Control Number: EPA-HQ-OAR-2002-0058-2769.1

Comment Excerpt Number: 25

Comment: 40 CFR 63.7522(a) allows a facility to demonstrate compliance by emission 

averaging for PM, HCl, and mercury. Why are CO and dioxins/furans excluded from the 

emission averaging provisions? 
284

Response: In the final rule, dioxins/furans have been adjusted to a one-time emission test and 

thus the emission averaging provisions would not apply. CO emissions are highly variable and 

therefore EPA did not determine that emissions averaging applied for CO.

Commenter Name: Chris Greissing

Commenter Affiliation: Industrial Minerals Association

Document Control Number: EPA-HQ-OAR-2002-0058-2740.2

Comment Excerpt Number: 29

Comment: (b) You can conduct performance stack tests less often for a given pollutant if your 

performance stack tests for the pollutant for at least 3 consecutive years show that your 

emissions are at or below 75 percent of the emission limit, and if there are no changes in the 

operation of the affected source or air pollution control equipment that could increase 

emissions...This reduced testing option does not apply to performance stack tests for 

dioxin/furan. 

EPA should amend paragraph (b) to make reduced performance testing available to dioxin/furan. 

As a precondition to reduced performance testing, a boiler owner must not have changed 

operations or fuel types. Under such conditions, there would be no expectation that the 

dioxin/furan emissions would change more dramatically year-to-year than HCl or mercury. 

Moreover, EPA Reference Method 23 for dioxins/furans is the most expensive of all the required 

emission tests under this rule. 

Response: Annual testing of dioxin/furan emissions is not required under the final rule.

Commenter Name: Chris Greissing

Commenter Affiliation: Industrial Minerals Association

Document Control Number: EPA-HQ-OAR-2002-0058-2740.2

Comment Excerpt Number: 34

Comment: 63.7550. What reports must I submit and when? 

(c)(5)A summary of the results of the annual performance tests and documentation of any 

operating limits that were reestablished during this test, if applicable. If you are conducting stack 

tests once every three years consistent with 63.7515(b) or (c), the date of the last three stack 

tests, a comparison of the emission level you achieved in the last three stack tests to the 90 

percent emission limit threshold required in 63.7515(b) or (c). 

Paragraph (c)(5) describes the criterion for reduced stack test frequency as 90 percent of the 

emission limit; however, 63.7515(b) and (c) specifies 75 percent of the emission limit. The 

criterion should be 75 percent of the emission limit. 

Response: This has been corrected in the final rule.
285

Commenter Name: Chris Greissing

Commenter Affiliation: Industrial Minerals Association

Document Control Number: EPA-HQ-OAR-2002-0058-2740.2

Comment Excerpt Number: 35

Comment: 63.7555. What records must I keep? 

(d) (6) If consistent with 63.7555(b) and (c), you choose to stack test less frequently than 

annually, you must keep annual records that document that your emissions in the previous stack 

test(s) were less than 90 percent of the applicable emission limit... 

The reference to Section 63.7555(b) and (c) is incorrect. EPA needs to amend the Proposed Rule 

to read “ 63.7515(b) and (c).” Paragraph (d)(6) describes the criterion for reduced stack test 

frequency as 90 percent of the emission limit; however, 63.7515(b) and (c) specifies 75 percent 

of the emission limit. The criterion should be 75 percent of the emission limit. 

Response: This has been corrected in the final rule.

Commenter Name: David A. Buff

Commenter Affiliation: Golder Associates Inc

Document Control Number: EPA-HQ-OAR-2002-0058-2801.1

Comment Excerpt Number: 57

Comment: Remove requirement to be 75 percent of limit to be eligible for reduced frequency 

Response: EPA disagrees and note that the intent of this provision is to provide an incentive for 

better performers. By specifying the less than 75 percent of the emission standard margin, we 

are providing such an incentive for good performance, and not rewarding units that just barely 

meet the standard for a pollutant.

Commenter Name: Robert D. Bessette

Commenter Affiliation: Council of Industrial Boiler Owners (CIBO)

Document Control Number: EPA-HQ-OAR-2002-0058-2702.1

Comment Excerpt Number: 133

Comment: We recognize EPA has included a provision to skip to a three year frequency, but a 

source must pass three tests in a row with at least a 25 percent margin. Given the very stringent 

limits EPA has proposed, very few, if any units are likely to qualify for this provision, so we are 

not sure of its value. 
286

Response: Regarding the assertion that the margin for reduced testing is too high to be effective, 

we disagree and note that the intent of this provision is to provide an incentive for better 

performers. By specifying the less than 75 percent of the emission standard margin, we are 

providing such an incentive for good performance, and not rewarding units that just barely meet 

the standard for a pollutant.

Commenter Name: Matthew Todd and David Friedman

Commenter Affiliation: American Petroleum Institute (API) and National Petrochemical and 

Refiners Association (NPRA)

Document Control Number: EPA-HQ-OAR-2002-0058-2960.1

Comment Excerpt Number: 179

Comment: Proposed 63.7517(c) specifies a repeat performance test be done within 36 months of 

the previous test if the three year skip test interval has been achieved. This requirement leads to 

relative to annual testing. Requiring the test every 36 months from the previous test means the 

testing interval will be less than three years and will be hard to manage. 

Recommendation: Revise 63.7517(c) to require that any required repeat performance testing be 

done in the calendar quarter three years after the calendar quarter in which the previous test was 

performed. 

Response: The final language requires that the next test be conducted within 37 months after the 

prior test.

Commenter Name: Patrick Strauch

Commenter Affiliation: Maine Forest Products Council

Document Control Number: EPA-HQ-OAR-2002-0058-3120.1

Comment Excerpt Number: 6

Comment: Another suggestion we have heard from our members is that the EPA might consider 

incorporating a standard in the rule that allows facilities with boilers targeted in this rule to test 

out of more rigid testing procedures should they meet certain efficiency standards. For instance, 

if a boiler were to test to certain efficiency, the company would then have to test levels of certain 

pollutants on a five year basis, rather than on an annual one. Recognizing that existing boilers 

would have three years in which to meet the standards once this rule is finalized, this option is 

viewed as favorable and constructive alternatives by the industry. 

Response: EPA does not believe that this idea is warranted at this time, and would require 

further analysis and data to determine if it is appropriate.

Commenter Name: J. Michael Geers
287

Commenter Affiliation: Duke Energy

Document Control Number: EPA-HQ-OAR-2002-0058-2765.1

Comment Excerpt Number: 16

Comment: Duke Energy Urges EPA to Revise the Requirements for Subsequent Performances 

Tests in 63.7515 

EPA has proposed the establishment of requirements for subsequent testing that allow a reduced 

testing frequency under certain conditions. While Duke Energy agrees that sources should be 

able to perform certain tests on a reduced frequency, it believes that EPA is overly restrictive in 

two areas and should make changes. First, EPA has not extended the option for reduced testing 

frequency to dioxin and furans. EPA has offered no justification for this discrepancy and Duke 

Energy believes that the dioxin/furan testing frequency should be allowed to be reduced along 

with the other pollutants. Duke Energy also believes that the requirements for extended testing 

frequency should not be that the unit demonstrating 75% of the standard. Rather it recommends 

that the unit pass either two test in a row, or one test by no more than 90% of the standard. EPA 

has also not addressed the issue of how a limit of detection is handled in the context of reduced 

testing frequency. 

Response: EPA disagrees, and notes that the intent of this provision is to provide an incentive 

for better performers. By specifying the less than 75 percent of the emission standard margin, 

we are providing such an incentive for good performance, and not rewarding units that just 

barely meet the standard for a pollutant. We have eliminated the requirement for annual testing 

of dioxin/furan emissions.

Commenter Name: John Hopewell

Commenter Affiliation: American Coatings Association

Document Control Number: EPA-HQ-OAR-2002-0058-2886.1

Comment Excerpt Number: 19

Comment: EPA should remove the discount factor for qualifying for a reduced testing 

frequency and allow dioxin to have the reduce d testing frequency requirement. 

Response: EPA disagrees, and notes that the intent of this provision is to provide an incentive 

for better performers. By specifying the less than 75 percent of the emission standard margin, 

we are providing such an incentive for good performance, and not rewarding units that just 

barely meet the standard for a pollutant. We have eliminated the requirement for annual testing 

of dioxin/furan emissions.

Commenter Name: Russ A. Wozniak

Commenter Affiliation: Dow Chemical Company

Document Control Number: EPA-HQ-OAR-2002-0058-2632.1

Comment Excerpt Number: 41
288

Comment: EPA provides no justification for requiring that three sequential retests achieve 75% 

of allowable emission limit to reduce to a three year retesting cycle. EPA has already, through 

the MACT floor process, attempted to set the emission limit at the level of the best performing 

facilities. EPA has yet to demonstrate that any one facility can simultaneously meet all the 

emission limits much less achieve emission rates 25% below the proposed emission limits. 

Requiring that a facility must be repeatedly 25% below the emissions of the best-of-the-best has 

no statistical or rational basis. 

Dow suggests that EPA’s final rule drop entirely the requirement to repetitively achieve 75% of 

the emission limits to allow for a reduction in retesting frequency and establish retesting 

requirements similar to those referenced above in the Hazardous Waste Combustion MACT (i.e., 

re-testing after 5 years). 

Response: EPA disagrees, and notes that the intent of this provision is to provide an incentive 

for better performers. By specifying the less than 75 percent of the emission standard margin, 

we are providing such an incentive for good performance, and not rewarding units that just 

barely meet the standard for a pollutant. We have eliminated the requirement for annual testing 

of dioxin/furan emissions.

Commenter Name: William O'Sullivan

Commenter Affiliation: New Jersey Department of Environmental Protection

Document Control Number: EPA-HQ-OAR-2002-0058-2969.1

Comment Excerpt Number: 6

Comment: We recommend that stack testing and fuel analyses frequency be different for light 

oil 

and residual No 4, 5 or 6 fuel oil) oil. Light oil has a more consistent formulation than 

heavy oil. Chlorine, particulate, and mercury emissions would be very tow for ultra low sulfur #2 

oil with 15 ppm sulfur. The proposed annual stack testing or monthly fuel oil analysis is 

unnecessary for light oil, The testing schedule in the proposed rule is appropriate for heavy oil. 

Response: A monthly frequency provides assurance of continuous compliance with the 

emission limits and an annual testing frequency is consistent with several other NESHAP 

standards. EPA has provided provisions for skip testing at units that consistently demonstrate 

compliance below 75 percent of the applicable emission limit and this provision is expected to 

provided reduced compliance burden to low emitting sources such as ultra low sulfur fuel oil.

Commenter Name: Barry Christensen

Commenter Affiliation: Occidental Chemical Corp

Document Control Number: EPA-HQ-OAR-2002-0058-2848.1

Comment Excerpt Number: 10
289

Comment: Proposed annual stack sampling frequencies are too frequent. The requirement to 

repeat stack tests any more frequently than once every five years is excessive. Such tests are very 

complex, time-consuming and costly. The proposed rule requirement to establish parametric 

monitoring limitations for control equipment will be sufficient to ensure emissions are 

consistently controlled within applicable limitations. 

Response: For the operations and facilities subject to the rule, we believe that the combination 

of periodic compliance emissions testing and continuous monitoring of operational and 

parametric control measure conditions is appropriate for assuring ongoing compliance. Without 

recurring testing, we would have no way to know if parameter ranges established during initial 

performance testing remained viable in the future. Note that annual testing for dioxin/furan 

emissions is not required under the final rule. 

Commenter Name: Gary W. Kruger

Commenter Affiliation: Morton Salt

Document Control Number: EPA-HQ-OAR-2002-0058-2883.1

Comment Excerpt Number: 12

Comment: We disagree with EPA’s statement in the preamble to the proposed rule that the 

proposed compliance requirements ensure compliance with the proposed rule without imposing a 

significant burden for facilities that must implement them. 75 FR 32,033. The proposed 

performance testing requirements are excessive and do pose a significant burden on sources. 

This frequency of testing is too aggressive and is not consistent with other MACT and NSPS 

standards as well as other state performance testing requirements contained in major source Title 

V permits. As an example, the Hazardous Waste Combustor MACT (Subpart EEE) requires a 

comprehensive performance test only once every 5 years. Many other MACT standards and 

NSPS standards only require one initial performance test, unless there is a physical change to the 

control device. 

Response: See the response to EPA-HQ-OAR-2002-0058-2848.1, Comment Excerpt Number: 

10.

Commenter Name: Lee B. Zeugin

Commenter Affiliation: Utility Air Regulatory Group

Document Control Number: EPA-HQ-OAR-2002-0058-2880.1

Comment Excerpt Number: 22

Comment: UARG agrees performance testing should not be required any more frequently than 

annually, and supports inclusion of a reduced testing provision. However, UARG does not 

believe that the 75 percent criterion (or a 90 percent criterion) is reasonable given the extremely 
290

low levels of EPA’s proposed limits. UARG requests that EPA remove this restriction, which 

EPA did not deem necessary in the 2004 rule. EPA has provided no reason for this restriction, or 

data suggesting that any source could achieve 75 percent (or even 90 percent) of the proposed 

emission limits, some of which are established at or near the detection limit. UARG does not 

understand how a source could test at a percent of the detection limit. The requirement that 

source and control device operation remain consistent with prior successful testing should be 

sufficient to ensure representativeness of the prior test(s). 

Response: EPA disagrees, and notes that the intent of this provision is to provide an incentive 

for better performers. By specifying the less than 75 percent of the emission standard margin, 

we are providing such an incentive for good performance, and not rewarding units that just 

barely meet the standard for a pollutant. We have eliminated the requirement for annual testing 

of dioxin/furan emissions.

Commenter Name: Lee B. Zeugin

Commenter Affiliation: Utility Air Regulatory Group

Document Control Number: EPA-HQ-OAR-2002-0058-2880.1

Comment Excerpt Number: 25

Comment: Under proposed § 63.7515, stack testing for D/F must be conducted annually without 

exception. Although EPA does not explain its logic, UARG assumes that EPA proposed annual 

testing for D/F to be consistent with the annual frequency proposed for other pollutants and did 

not provide a reduced testing option for D/F out of concern that the proposed rule does not 

provide any operating limits directly associated with D/F control in between stack tests. 

The lack of continuous operating limits does not necessarily mean that annual testing should be 

required. D/F differs from the other pollutants covered by the rule in several respects. First, few 

sources are likely to use controls to meet the proposed standard. As a result, the lack of control 

device operating limits is not a reason to require more frequent testing. Moreover, since there are 

no clear actions sources can take to address failed D/F test results, sources that fail a test are 

likely to achieve the standard simply by retesting. Second, D/F emissions are very low and there 

is no clear explanation for the differences in test results between units other than limitations in 

the ability to measure D/F at those low levels. Emissions are so low that EPA set the proposed 

emission limits near the detection level for the method (Method 23) and below the level at which 

D/F emissions can be accurately quantified. Method 23 samples also are easily affected by 

contamination. See, e.g., Method 23, § 4.2. As a result, differences in test results from year to 

year are just as likely to be the result of measurement issues as changes in actual emissions. 

Third, D/F testing is very expensive and there are only a limited number of laboratories qualified 

to perform the sample analysis. According to EPA’s cost analysis the costs of D/F stack testing 

may range from $15,000 to $50,000.[ Memorandum, “Methodology for Estimating Control 

Costs for Industrial, Commercial, Institutional Boilers and Process Heaters National Emission 

Standards for Hazardous Air Pollutants -- Major Source” (Apr. 2010), EPA-HQ-OAR-2002-

0058-0803, Appendix J-1. In the EGU ICR, EPA assumed a cost of $42,000, Supporting 
291

Statement for Review of EPA ICR No. 2362.01 (Dec. 24, 2009), EPA-HQ-OAR-2009-0234-

0102, Attachment 2.] 

Given all of these factors, UARG questions the point of annual testing at all, let alone 

disallowing use of the reduced testing provision. EPA’s proposed rule already requires source 

owners/operators to confirm that there are no changes in the operation of the affected unit or 

control equipment that could increase emissions. Proposed § 63.7550(c)(5). Unless EPA can 

identify some other factor that could influence D/F emissions, EPA should allow such tests to 

qualify for reduced testing under § 75.15(c) and should consider simply mandating biennial or 

triennial testing for all units. At a minimum since most of the ICR results were below the 

detection limit, EPA should provide for triennial stack testing for any unit that produces all nondetects. 

Response: Annual testing for dioxin/furan emissions is not required under the final rule.

Commenter Name: Bill Wemhoff

Commenter Affiliation: National Rural Electric Cooperative Association

Document Control Number: EPA-HQ-OAR-2002-0058-2835.1

Comment Excerpt Number: 27

Comment: NRECA also supports EPA’s proposal for reduced periodic testing, but objects to the 

restrictions EPA would impose. 

Response: See the response to EPA-HQ-OAR-2002-0058-2882.1, Comment Excerpt Number 9. 

Also, the final rule does not require annual testing for dioxin/furan emissions.

Commenter Name: David O'Keefe

Commenter Affiliation: USEC, Inc

Document Control Number: EPA-HQ-OAR-2002-0058-3122

Comment Excerpt Number: 30

Comment: Subsequent §63.7515 performance tests.The cost of stack testing will increase 

substantially under the proposed rule. Additional pollutants and more frequent 

testing mean additional costs. Under the new Boiler MACT, testing will be annual 

for at least the first three years, then every three years as long as certain conditions are met, 

including a requirement that each test result be less than or equal to 75% of the limit. Many 

facilities will not likely meet those conditions and will be forced to conduct annual stack testing 

for the remainder of the operating life of the unit(s) at significantly higher costs. 

The 75 percent threshold for conducting stack tests less often should be increased to 90 percent 

of the limit. The rationale for setting the threshold at 75 percent is not apparent.Setting the 

threshold at 90 percent would be statistically justified since the proposal includes variability in 

setting the emission standards, emission averaging, and in calculating uncertainty in fuel 
292

analysis. Additionally the initial performance test provides assurance through the establishment 

of operating parameters that the emission limits are not exceeded. The longer test times during 

initial performance testing from historic practices ensures established operating parameters 

account for variability in emissions. The three consecutive year time period requirement further 

lessens the likelihood emission limits are exceeded during the years when emission testing is not 

conducted. 

Response: EPA disagrees, and notes that the intent of this provision is to provide an incentive 

for better performers. By specifying the less than 75 percent of the emission standard margin, 

we are providing such an incentive for good performance, and not rewarding units that just 

barely meet the standard for a pollutant. We have eliminated the requirement for annual testing 

of dioxin/furan emissions.

Commenter Name: Jim Griffin

Commenter Affiliation: American Chemistry Council

Document Control Number: EPA-HQ-OAR-2002-0058-2792.1

Comment Excerpt Number: 194

Comment: EPA Should Remove The Discount Factor For Qualifying For A Reduced Testing 

Frequency And Allow Dioxin To Have The Reduced Testing Frequency Requirement. Proposed 

section 63.7515 (a) requires annual emissions testing (once every 10 to 12 months), with only a 

limited option for reduced testing frequency in section 63.7515(b). The reduced testing 

frequency is not proposed for dioxin/furan or for facilities using emissions averaging, and 

emissions of the other regulated pollutants must be below 75% of the applicable emission limit 

to qualify for testing every 3 years. We do not believe these restrictions are justified, and as 

stated above, we believe that testing should be on a 5-year frequency. The proposed rule requires 

continuous monitoring of operating parameters and fuel input that are meant to provide an 

ongoing assurance of compliance with the emission limits. As long as the facility continues to 

operate in a similar mode following the initial performance test and maintains operating 

parameters and fuel inputs within the established operating ranges, annual stack testing for all 

pollutants is not necessary. As the dioxin/furan testing is the most expensive testing requirement, 

this will be a significant annual cost for facilities. In addition, there is no basis provided for 

including the requirement that emissions during 3 consecutive stack tests be less than 75% of the 

emission limit in order to qualify for a reduced testing frequency. Therefore, we believe that the 

rule should allow testing every 5 years for all pollutants as long as facilities are meeting the 

emission and operating parameter limits and have not made operational or air pollution control 

changes that could increase emissions above the limits. 

Response: EPA disagrees, and notes that the intent of this provision is to provide an incentive 

for better performers. By specifying the less than 75 percent of the emission standard margin, 

we are providing such an incentive for good performance, and not rewarding units that just 

barely meet the standard for a pollutant. We have eliminated the requirement for annual testing 

of dioxin/furan emissions.
293

Commenter Name: Kirby D. Juntila

Commenter Affiliation: Marquette Board of Light and Power

Document Control Number: EPA-HQ-OAR-2002-0058-3175

Comment Excerpt Number: 2

Comment: The original boiler MACT required PM testing on an annual basis. A facility could 

conduct performance tests less often for PM if three consecutive years showed compliance with 

the emission limits. 

The EPA needs to consider allowing units the flexibility to follow the PM requirements in the 

original boiler MACT if they verify that their emissions are equal to or less than 90% of the PM 

emission limit. This provides an incentive and cost justification for facilities to upgrade their 

emission control equipment (i.e. replace older outdated bags in a baghouse with newer modern 

and more efficient bags) rather then spending the money to install, certify, maintain, and operate 

a PM CEMS. Our 264 mmBtu/hr coal fired stoker boiler currently has a PM emission rate of 

approximately 0.016 lbs/mmBtu (less than the new boiler MACT limit). There would be an 

enormous incentive and cost justification for us to invest the capital to upgrade the bags in the 

baghouse to ensure that we maintain and widen the gap between our actual emissions and the 

Boiler MACT PM limit, if the PM conditions in the original boiler MACT are adopted. This 

option results in a net benefit to the environment versus just investing the capital to operate a PM 

CEMS which provides no benefit if a facility is already under the limit. This is the contrast 

between writing a rule that establishes emission limits versus constructing a rule that offers 

incentives to control below the limits. 

Response: EPA disagrees, and notes that the intent of this provision is to provide an incentive 

for better performers. By specifying the less than 75 percent of the emission standard margin, 

we are providing such an incentive for good performance, and not rewarding units that just 

barely meet the standard for a pollutant. We have eliminated the requirement for annual testing 

of dioxin/furan emissions.

Compliance Flexibility for Small Entities

Commenter Name: David A. Buff

Commenter Affiliation: Golder Associates Inc

Document Control Number: EPA-HQ-OAR-2002-0058-2801.1

Comment Excerpt Number: 59

Comment: Should have a provision to be able to test one unit if it is “representative” of multiple 

units (e.g., same size/type/fuel) at facility 
294

Response: EPA disagrees with the commenter. Each and every unit that is part of the affected 

source is subject to an emission limit or work practice standard. From a compliance perspective 

it is too difficult to establish representative criteria given the multiple variables of fuel and 

operations cited by many other commenters.

Commenter Name: Robert D. Bessette

Commenter Affiliation: Council of Industrial Boiler Owners (CIBO)

Document Control Number: EPA-HQ-OAR-2002-0058-2702.1

Comment Excerpt Number: 152

Comment: Finally, we remain concerned about the ability of small businesses to comply with 

the proposed standards within three years. The monetary impact on small businesses will be 

substantial enough to strain their financial well-being. The present sluggish economy simply 

does not provide the financial resources for many of these small companies to take on the 

additional costs of retrofits to meet the proposed MACT standards in three years. More time is 

needed. 

Response: Sources may petition to the Administrator to request a site-specific extension, as 

appropriate.

Commenter Name: Robert D. Bessette

Commenter Affiliation: Council of Industrial Boiler Owners (CIBO)

Document Control Number: EPA-HQ-OAR-2002-0058-2702.1

Comment Excerpt Number: 156

Comment: Given the wide variety of sources impacted by this proposal, it is reasonable to 

provide flexibility in how sources demonstrate compliance, as long as clearly-defined 

compliance objectives are met. CIBO requests that EPA include the compliance schemes 

discussed above in the final rule as allowable optional compliance strategies. We are willing to 

work with the agency to further refine these strategies. Additionally, CIBO requests that the final 

rule include an allowance for a source to use, with prior Agency approval, other compliance 

strategies that may be more appropriate on a site-specific basis. 

Response: EPA has included several compliance alternatives in the final rule. To the extent that 

further alternative compliance strategies are developed in the future, EPA may consider working 

with stakeholders to incorporate additional compliance alternatives as part of the reconsideration.

Commenter Name: Winslow Sargeant

Commenter Affiliation: US Small Business Administration

Document Control Number: EPA-HQ-OAR-2002-0058-2916.1

Comment Excerpt Number: 4
295

Comment: EPA Should Have Minimized Facility Monitoring and Reporting Requirements 

Several SERs noted that recordkeeping activities, as written in the vacated boiler MACT, would 

be especially challenging for small entities that do not have a dedicated environmental affairs 

department. The SERs advocated for the most efficient way to get reductions in HAP and 

requested that the Panel consider all available alternatives to reduce to a bare minimum any 

extraneous requirements that require a lot of paperwork that in the opinion of the SERs do not 

contribute to emission reductions. 

Response: EPA has minimized monitoring and reporting for many sources, but a minimal 

amount of reporting is still required from all sources to demonstrate compliance. EPA expects 

that a majority of small entities affected will benefit from the work practices created for small 

and gas 1 units, which in turn reduces burden on many small entities. For small entities with 

units subject to emission limits, many of the requirements for reporting, monitoring and 

recordkeeping are consistent with the general provisions and are necessary to demonstrate 

continuous compliance.

Commenter Name: Patrick Strauch

Commenter Affiliation: Maine Forest Products Council

Document Control Number: EPA-HQ-OAR-2002-0058-3120.1

Comment Excerpt Number: 7

Comment: Create a best management practices procedure for these smaller facilities that will 

achieve an environmentally friendly standard, while not imposing the significant costs associated 

with the rule as it is currently proposed. 

Response: See response to EPA-HQ-OAR-2002-0058-2916.1, Comment Excerpt Number 4.

Commenter Name: J. Michael Geers

Commenter Affiliation: Duke Energy

Document Control Number: EPA-HQ-OAR-2002-0058-2765.1

Comment Excerpt Number: 29

Comment: Duke Energy remains concerned about the ability of small businesses to comply with 

the proposed standards within three years. EPA identified a variety of small businesses that will 

have to comply with the new rule, many of which will face substantial compliance costs. The 

proposal 75 FR 32045, EPA identified a number of mechanisms such as work practice standards, 

subcategorization, health based compliance options, and emissions averaging that it explains will 

lessen the burden on small businesses. Never the less Duke Energy believes that despite these 

attempts to lessen the financial impacts on small businesses, the ultimate cost to comply with 

Subpart DDDDD will be enormous. They are certainly “significant” within the meaning of the 
296

Regulatory Flexibility Act. The monetary impact on small businesses will be substantial enough 

to strain their financial well being. The present sluggish economy simply does not provide the 

financial resources for many of these small companies to take on the additional costs of retrofits 

to meet the proposed MACT standards in three years. More time and more flexibility are needed. 

Response: See response to EPA-HQ-OAR-2002-0058-2702.1, Comment Except Number 152.

Operating Parameter Monitoring

Commenter Name: Michael L. Steele

Commenter Affiliation: CraftMaster Manufacturing, Inc

Document Control Number: EPA-HQ-OAR-2002-0058-1907.1

Comment Excerpt Number: 10

Comment: Establishing Site-Specific Operating Limits § 63.7530 

The proposed rules specify that the heat input for each fuel must be measured in the time frame 

of a stack test. This is not possible in all cases. Provisions for alternate, site-specific approaches 

should be provided for in the rules. 

Response: If there are particular cases where this generally applicable approach presents a 

technical challenge for a specific source, then the owner/operator may submit an alternative 

monitoring request in accordance with the general provisions in Part 63. EPA does not believe 

that any global change is appropriate based on the general concerns identified by the commenter.
297

Commenter Name: Michael L. Steele

Commenter Affiliation: CraftMaster Manufacturing, Inc

Document Control Number: EPA-HQ-OAR-2002-0058-1907.1

Comment Excerpt Number: 37

Comment: Monitor Calibrations §63.7525 

The proposed rules specify in paragraph (e) that flow measurement devices shall undergo a 

calibration check at least semi-annually. The calibration frequency should be per manufacturer’s 

specifications. 

In paragraph (f)(4) "a pressure monitor shall be checked for pressure tap pluggage daily." We 

request this be revised to "when a deviation from normal is indicated." 

In paragraph (f)(5) , IIcheck a pressure gauge calibration quarterly using a monometer and 

transducer calibration monthly." The calibration method and frequency should be per 

manufacturer’s specifications. 

In paragraph (g), "check pH meters calibration every 8 hours." The calibration frequency should 

be per manufacturer’s specifications. 

Response: EPA received many comments that suggested that the calibration procedures were 

too specific and/or too stringent. The comments suggested using the site-specific plan to set 

these limits, following manufacturer specifications, or using other options for reducing the 

stringency of parameter monitoring QA/QC requirements. In the final rule, the source must 

prepare a site-specific monitoring plan which identifies the QA/QC procedures the source will 

follow, and calls generally for a daily performance evaluation of some form for most monitoring 

devices as a basic QC check. For example, the method for checking for pressure obstructions is 

not prescribed in the rule. This is a basic quality control check that can be fulfilled in many of the 

ways that commenters have described (such as by looking for lack of changes in the data). The 

specific method that the source will use to fulfill this QC check can be developed in conjunction 

with the site's monitoring plan. Calibrating with a manometer is not necessary as part of this 

basic check. In addition, the pH meter check language has been modified to call for a daily 

performance evaluation, and not a two point calibration. With respect to some of these

commenter's other points that objected completely to the proposed QA/QC provisions, EPA 

contends that, as finalized, the monitoring, recordkeeping, and reporting requirements of the rule 

are the minimum necessary to determine continuous compliance and are not overly burdensome. 

The requirements are generally consistent with the NESHAP general provisions and are 

reasonably consistent with other NESHAPs. The monitoring systems require periodic inspection, 

maintenance, and calibration to ensure continued accuracy. The EPA believes the proposed 

requirements for ensuring data quality and for site-specific monitoring plans (where applicable) 

are reasonable and contends that the information required in the site-specific monitoring plans is 

necessary for regulators to ensure that the monitoring equipment are properly installed and 

maintained. The required information provides a written record of the calibration, maintenance, 

data quality, and recordkeeping and reporting procedures to be followed by the facility. EPA also 
298

notes that owners / operators can always seek approval for site-specific monitoring. This could 

include, as some commenters noted, requesting alternative calibration frequencies using 

consensus-based approaches that can require fairly sophisticated analyses of past experience and 

failure rates. The Agency also believes that owners / operators can develop procedures to 

calibrate parameter measurements without causing safety or environmental release incidents. 

Commenter Name: Mark Denzler

Commenter Affiliation: Illinois Manufacturers' Association

Document Control Number: EPA-HQ-OAR-2002-0058-2635.1

Comment Excerpt Number: 5

Comment: Performance Test Operating Parameter Limits Are Inappropriate. EPA is proposing 

that the operating parameters measured during performance tests must be used to represent the 

minimum site-specific operating requirements for use subsequent to the performance test. Such 

an operating limit would be unmanageable long-term as it would require 

exact replication of the test fuel. It is not always feasible or appropriate to use operating 

conditions during a performance test to establish a minimum requirement for all possible load 

ranges especially considering that the performance tests are often performed at the unit’s 

maximum firing rate.. 

Response: We believe that continuous monitoring is needed to ensure ongoing compliance with 

this rule. In order to minimize costs, we look for parameters that are already monitored to use for 

compliance demonstration. Operating limits are not direct measures of emissions, but provide 

measure of fuel characteristics and control device performance. We require performance tests to 

demonstrate compliance with emission limits, and then use operating limits to ensure the source 

is operating similarly to how it was operating when it completed a successful performance test.

Under the final rule, we clarify that tests are to be performed under representative operating 

conditions. Also in response to comments, EPA reviewed the proposed procedure for 

establishing the operating parameter limits (i.e., calculated as the average of three test runs and 

as 90 percent of the average value recorded during the applicable performance tests) and 

concluded that it may be too restrictive on control device operations in terms of energy or other 

operating needs. We determined that the operating limits should be more appropriately based on 

values recorded during the performance test runs. The final rule requires that operating limits be 

established on a site-specific basis as the minimum (or maximum, as appropriate) operating 

parameter value measured over a single test run during the performance test. This approach has 

been incorporated into the final rule for all applicable operating parameters and will result in 

achievable operating ranges that will ensure that the control devices used for compliance will be 

operated to achieve continuous compliance with the emissions limits.

We have also provided for scaling certain parameters such as sorbent injection rate based on the 

operating load, to address load conditions that are less than those that occur during testing. In 

addition, we modified and simplified opacity limits, fuel sampling/testing requirements, and are 
299

allowing emission averaging. You are also able to petition the Administrator for approval of an 

alternative monitoring plan under section §63.8(f) of subpart A of part 63.

Commenter Name: Peter Zalzal

Commenter Affiliation: Environmental Defense Fund

Document Control Number: EPA-HQ-OAR-2002-0058-2869.1

Comment Excerpt Number: 5

Comment: Allowing affected sources to demonstrate continuous compliance based solely on 

operating parameter monitoring likewise fails to account for coal-mercury content variations. 

EPA itself has recognized the limitations of parameter monitoring and fuel-content analysis in 

providing accurate mercury emissions data. In its recently-finalized Portland Cement MACT, for 

instance, EPA requires facilities to monitor mercury emissions using either mercury CEMS or a 

sorbent trap. In its response to comments, EPA rejects input monitoring, concluding it is an 

inaccurate way of capturing mercury emissions. The Agency found that “short term test data do 

not necessarily reflect the long term emissions,” and that “the performance of the available 

mercury controls may be significantly affected by operational factors.” [Footnote: National 

Emission Standards for Hazardous Air Pollutants From the Portland Cement Manufacturing 

Industry and Standards of Performance for Portland Cement Plants, 40 CFR Parts 60, 63 at p. 

198 [hereinafter Portland Cement MACT]] As such, EPA concluded that it “would be difficult to 

establish the proper control device operating parameters and operating limits,” and as a result, 

“mercury CEMS are essential in demonstrating continuous compliance with the mercury 

emissions limits.”. [Footnote: Portland Cement MACT] EPA has recognized the limited 

accuracy of parameter monitoring and fuel analysis and should not allow sources to rely on it 

here in lieu of advanced mercury monitoring systems. 

Response: For the operations and facilities subject to the rule, we believe that the combination 

of periodic compliance emissions testing and continuous monitoring of operational and 

parametric control measure conditions is appropriate for assuring ongoing compliance. Using 

the alternative monitoring procedures of the general provisions, the rule allows a source owner or 

operator to install and operate CEMS in lieu of some testing and parametric monitoring 

requirements. This process requires source owners to propose site-specific monitoring plans for 

approval. These plans would include CEMS PS and periodic QA/QC steps to assure the quality 

of the alternative monitoring data. Currently, EPA has the requisite CEMS PS for Hg 

monitoring systems. 

Commenter Name: Robin Mills Ridgway

Commenter Affiliation: Purdue University

Document Control Number: EPA-HQ-OAR-2002-0058-2782.1

Comment Excerpt Number: 8
300

Comment: Inflexibility in operating limits will cause equipment operation problems at varying 

loads. 

§63.7530, Table 4 and Table 7 of the proposed rule require that the minimum sorbent injection 

rate be established during the compliance stack tests. Purdue University requests that EPA allow 

the rate to be established so that it is scalable at varying operating loads. For example, an 

injection rate in units of lb sorbent/ton coal established at high loads may not be appropriate for 

lower operating loads, and may, in fact, hinder the proper operation of the unit as the sorbent in a 

circulating fluidized bed boiler serves the dual purpose of pollution control and fluidization 

media for efficient combustion. 

Response: Table 7 provides for scaling the rate based on operating loads.

Commenter Name: Steven M. Maruszewski

Commenter Affiliation: The Pennsylvania State University

Document Control Number: EPA-HQ-OAR-2002-0058-2729.1

Comment Excerpt Number: 16

Comment: Operating limits - Sorbent injection rate 

Establishing a set-point minimum injection rate based on stack testing at 100-110% of the 

maximum operating capability is not environmentally responsible nor, in many cases, technically 

feasible. Sorbent injection rates are determined by the volume of flue gas at a given operating 

load. The University stack tests at a combustion rate of 400-425 MMBtu/hour with a flue gas 

volume in excess of 6.6 million standard cubic feet per hour. Under these conditions, the 

University generates over 300,000 pounds of steam per hour. The normal injection rate for 

carbon, to capture mercury, is 6-8 pounds per million standard cubic feet of flue gas flow. At that 

concentration, the University would have a set-point minimum injection rate of 40-53 pounds of 

carbon for every hour of operation. The boilers average operating load is less than one third of 

the load at testing. On average, the University will be injecting three times the amount of carbon 

as needed with no environmental or health benefits. This scenario is true for lime/trona injection 

as well. Should Spray Dryer Absorber technology be selected, this method of establishing the 

minimum injection rate would lead to a system failure. Establishing the injection rate when the 

system temperatures and effluent flow rate are maximized will lead to more material being 

injected at lower operating rates than the flue gas can evaporate. This imbalance may lead to 

system failures. 

The University suggests that the Administrator adopt variable injection rates across the operating 

range that are tied to steam flow or heat input. In this way, little material is wasted and facilities 

will not have to stack test over the range of operation. 

Response: Table 7 provides for scaling the rate based on operating loads.

Commenter Name: Stephen R. Gossett

Commenter Affiliation: Eastman Chemical Company
301

Document Control Number: EPA-HQ-OAR-2002-0058-3137.1

Comment Excerpt Number: 59

Comment: SO2 CEMS data demonstrating removal of SO2 should be allowed to be used to 

demonstrate compliance with the HCl emission standard. 

Eastman operates two coal-fired boilers equipped with spray dryer absorbers (SDAs) to comply 

with SO2 emission rates. Since HCl is easier to absorb than SO2, if a unit is achieving significant 

SO2 removal, it can be concluded that HCl is being removed at an even higher efficiency. The 

results of the 2009 ICR Phase II performance test conducted on Eastman’s Boiler 30 illustrate 

this relationship between SO2 removal and HCl removal very well. The SO2 removal during this 

test was 77 percent whereas no HCl was detected and an HCl removal efficiency is estimated at 

99.4 percent assuming HCl was present at detection limits. In a case like this, a SO2 CEMS is a 

very good indicator of HCl removal and should be allowed to be used in lieu of scrubber 

parameter monitoring. As discussed elsewhere in these comments, EPA’s proposal to require 

sorbent input rates to an SDA to meet or exceed the rates demonstrated in the performance test 

will be problematic and could result in a waste of sorbent. 

Response: Section 63.7500(a) allows for seeking an alternative monitoring approach pursuant to 

the Part 63 general provisions and establishment of an appropriate operating limit for the 

alternative parameter. Assuming an effective demonstration, the situation described by the 

commenter may be an appropriate example of applying that authority.

Commenter Name: Stephen R. Gossett

Commenter Affiliation: Eastman Chemical Company

Document Control Number: EPA-HQ-OAR-2002-0058-3137.1

Comment Excerpt Number: 61

Comment: Setting operating limits solely on data gathered during performance tests is 

impractical. EPA should allow use of supplemental information to set operating limits. 

EPA has proposed that operating parameters (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 on operating levels for the parameters 

measured during the most recent performance test. 

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. 

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 
302

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 Figures 14 and 15). 

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. 

Response: See the response to EPA-HQ-OAR-2002-0058-2635.1, Comment Excerpt Number 5.

Commenter Name: Stephen R. Gossett

Commenter Affiliation: Eastman Chemical Company

Document Control Number: EPA-HQ-OAR-2002-0058-3137.1

Comment Excerpt Number: 65

Comment: The averaging time for continuous parametric monitoring systems should be changed 

to 24 hour block averages. 
303

EPA has proposed operating parameters of 12-hour block average based on 4-hour averages (see 

75 FR 32033). Eastman recommends that EPA adopt instead a 24-hour rolling average for 

operating parameters. This will allow for normal operating fluctuations and slower emissions 

response to operating parameter changes and startup/shutdown periods. The HON uses 24-hour 

block average for chemical processes that typically do not vary greatly due to throughput or 

firing rate. This generally occurs for boilers where the additional latitude of a rolling average is 

more appropriate. If EPA does not determine the 24-hour rolling average is appropriate, 

Eaastman proposes a 24-hour block average, and alternatively, a 12-hour rolling average. 

Furthermore, the Proposed Rule is inconsistent in the averaging times specified for operating 

parameters. EPA should amend § 63.7525(d)(4), which currently references 3-hour block 

averages, so that it reflects what is stated in Table 8 75 FR 32056, 32072 

Response: EPA has retained the 12-hour block averages as appropriate for ensuring continued 

compliance. The incorrect reference has been corrected in the final rule.

Commenter Name: Timothy Hunt

Commenter Affiliation: American Forest and Paper Association (AF&PA)

Document Control Number: EPA-HQ-OAR-2002-0058-3213.1

Comment Excerpt Number: 292

Comment: CPMS Calibration Requirements 

Quality Assurance (QA) procedures for Continuous Parameter Monitoring Systems (CPMS) are 

best defined and implemented by the owner/operator of each CPMS. Preventative maintenance 

and sensor calibration for both process and control device monitoring is oftentimes accomplished 

during an annual outage, with some sensors only needing calibration once every 5 years. We 

believe that a more appropriate requirement is for sources to develop site-specific CPMS QA 

plans that are self implemented and maintained on site for inspections and audits. Utilizing 

facility specific information to develop a QA Plan will ensure that unnecessary and arbitrary 

calibration frequencies do not result in either a potential safety incident or environmental 

releases during the accuracy audits. 

Today’s state of the art sensors and electronic transmitters, power supplies, etc. do not require 

the repeated checks and inspections proposed. In addition, newer digital communications 

technologies, such as Foundation Fieldbus and HART technologies, can incorporate advanced 

sensor diagnostics, reducing the need for labor intensive field inspections. Facilities have learned 

through experience what sensors and CPMS system components perform best in their 

environment. 

The establishment of fixed calibration intervals, as EPA proposes, is contrary to standard 

metrology practice. NCSL International, an ANSI-accredited consensus standards developer for 

metrology standards, has a long-established Recommended Practice for determination of 

appropriate calibration intervals for measurement systems. This Practice recognizes that 

calibration intervals need not (in fact, must not) be set at arbitrary, fixed intervals to achieve 

acceptable data quality. The National Institute of Standards and Technology, the U.S. 

government agency concerned with the quality and reliability of measurement data, does not 

require fixed calibration intervals. Other U.S. government agencies such as NASA also do not 
304

require fixed calibration intervals. Acceptable calibration intervals are based on past experience 

and failure rates. Using this approach, calibration intervals can be determined that provide the 

required data quality at the least cost. This reliance on fixed interval QA/QC checks seems to be 

a remnant of the Agency‘s initial promulgation of Appendix F about a quarter century ago. At 

that time, Appendix F applied to CEMS – a fairly new technology at that time. Many of these 

early instruments suffered from drift, non-linearity, and other performance issues that required 

frequent checks. Computerized control was virtually unknown. Today‘s instruments are 

generations away from those early CEMS. They are relatively stable, rugged, and reliable. EPA 

should develop a QA/QC rule that acknowledges the complex instruments in use today. 

The QA/QC process is not intended to detect failures. In most cases, failure of a sensor or other 

measurement system component is immediately recognizable in the data itself. One knows that a 

thermocouple has failed if the thermal oxidizer is operating and the temperature is reported as -

20 °F. One does not need a QA/QC check to detect the failure. The QA/QC process is designed 

to correct drift, biases, and other more subtle data quality issues. Most of the reliability issues 

that the QA/QC process is designed to correct are known and predictable and therefore can be 

taken into account when establishing calibration intervals. 

A flexible calibration interval does not imply an arbitrary calibration interval. Proper calibration 

intervals are established by experience. This experience may come from other systems installed 

at the source, from known failure rates of system components, from vendors, or from 

installations at similar facilities. Also, initial calibration intervals are not fixed, they are adjusted 

based (again) on experience. If a system on a yearly check cycle is failing, that cycle should be 

pushed back to once every six months (for example). If a system is consistently passing a sixmonth QA/QC check, that check may be pushed to annual. 

Response: See the response to EPA-HQ-OAR-2002-0058-1907.1, Comment Excerpt Number 

37.

Commenter Name: Timothy Hunt

Commenter Affiliation: American Forest and Paper Association (AF&PA)

Document Control Number: EPA-HQ-OAR-2002-0058-3213.1

Comment Excerpt Number: 293

Comment: Semi-annual flow sensor calibration check 

Some flow sensors only need calibration once every 5 years and some flow meters are calibrated 

by the manufacturer and cannot be calibrated in the field. For Emerson Micro Motion flow tubes, 

there is nothing to wear or break, so frequent calibration is not needed. Calibration is only 

accomplished by removing the flow tube and sending it offsite, so this can only be done during a 

scheduled shutdown of a unit, which does not typically happen on a semi-annual basis. 

Recalibrations should be done at the unit’s normal maintenance shutdown frequency since 

electronic flow sensors do not drift and it may not be possible to take devices out of service for 

calibration without adversely affecting operation. 

Historical calibration data has proven that the manufacturer’s recommended frequencies for 

calibration are more than adequate to ensure accuracy. For example, many facilities have flow 
305

meters manufactured by Rosemount, a recognized global leader in manufacturing process 

instrumentation. Per Rosemount’s documentation the annual stability of those flow meters are 

+/- 0.2% per year. Rosemount recommends that these instruments be calibrated at least once 

every 5 years. 

Response: See the response to EPA-HQ-OAR-2002-0058-1907.1, Comment Excerpt Number 

37.

Commenter Name: Timothy Hunt

Commenter Affiliation: American Forest and Paper Association (AF&PA)

Document Control Number: EPA-HQ-OAR-2002-0058-3213.1

Comment Excerpt Number: 294

Comment: Check pressure tap pluggage daily; Using a manometer, check pressure gauge 

calibration quarterly and transducer calibration monthly. 

These are extremely onerous requirements and do not reflect common practice or experience in 

industrial applications. Electronic devices experience very little drift, and calibrations at least 

annually would be more than adequate unless specific applications are shown to experience 

problems. Some pressure sensors only need calibration once every 5 years. OSHA considers 

annual testing of instrumentation to be adequate for most critical safety interlock applications. 

There is no reason to calibrate (audit and inspect) CPMS systems 4-12 times as often. Even the 

CEM performance specifications do not require inspections and calibrations as often as the 

proposed rule. 

Response: See the response to EPA-HQ-OAR-2002-0058-1907.1, Comment Excerpt Number 

37.

Commenter Name: Timothy Hunt

Commenter Affiliation: American Forest and Paper Association (AF&PA)

Document Control Number: EPA-HQ-OAR-2002-0058-3213.1

Comment Excerpt Number: 295

Comment: Conduct calibration checks any time the sensor exceeds the manufacturer’s specified

maximum operating pressure range or install a new pressure sensor. 

We believe that this requirement is not justified. Calibration or replacement should only be 

required if the instrument’s reading is suspect. 

Response: See the response to EPA-HQ-OAR-2002-0058-1907.1, Comment Excerpt Number 

37.
306

Commenter Name: Timothy Hunt

Commenter Affiliation: American Forest and Paper Association (AF&PA)

Document Control Number: EPA-HQ-OAR-2002-0058-3213.1

Comment Excerpt Number: 296

Comment: Check the pH meter’s calibration on at least two points every 8 hours of process 

operation. 

The length of time to check the calibration of a pH meter is entirely site specific. The proposed 

frequency is excessive, as most facilities calibrate pH meters weekly, especially if they are not 

exposed to a corrosive environment. One set frequency for all instruments regardless of the 

sophistication of the instrument and regardless of the service environment for the instrument is 

not appropriate. In other words, one size does not fit all. Autocalibration systems are available 

for around $30,000 per application, which adds to the already significant control, testing, and 

monitoring costs for this rule if this requirement is retained. 

EPA should allow facilities to establish site-specific QA/QC plans for CPMS that take their 

specific operating conditions into account and establish the appropriate inspection and 

calibration intervals for each type of monitoring device. 

Response: See the response to EPA-HQ-OAR-2002-0058-1907.1, Comment Excerpt Number 

37.

Commenter Name: Timothy Hunt

Commenter Affiliation: American Forest and Paper Association (AF&PA)

Document Control Number: EPA-HQ-OAR-2002-0058-3213.1

Comment Excerpt Number: 299

Comment: Facilities need more flexibility in development of operating parameter limits. 

The proposed rule requires development of operating parameter limits based on the values 

achieved during the performance test. In many cases, these levels will be appropriate only for 

certain modes of operation. For example, the absolute sorbent injection rate observed during the 

performance test conducted under full load will not correlate to the sorbent injection rate 

necessary during startup or periods of lower load. Frequently, sorbent injection rates are set using 

a feedback loop from a CEMS or CPMS to avoid wasting sorbent. EPA should allow affected 

sources to adopt flexible parametric limits such that the limit can vary according to relevant 

operating conditions. Affected sources should be able to use all credible and available 

information in setting such limits, including performance testing over a range of conditions as 

well as engineering, scientific, and process information. Requiring the use of "one size fits all 

conditions" parametric limits is arbitrary because such limits necessarily would require overcompliance with standards when affected sources operate under less rigorous conditions than 

those used for compliance testing. 
307

Response: See the response to EPA-HQ-OAR-2002-0058-2635.1,Comment Excerpt Number 5.

Commenter Name: Timothy Hunt

Commenter Affiliation: American Forest and Paper Association (AF&PA)

Document Control Number: EPA-HQ-OAR-2002-0058-3213.1

Comment Excerpt Number: 301

Comment: We are concerned that each performance test will ratchet down operating parameter 

limits. 

We are concerned that the ongoing testing requirements in the rule will result in a continual 

ratcheting down of operating parameter 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 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, Subpart EEE for Hazardous Waste Combustors, 

allow for a waiver of the operating limits during stack testing (see 63.1207(h)) and we believe 

this should be allowed under this rule. 

Response: 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 

emission 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 tests with less stringent operating levels than may have been initially 

determined, the source will be able to set the limits at levels appropriate for their operations 

while ensuring emission limits are met.

Commenter Name: Timothy Hunt

Commenter Affiliation: American Forest and Paper Association (AF&PA)

Document Control Number: EPA-HQ-OAR-2002-0058-3213.1

Comment Excerpt Number: 303

Comment: For sources using SO2 CEMS that have acid gas controls, scrubber parameter 

monitoring would not be necessary if the control device captures both HCl and SO2. Low SO2 

would indicate low HCl emissions, so the SO2 concentration could be used as a surrogate 

parameter to ensure compliance with the HCl emission limit. For sources using HCl CEMS, 

scrubber parameter monitoring should not be required. 
308

Response: See the response to EPA-HQ-OAR-2002-0058-3137.1, Comment Excerpt Number 

59. 

Commenter Name: Robert D. Bessette

Commenter Affiliation: Council of Industrial Boiler Owners (CIBO)

Document Control Number: EPA-HQ-OAR-2002-0058-2702.1

Comment Excerpt Number: 113

Comment: Continuous Parameter Monitoring System Maintenance Procedures. 

EPA has proposed that the continuous parameter monitoring system (CPMS) complete a 

minimum of "one cycle of operation for each successive 15-minute period" and have a minimum 

of "four successive cycles of operation" for a valid hour of data. 75 FR 32056. This requirement 

could result in certain units that do not currently have CEMS installed being forced out of CAM. 

EPA should amend these provisions and provide a methodology to explain how it is to be 

implemented to avoid automatic deviations upon a problem with operating data. EPA must 

provide flexibility to control sorbent feed rates based on CEMS output over full load range and 

fuel qualities in cases where CEMS are utilized. 

Response: The final rule clarifies the operating requirements applicable to CPMS. If a PM 

CEMS is used, then the operating parameter limits do not apply, so the commenter’s second 

concern seems inapplicable.

Commenter Name: Randall D. Quintrell

Commenter Affiliation: Georgia Paper and Forest Products Association, GPFPA

Document Control Number: EPA-HQ-OAR-2002-0058-2905

Comment Excerpt Number: 9

Comment: Nothing in the statute or regulations requires that the test duration be the same as the 

averaging period. If boiler operations are stable at "maximum normal" operation with a 

consistent fuel mix for the parameter being tested (conditions also dictated by the proposed test 

requirements) a standard Method 5 test could be used to determine acceptable continuous 

parametric values that can be reasonably extrapolated to a 12-hour or 24-hour average 

monitoring parameter value. This testing scenario is comparable to current testing requirements 

for many boilers and a Method 5 PM test can typically be completed in a 12-hour work day even 

with some occasional upset of the boiler load. 

Response: Nothing in the final rule is inconsistent with this approach. The parameter operating 

limit is established based on average results obtained during the performance testing and then the 

source will collect the data on an hourly basis and combine parameter data into longer block 

averages.
309

Commenter Name: Walter Tyler

Commenter Affiliation: Invista

Document Control Number: EPA-HQ-OAR-2002-0058-2761.1

Comment Excerpt Number: 12

Comment: Boilers regulated under the Boiler MACT will be operated at many loads ranging 

from 50% - 90+% of nameplate capacity. In order to comply with 63.7520(c), which requires the 

performance test to be conducted at the “maximum normal operating load,” the boiler will be 

tested at the upper end of this operating range, i.e., 80 to 90+% of capacity. However, due to 

current economic conditions and other factors, this same boiler may also be operated at much 

lower operating rates, e.g., near 50% of capacity. The requirement that injectant feed rates be at 

or above those rates during the performance test will result in over injection of material that will 

not reduce the HAP emission rates, will result in unnecessary and excess injectant that must be 

disposed of, and will result in significant unnecessary cost to the owner. 

To ensure compliance with the required emission limitations and minimize the above concerns, 

INVISTA recommends that EPA provide flexibility for dry scrubber injectant rates that would 

allow a facility to develop multiple operating points (or an operating curve) for dry scrubbers. 

This would require changes to the Boiler MACT regulatory language at: 

* 63.7520(c) to allow for more than the single “maximum normal operating load” 

* 63.7530(b)(3)(iii) to describe the alternative of establishing multiple injectant operating points 

(or an operating curve) 

* 63.7530(c) and Table 8, Item 5 to describe how the injection rate should be maintained to 

demonstrate compliance with the operating limits 

Response: Table 7 allows for scaling the injection rate based on operating loads.

Commenter Name: Leonard W. Sandridge

Commenter Affiliation: University of Virginia

Document Control Number: EPA-HQ-OAR-2002-0058-2769.1

Comment Excerpt Number: 18

Comment: We operate three coal- and gas-fired boilers each equipped with a spray dry absorber 

(SDA) and baghouse. According to Tables 4 and 7 and §63.7530(b), these boilers must establish 

a minimum sorbent injection rate limit calculated as 90% of the average sorbent inject rate 

during the HCl performance test, which is conducted under maximum normal operating loads. 

Our SDAs have an operating curve they follow – adjusted for actual flue gas temperatures and 

SO2 removal rates – with minimum sorbent flows at low loads. The scrubber manufacturer has 

recommended lime slurry feeds ranging from 2.53 to 13.4 gpm for low range operations of 

30,000 lbs/hr steam flow to high range operations of 67,000 lbs/hr steam flow. The discount of 

90% will not cover the full operating range of our boilers. 
310

Response: Table 7 allows for scaling the injection rate based on operating loads.

Commenter Name: Leonard W. Sandridge

Commenter Affiliation: University of Virginia

Document Control Number: EPA-HQ-OAR-2002-0058-2769.1

Comment Excerpt Number: 19

Comment: Is data available to support using SO2 as a surrogate for HCl? We have inlet and 

outlet SO2 analyzers for calculating SO2 emission rates and SDA removal efficiencies. Other 

Boiler MACT sources may have similar monitoring requirements. Could a 30-day average SO2 

removal efficiency limit be an allowable substitute for a 12-hour rolling average sorbent 

injection rate limit? 

Response: See the response to EPA-HQ-OAR-2002-0058-3137.1, Comment Excerpt Number 

59.

Commenter Name: Leonard W. Sandridge

Commenter Affiliation: University of Virginia

Document Control Number: EPA-HQ-OAR-2002-0058-2769.1

Comment Excerpt Number: 20

Comment: When does the clock start for a 12-hour rolling average? Our boilers startup on 

natural gas before transitioning to coal. It typically takes four or five hours to warm up a boiler 

from a cold start before switching to coal, and the SDA does not operate during gas-fire 

operations. If the 12-hour average starts when the boiler is first fired on gas, then has a four or 

five hour warm-up period with zero sorbent injection, and then seven or eight hours of coal fire, 

our boilers will not be in compliance with the minimum sorbent injection rate limit. If the 12-

hour average only includes coal-fire operations, we may be able to able to “absorb” some low 

sorbent feed in the 12-hour rolling average. Please clarify the allowable methods for 

demonstrating compliance with the operating limits in the regulations. 

Response: The requirements apply on a 12-hour block average, not a rolling average. EPA 

believes that this issue could be addressed in the monitoring plan for the specific source, and 

should be handled on a site-specific basis.

Commenter Name: Melvin E. Keener

Commenter Affiliation: Coalition for Responsible Waste Incineration (CRWI)
311

Document Control Number: EPA-HQ-OAR-2002-0058-2824.1

Comment Excerpt Number: 20

Comment: EPA should modify the language in 63.7525(q)(3) to make the calibration 

requirements for pH meters site-specific. 

As proposed, EPA would require all pH meters to have a two point calibration every 8 hours. 

CRWI members have extensive experience with pH meters and consider this level of detail to be 

unnecessary. The length of time between checking the calibration of a pH meter is site-specific 

and the facility should have flexibility to determine a frequency of calibration based on the 

historical experience with similar installations and instruments without EPA prescribing a onesize-fits-all frequency. A set frequency for all instruments regardless of the sophistication of the 

instrument and regardless of the service environment of the instrument is not appropriate. In 

other words, one size does not fit all. 

Companies that have’gone to the expense of using sophisticated instruments such as smart 

transmitters and other instruments with self-diagnostics as opposed to continuing to use older, 

less sophisticated systems would not benefit from upgrading their systems. It is the facility’s 

responsibility to develop and implement an adequate monitoring program. This is already 

required as a part of their site-specific monitoring plan. Putting this level of detail in a regulation 

does not help; it only creates unnecessary work under most circumstances. 

Response: See the response to EPA-HQ-OAR-2002-0058-1907.1, Comment Excerpt Number 

37.

Commenter Name: Melvin E. Keener

Commenter Affiliation: Coalition for Responsible Waste Incineration (CRWI)

Document Control Number: EPA-HQ-OAR-2002-0058-2824.1

Comment Excerpt Number: 21

Comment: EPA should modify the language in 63.7540(a)(1) so that the facilities have until the 

results of the initial test are submitted before having to meet the operating parameter limits 

established in the test. 

As proposed, 63.7540(a)(1) requires facilities to operate below any applicable operating 

parameter limits as soon as the initial performance test is completed. Facilities cannot know what 

the maximum (or minimum) operating parameter limits will be until the results of their initial (or 

subsequent) performance tests are received and analyzed. CRWI suggests that this language be 

modified to state that the facility must follow the operating parameter limits once the test results 

are submitted.. 

Later in this section, EPA states that operating parameter limits must be confirmed or reestablished during performance tests. To avoid obvious, ratcheting down of operating parameter 
312

limits, CRWI suggests that EPA add a provision to waive meeting current operating parameter 

limits during subsequent testing. 

Response: Under the final rule, initial compliance with operating limits is required at the same 

time as when initial compliance with the emission limit is required. For subsequent tests where 

the operating limit may be re-established, the new limit, if applicable, would apply as of when 

the test data documenting compliance are available. Until that time, the existing limit would 

remain in effect. On the concern about ratcheting down operating limits, see the response to 

EPA-HQ-OAR-2002-0058-3213.1, Comment Excerpt Number 301.

Commenter Name: Chris Greissing

Commenter Affiliation: Industrial Minerals Association

Document Control Number: EPA-HQ-OAR-2002-0058-2740.2

Comment Excerpt Number: 22

Comment: EPA Fails to Justify the Requirement for 3 Hour Averaging for Wet Scrubbers. The 

Proposed Rule 63.7541 requires a 3-hour average for units with wet scrubbers participating in 

emissions averaging. There appears to be no reasonable justification in requiring a 3-hour 

averaging period for sources with wet scrubbers that elect to average emissions, as compared to 

the 12-hour averaging period for individual units specified in Table 8. As noted above, only 

existing sources who can demonstrate that emissions averaging will not result in total emissions 

greater than those units complying on an individual basis can take advantage of the alternative 

compliance option. This more stringent monitoring interval is not justified by EPA as being 

necessary to ensure a source does not exceed the emissions standards and will further discourage 

emission averaging. 

EPA should eliminate the requirement for 3-hour averaging for units with wet scrubbers at 

existing sources that choose to demonstrate compliance through emission averaging. EPA should 

impose the same monitoring requirements for existing sources that elect emissions averaging as 

individual units. These standards will be adequate to ensure equality in total HAP emissions. 

Response: The final rule uses a 12-hour block average.

Commenter Name: Randall D. Quintrell

Commenter Affiliation: Georgia Paper and Forest Products Association, GPFPA

Document Control Number: EPA-HQ-OAR-2002-0058-2905

Comment Excerpt Number: 25

Comment: An unreasonable compliance monitoring requirement is the pH calibration 

requirement for sources using wet scrubbers for HC1 control. The proposed Rule specifies a 2-

point calibration every 8 hours. Perhaps such unreliability in monitoring was typical 50 years 
313

ago, but with the solid state, digital technology of instrumentation today, pH meters are capable 

of holding calibration indefinitely. Such a calibration requirement is unnecessary and 

unreasonable, and will result in needless monitor downtime and expense. To provide 

documentation to the agency that the monitor is correct, a daily verification of a scrubbant pH 

against a calibrated lab pH meter is more than sufficient, with a requirement for corrective action 

(e.g., 2-point calibration) if it is out of range. Even this level of detail on calibration should not 

necessarily be embodied in the MACT Rule itself It is unnecessary and overly prescriptive. At 

most, the Rule should specify "according to manufacturer’s recommendations". Moreover, many 

of the sources with wet scrubbers are biomass boilers that have inherently low HC1 in the fuel 

and have inherently alkaline flue gas for effective removal of any trace amounts, so even the 

emission levels entering the scrubber will be very low. The concerns over these very low levels 

of HC1 are misplaced. The pH monitor calibration requirement should be removed from the 

Rule. 

Response: See the response to EPA-HQ-OAR-2002-0058-1907.1, Comment Excerpt Number 

37.

Commenter Name: Melvin E. Keener

Commenter Affiliation: Coalition for Responsible Waste Incineration (CRWI)

Document Control Number: EPA-HQ-OAR-2002-0058-2824.1

Comment Excerpt Number: 27

Comment: EPA should resolve the conflicting instruction on operating conditions for certain 

parameters 

In the preamble (75 FR 32033), EPA states that facilities must set certain parameters (pH, 

pressure drop and liquid flow rates for wet scrubbers, etc.) based on a 4-hour block average. 

However, Table 7 requires that the operating limits should be based on the average of each 

individual test run. Typically, each individual test run lasts one hour. Thus, the average of three 

tests would only come up to 3 hours, not the 4 hours listed in the preamble. CRWI believes that 

the regulations have the proper way to set operating parameters and suggests that the preamble 

should be modified to match the regulatory language. 

Response: The parameters are set based on the values obtained during the performance test. 

That value is then established as the operating limit. The monitoring then occurs, collecting 

hourly values that are combined into 4-hour block averages, then a combined 12-hour block 

average to determine if the limit is met.

Commenter Name: Chris Greissing

Commenter Affiliation: Industrial Minerals Association

Document Control Number: EPA-HQ-OAR-2002-0058-2740.2
314

Comment Excerpt Number: 27

Comment: OPERATING LIMITS. The Proposed Rule would require that sources establish and 

monitor numerous operating limits, as well as fuel content limits. These operating limits would 

include pressure drop, pH, liquid flow rate, voltage, sorbent injection rates, etc. The operating 

limits would be established by measuring these parameters during initial performance testing. 

This is an invalid methodology because there is no correlation between these parameters and 

MACT emission limits. The performance test might measure emissions to be far below the 

MACT limits, but the source would nonetheless be required to meet the parameters associated 

with the lower emission rates. 

This process fails to recognize the variability of operating rates and the relationship between 

such rates and the parameters in question. For example, if a performance test were conducted at 

near a unit’s maximum operating rate, and sorbent injection rates of activated carbon to control 

mercury at this maximum rate were required to be maintained even when unit was operating at 

half the maximum rate, sorbent injection would be wastefully required to be double what is 

needed to meet emission limits at the lower operating rate. The parameters measured during 

initial performance tests are not representative of the range of operating conditions. Just as EPA 

accounts for variability in boiler fuels and operations in setting MACT limits, if it insists on 

requiring parameter monitoring it should also recognize variability when setting operating limits 

and allow for sufficient flexibility to accommodate that variability. 

Response: See the response to EPA-HQ-OAR-2002-0058-2635.1,Comment Excerpt Number 5.

Commenter Name: Chris Greissing

Commenter Affiliation: Industrial Minerals Association

Document Control Number: EPA-HQ-OAR-2002-0058-2740.2

Comment Excerpt Number: 33

Comment: 63.7540. How do I demonstrate continuous compliance with the emission limits and 

work practice standards? 

(a)(1) Following the date on which the initial performance test is completed or is required to be 

completed under 63.7 and 63.7510, whichever date comes first, you must not operate above any 

of the applicable maximum operating limits or below any of the applicable minimum operating 

limits listed in Table 4 to this subpart at any times. Operation above the established maximum or 

below the established minimum operating limits shall constitute a deviation of established 

operating limits. 

During initial performance testing each source is to establish operating limits for the associated 

pollution control equipment (“PCE”) after which those operating limits represent continuous 

compliance. The rule requires performance stack testing to be conducted at the “maximum 

normal operating load”. (63.7520(c).) Accordingly, the minimum operating limits are established 

at the maximum normal operating load. This requirement will force the source to maintain 

unnecessarily high scrubber pressure drops or ESP power levels during periods in which the 
315

boiler or process heater is at less than maximum operating rates. High scrubber pressure drops 

and ESP power levels consume significant energy and, if unwarranted, would be contrary to 

EPA’s initiative for energy conservation in this rule. EPA should allow flexibility for PCE 

operating limits, such as a mechanism that would allow PCE operating limits to be proportional 

to the unit’s operating rate. One example might be an option for verification of compliance at 

three different operating rates with three corresponding PCE operating parameters; these data 

could provide the basis for a regression that could be applied across the operating range of the 

unit. 

Response: See the response to EPA-HQ-OAR-2002-0058-2635.1,Comment Excerpt Number 5.

Commenter Name: David A. Buff

Commenter Affiliation: Golder Associates Inc

Document Control Number: EPA-HQ-OAR-2002-0058-2801.1

Comment Excerpt Number: 53

Comment: Operating parameters are not needed where CEMS are required. 

Response: EPA agrees with those commenters that suggested that operational parameter 

monitoring is not needed when CEMS are used and has adjusted the proposed rule language to 

provide for this exclusion.

Commenter Name: Robert D. Bessette

Commenter Affiliation: Council of Industrial Boiler Owners (CIBO)

Document Control Number: EPA-HQ-OAR-2002-0058-2702.1

Comment Excerpt Number: 108

Comment: Operating Limits 

A. Operating Limits Approach Is Unworkable. 

EPA proposes that operating parameters measured during performance tests should constitute 

minimum site-specific operating requirements subsequent to the performance test. It is 

inappropriate and in many cases not technically feasible to use near-ideal 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. EPA should amend the 

Proposed Rule to allow for optimum system operations and ratio-type parameters. The following 

comments detail why the current proposal is unacceptable. 

EPA sets minimum required operating parameters at high load conditions, which are applicable 

to all operating conditions going forward. This approach is unacceptable. EPA’s function is not 

to dictate how a source operates each and every unit, but instead to limit emissions impacts to the 

environment. It is unreasonable to place many of the hard limits derived from the operating

limits approach on a facility long term. EPA provides in the Proposed Rule that boilers and 
316

process heaters without wet or dry scrubbers that must comply with an HCl emission limit must 

"measure the average chlorine content level in the input fuel(s) during the HCl performance test." 

75 FR 32013. Such an operating limit would be unmanageable long term as it would require 

exact replication of the test fuel, which in some cases is not likely and would also eliminate the 

use of permitted opportunity fuels. EPA has does not have the expertise, nor the legal authority 

to mandate such an approach. 

With many pollution control technologies, the proposed approach to establishing and 

maintaining minimum operating limits would result in needless over-consumption of sorbents at 

great cost to the facility with little or no commensurate benefit to human health. 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. While such an approach may work for based loaded utility 

boilers that are baseloaded, there are a great diversity of units and operating conditions affected 

under this rule as compared to utility-type units. Institutional, commercial and industrial boilers 

vary loads widely based on site conditions, business conditions, season and time of day, and 

other factors. This minimum sorbent flow requirement 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. One member company with solid-fuel fired boilers equipped with SDA’s experienced 

catastrophic failures due to operation where more slurry was injected than the flue gas could 

evaporate. Operating limits are simply unacceptable for throughput and firing load variations and 

to attempt to include them would require excessive and unnecessary costs for minimal, if any, 

environmental benefit. 

Response: See the response to EPA-HQ-OAR-2002-0058-2635.1,Comment Excerpt Number 5.

Commenter Name: Robert D. Bessette

Commenter Affiliation: Council of Industrial Boiler Owners (CIBO)

Document Control Number: EPA-HQ-OAR-2002-0058-2702.1

Comment Excerpt Number: 109

Comment: Variability of Sorbent Injection Over Loads. 

Sorbent injection limits should not be fixed at the as tested/full-load injection rates as in many 

cases this is not considered normal boiler operation. This results in a waste of sorbents resulting 

in excessive O&M costs to the boiler owner in many operating load ranges, and can compromise 

the integrity or reliable operation of some types of pollution control equipment. An option to 
317

include a feed forward and possibly feed back control logics should be allowed that sets injection 

rates based upon a feed forward operation signal such as gas flow rates or a feed back signal 

from certified CEMS if provided. i.e. Feed rates for mercury control are calculated based upon 

lb/MMacf. 

Response: Table 7 allows for scaling injection rates based on operating load.

Commenter Name: Robert D. Bessette

Commenter Affiliation: Council of Industrial Boiler Owners (CIBO)

Document Control Number: EPA-HQ-OAR-2002-0058-2702.1

Comment Excerpt Number: 110

Comment: Values Obtained During Initial Performance Tests are Not Necessarily 

Representative. 

CIBO also has concerns with the representativeness of values measured during a source’s initial 

performance test. EPA asserts performance tests must be conducted using "worst case fuels" with 

respect to emissions of PM, metals, HCI, and mercury, i.e. the fuel mix that results in the highest 

emission levels for these substances. The practicality of requiring worst-case fuels for 

performance testing purposes is addressed separately in these comments. However, burning 

"worst case" fuels may not result in the "worst case" emissions. Such a requirement imposes an 

arbitrary lowering of emission limits under other operating and fuel conditions. 

CIBO supports use of fuel analyses and fuel supplier certification with extrapolation allowed 

from performance test levels to the emission limits as a more appropriate approach for assuring 

compliance with the total metals and mercury limits (and HCl emission limit as explained 

elsewhere in these comments). Initial performance testing, periodic emissions testing, and use of 

operating parameters are adequate to provide assurance of compliance. 

Response: See the response to EPA-HQ-OAR-2002-0058-2635.1,Comment Excerpt Number 5.

Commenter Name: Robert D. Bessette

Commenter Affiliation: Council of Industrial Boiler Owners (CIBO)

Document Control Number: EPA-HQ-OAR-2002-0058-2702.1

Comment Excerpt Number: 111

Comment: B. The Current Approach Should Be Changed. 

The current operating limits approach should be changed to allow for optimum system 

operations and ratio parameters. The Hazardous organic NESHAP (HON) allows for single-point 

testing and extrapolation with engineering judgment. 59 FR 19425 (Apr. 22, 1994). Other 

MACT standards simply recognize that it is not always possible to establish these operating 
318

ranges solely on performance test data. For example, the HON found at 40 CFR 63 Subpart G 

has the following relevant provision: 

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. 

40 CFR 63.152(b)(2)(ii)(A). 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. The method contained in the HON is what should be adopted as it allows the source to 

propose the single-point testing based on what is appropriate and allowed in the rule without 

alternative monitoring procedures. If EPA decides upon this approach it should modify certain 

definitions including the following: minimum pressure drop; minimum scrubber effluent pH; 

minimum scrubber flow rate; minimum sorbent injection rate; minimum voltage or amperage.

Response: See the response to EPA-HQ-OAR-2002-0058-2635.1,Comment Excerpt Number 5.

Commenter Name: Robert D. Bessette

Commenter Affiliation: Council of Industrial Boiler Owners (CIBO)

Document Control Number: EPA-HQ-OAR-2002-0058-2702.1

Comment Excerpt Number: 112

Comment: Continuous Compliance Proposal of 12-hour block averages. 

EPA has proposed operating parameters of 12-hour block average based on 4-hour averages. 75 

FR 32033 CIBO recommends that EPA adopt instead a 24-hour rolling average for operating 

parameters. This will allow for normal operating fluctuations and slower emissions response to 

operating parameter changes and startup/shutdown periods. The HON uses 24-hour block 

average for chemical processes that typically do not vary greatly due to throughput or firing rate. 

This generally occurs for boilers where the additional latitude of a rolling average is more 

appropriate. If EPA does not determine the 24-hour rolling average is appropriate, CIBO 

proposes a 24-hour block average, and alternatively, a 12-hour rolling average. Furthermore, the 

Proposed Rule is inconsistent in the averaging times specified for operating parameters. EPA 

should amend § 63.7525(d)(4), which currently references 3-hour block averages, so that it 

reflects what is stated in Table 8 75 FR 32056, 32072. 

Response: The incorrect reference to a 3-hour average has been removed. EPA has retained the 

12-hour block average as an appropriate period for ensuring continuous compliance under this 

subpart.
319

Commenter Name: Robert D. Bessette

Commenter Affiliation: Council of Industrial Boiler Owners (CIBO)

Document Control Number: EPA-HQ-OAR-2002-0058-2702.1

Comment Excerpt Number: 139

Comment: Semiannual flow sensor calibration is too frequent and unjustified. 

The Proposed Rule requires sources with an operating limit that requires flow measurement to 

"conduct a flow sensor calibration check at least semiannually." 75 FR 32056. This requirement 

is unreasonable because the calibration is too frequent. Electronic flow sensors have minimal 

drift and may not be able to do calibration without adversely affecting operation. CIBO 

recommends that EPA allow recalibrations be done on the normal unit overhaul frequency. 

Response: See the response to EPA-HQ-OAR-2002-0058-1907.1, Comment Excerpt Number 

37.

Commenter Name: Robert D. Bessette

Commenter Affiliation: Council of Industrial Boiler Owners (CIBO)

Document Control Number: EPA-HQ-OAR-2002-0058-2702.1

Comment Excerpt Number: 140

Comment: Daily check of pressure tap pluggage is onerous and unjustified. 

Sources with operating limits that require the use of a pressure measurement device are required 

to "check pressure tap pluggage daily. 75 FR 32056. This requires gauging calibration with a 

manometer. 75 FR 32056. This requirement does not reflect common practice. CIBO 

recommends that EPA amend this requirement so that it is more flexible. 

Response: See the response to EPA-HQ-OAR-2002-0058-1907.1, Comment Excerpt Number 

37.

Commenter Name: Robert D. Bessette

Commenter Affiliation: Council of Industrial Boiler Owners (CIBO)

Document Control Number: EPA-HQ-OAR-2002-0058-2702.1

Comment Excerpt Number: 141

Comment: The pH meter calibration requirement is too frequent and unjustified 

Sources with operating limits that require the use of a pH measurement device must check the 

pH meter’s calibration on at least two points every 8 hours of process operation. 75 FR 32056. 

This requirement is excessive, as most facilities calibrate pH meters weekly. Autocalibration 
320

systems are available for around $30,000 per application, which adds to the already significant 

control, testing, and monitoring costs for this rule. 

Response: See the response to EPA-HQ-OAR-2002-0058-1907.1, Comment Excerpt Number 

37.

Commenter Name: Robert D. Bessette

Commenter Affiliation: Council of Industrial Boiler Owners (CIBO)

Document Control Number: EPA-HQ-OAR-2002-0058-2702.1

Comment Excerpt Number: 142

Comment: The sorbent injection rate monitoring requirements are too unreasonable. 

Sources with operating limits that require the use of equipment to monitor sorbent injection rate 

(e.g. , weigh belt, weigh hopper, or hopper flow measurement device) must install and calibrate 

the device in accordance with manufacturer’s procedures and specifications. 75 FR 32056. 

Additionally, on an annual basis, sources must calibrate the device in accordance with the 

manufacturer’s procedures and specifications. 75 FR 32056. This requirement is unreasonable. 

EPA should allow units that do not shut down at least annually for a scheduled or code outage, to 

conduct this work on a frequency to coincide with scheduled maintenance or code outages. For 

any of the monitoring methods EPA should not require calibration more frequently than on an 

annual basis. 

Response: See the response to EPA-HQ-OAR-2002-0058-1907.1, Comment Excerpt Number 

37.

Commenter Name: Matthew Todd and David Friedman

Commenter Affiliation: American Petroleum Institute (API) and National Petrochemical and 

Refiners Association (NPRA)

Document Control Number: EPA-HQ-OAR-2002-0058-2960.1

Comment Excerpt Number: 149

Comment: For CPMS, we support the plan approach specified in this paragraph. Today’s state 

of the art sensors and electronic transmitters, power supplies, etc do not require the repeated 

checks and inspections proposed. The establishment of fixed calibration intervals, as EPA 

proposes, is contrary to standard metrology practice. NCSL International, an ANSI-accredited 

consensus standards developer for metrology standards, has a long-established Recommended 

Practice for determination of appropriate calibration intervals for measurement systems. This 

Practice recognizes that calibration intervals need not (in fact, must not) be set at arbitrary, fixed 

intervals to achieve acceptable data quality. The National Institute of Standards and Technology, 

the U.S. government agency concerned with the quality and reliability of measurement data, does 
321

not require fixed calibration intervals. Other U.S. government agencies such as NASA also do 

not require fixed calibration intervals. Acceptable calibration intervals are based on past 

experience and failure rates. Using this approach, calibration intervals can be determined that 

provide the required data quality at the least cost. 

However, EPA proceeds to override the plan by specifying many details of CPMS QA/QC 

procedures. The purpose of using a plan approach is to allow QA/QC activities to be 

individualized for the equipment and situation. Specifying inflexible calibration frequencies and 

other details of CPMS QA/QC requirements eliminates the very reason for having a plan, 

overrides manufacturer‘s recommendations and metrology standard practice and always adds 

unnecessary and wasteful burdens, and increases safety risk and environmental emissions. 

Additionally, specifying fixed QA/QC procedures, rather than relying on the available consensus 

standards mentioned above violates Section 12(d) of the National Technology Transfer and 

Advancement Act (NTTAA) of 1995 (Pub. L. 104113; 15 U.S.C. 272 note) which directs the 

EPA to use voluntary consensus standards in their regulatory and procurement activities unless 

to do so would be inconsistent with applicable law or otherwise impractical. The Agency goes to 

great lengths to address the requirements of NTTAA on pages 32046 through32048 of the 

preamble, but completely ignores the metrology consensus standards 

Recommendation: Eliminate the specific CPMS QA/QC requirements in proposed 63.7525(e), 

(f) and (g) and rely on the QA/QC plan proposed in 63.7505(d) and the available metrology 

consensus standards. 

Response: See the response to EPA-HQ-OAR-2002-0058-1907.1, Comment Excerpt Number 

37.

Commenter Name: Matthew Todd and David Friedman

Commenter Affiliation: American Petroleum Institute (API) and National Petrochemical and 

Refiners Association (NPRA)

Document Control Number: EPA-HQ-OAR-2002-0058-2960.1

Comment Excerpt Number: 150

Comment: For CPMS, EPA has proposed [Footnote: 73 FR 59956 (October 9, 2008)] 

Performance Specification 17, ”Specifications and Test Procedures for Continuous Parameter 

Monitoring Systems at Stationary Sources” and Procedure 4, “Quality Assurance Requirements 

for Continuous Parameter Monitoring Systems at Stationary Sources.” These proposed 

requirements would be applicable to any CPMS required by a part 63 subpart if 63.8(a)(2) 

applies to that subpart. Table 10 of this proposal would apply 63.8(a)(2) to this subpart. Thus, PS 

17 and P-4 will apply to the parameter monitors specified for boilers and process heaters. 

However, 63.7505(d) and 63.7525(e), (f) and (g) address QA/QC for this regulation and, with 

just a few exceptions, are much more feasible and reasonable than the proposed PS-17 and P-4. 

Applying both sets of requirements would not be practical or justified. 
322

Recommendation: Revise Table 10 of the proposed rule to specify No for 63.8(a)(2). 

Response: Section 63.8(a)(2) is intended to apply to this subpart and imposes general provisions 

that work together with the specific requirements in the rule. The extent to which PS 17 and 

Procedure 4 when finalized will apply to this subpart and the appropriate order of precedence in 

the event those proposed provisions do apply will be evaluated and discussed in the rulemaking 

for those requirements. For purposes of the current rulemaking, the Agency has developed and 

proposed specific requirements for performance specifications for this rule, allowing source 

owners or operators to develop plans customized for their sites. Source owners or operators are 

encouraged to build on their existing practices, rather than start from scratch, to minimize the 

burden associated with providing a continuous assurance of compliance as required by the 

statute.

Commenter Name: Matthew Todd and David Friedman

Commenter Affiliation: American Petroleum Institute (API) and National Petrochemical and 

Refiners Association (NPRA)

Document Control Number: EPA-HQ-OAR-2002-0058-2960.1

Comment Excerpt Number: 151

Comment: If proposed 63.7505(d) is maintained for CPMS and 63.8(a)(2) is made nonapplicable, we have the following comment on one of the specific items that must be included in 

the required monitoring plan. 63.7505(d)(1)(ii) calls for including performance and equipment 

specifications for the sample interface, the pollutant concentration or parametric signal analyzer, 

and the data collection and reduction systems. We do not understand the phrase the pollutant 

concentration or parametric signal analyzer. What performance and equipment specifications are 

associated with the pollutant concentration? Additionally, we believe it is wasteful to require 

documentation around the data collection system. These are generally very complex digital 

computer systems, often shared among a great many instruments. It serves no purpose to 

incorporate massive amounts of information about these large systems into a CMS monitoring 

plan. 

Recommendation: If proposed 63.7505(d) is maintained for CPMS and 63.8(a)(2) is made nonapplicable, revise 63.7505(d)(1)(ii) to remove the data collection and reduction systems and 

clarify the phrase “the pollutant concentration or parametric signal analyzer.” 

Response: Performance specifications are for the pollutant concentration analyzer. The phrases 

"pollutant concentration" and "parametric signal" both separately modify the word "analyzer." 

The language in this rule is the same as many other similar subparts and EPA does not believe 

that any adjustment in language is required. EPA disagrees with the comment about 

documentation of the data collection system. The plan should have basic information and 

specifications for the collection system to ensure that it is capable of capturing and storing data at 
323

appropriate frequencies. There is no need for massive amounts of information to meet this 

requirement. This requirement has been included in multiple other similar subparts and is 

capable of being met on a practical, effective basis.

Commenter Name: Matthew Todd and David Friedman

Commenter Affiliation: American Petroleum Institute (API) and National Petrochemical and 

Refiners Association (NPRA)

Document Control Number: EPA-HQ-OAR-2002-0058-2960.1

Comment Excerpt Number: 155

Comment: Proposed 63.7525(e)(2) specifies required continuous flow monitors “must use a 

flow sensor with a measurement sensitivity of 2 percent of the flow rate.” Such precision cannot 

be met and this should be revised to “must use a flow sensor with a measurement sensitivity of at 

least 2 percent of the flow rate.” 

Recommendation: Clarify 63.7525(e)(2). 

Response: The rule language in 63.7525(e)(2) will be revised to state " not greater than 2 

percent" instead of exactly "of 2 percent". 

Commenter Name: Matthew Todd and David Friedman

Commenter Affiliation: American Petroleum Institute (API) and National Petrochemical and 

Refiners Association (NPRA)

Document Control Number: EPA-HQ-OAR-2002-0058-2960.1

Comment Excerpt Number: 156

Comment: The language in proposed 63.7525(f) should be clarified to specify that the section 

only applies to continuous pressure monitors, not to manually read pressure gauges. 

Recommendation: Clarify that 63.7525(f) only applies to continuous pressure monitors. 

Response: This section, by its cross-reference to paragraph (d), applies only if you are required 

to use a CPMS.

Commenter Name: Matthew Todd and David Friedman

Commenter Affiliation: American Petroleum Institute (API) and National Petrochemical and 

Refiners Association (NPRA)

Document Control Number: EPA-HQ-OAR-2002-0058-2960.1
324

Comment Excerpt Number: 157

Comment: Proposed 63.7525(e)(4) specifies that required flow meters must be calibrated 

semiannually. Essentially all of the flow meters required by this rule are in clean, non corrosive, 

non-abrasive service and thus 5-year calibrations are typically recommended by the 

manufacturers [Footnote: For instance, Rosemont, a major supplier of flow meters to the refining 

industry recommends their flow meters be calibrated at least once every five years and their 

literature cites an annual stability for their meters of ±0.2% per year with this calibration 

frequency.] and are adequate to assure accurate measurements. We therefore recommend, if this 

requirement is not deleted in favor of a plan approach and use of consensus standards as 

recommended in Comment 3 above, this requirement be changed to every 5 years. In addition to 

eliminating several hours of flow meter outage per year, 5-year calibrations will lessen the 

chance of a boiler or process heater upset or a control device upset during a fuel gas meter 

outage. Because some boilers and process heaters are not safe to operate without a fuel gas meter 

(e.g., firing for some reboiler process heaters has to vary fairly rapidly as reboiler demand 

varies), we also recommend a delay provision be provided for unsafe to calibrate situations. 

Some flow meters are calibrated by the manufacturer and cannot be calibrated in the field. For 

Emerson Micro Motion flow tubes, for instance, there is nothing to wear or break, and 

calibration is only accomplished by removing the flow tube and sending it offsite. So this can 

only be done during a scheduled shutdown of a unit, which typically is infrequent. 

Recommendation: If this requirement is not deleted in favor of a plan approach and use of 

consensus standards change the flow meter calibration requirement to 5-year and provide a delay 

of calibration provision where the outage for calibration would cause an unsafe situation and a 

waiver where a flow meter cannot be field calibrated. 

Response: See the response to EPA-HQ-OAR-2002-0058-1907.1, Comment Excerpt Number 

37.

Commenter Name: Matthew Todd and David Friedman

Commenter Affiliation: American Petroleum Institute (API) and National Petrochemical and 

Refiners Association (NPRA)

Document Control Number: EPA-HQ-OAR-2002-0058-2960.1

Comment Excerpt Number: 158

Comment: Proposed 63.7525(f) specifies, relative to continuous pressure monitors, “Check 

pressure tap pluggage daily,” “Check calibration quarterly and transducer calibration monthly,” 

and “Conduct calibration checks any time the sensor exceeds the manufacturer‘s specified 

maximum operating pressure range or install a new pressure sensor.” 

To check for pluggage generally requires purging the pressure sensor, thereby releasing 

hydrocarbon and HAPs to the atmosphere. These significant, often unpermitted emissions have 
325

not been addressed in the rulemaking record. Generally, it is adequate to be sure the pressure 

reading is varying. In services where pluggage is a problem, the problem is generally apparent 

and occurs repeatedly. Thus, only where there is a history of pluggage is any action needed other 

than assuring the pressure reading varies. Where pluggage is a problem engineering fixes are 

usually preferable to daily or other routine checks, because they avoid environmental releases. 

Electronic pressure instruments experience very little drift, and calibrations at least annually 

would be more than adequate unless specific applications are shown to experience problems. Use 

of a plan allows sources to tailor their calibration frequencies to the situation. OSHA considers 

annual testing of instrumentation to be adequate for most critical safety interlock applications. 

There is no reason to calibrate (audit and inspect) CPMS systems 4-12 times as often as critical 

safety instruments. In fact, that much instrument outage will create unnecessary safety and 

environmental risk. 

Unless a pressure instrument is overpressured to a failure point, they generally are not impacted 

by operating briefly outside their pressure range. It is not industry practice, recommended 

practice, or reasonable to have to monitor every continuous pressure instrument for overpressure 

just on the off-chance this situation might occur. This just generates another applicable 

requirement that greats significant burdens to allow a compliance certification, while adding no 

benefit. If there is such an occurrence and it impacts the capability of the instrument, that will be 

immediately apparent because the instrument will fail to track or give an unreasonable reading. 

Only in that case, is it justified to recalibrate or replace the instrument and that will happen in 

any case. 

If these requirements are not deleted in favor of a plan approach and use of consensus standards 

as recommended in Comment 3 above, we recommend this provision be changed to Check the 

pressure reading daily to assure the reading is reasonable and varies. Where a plugging problem 

occurs in a pressure tap, take reasonable actions to avoid reoccurrence and maintain a record of 

the occurrence and the action taken, Change the calibration frequency to annual and delete 

subparagraph (6). 

Recommendation: If these requirements are not deleted in favor of a plan approach and use of 

consensus standards remove the current language in 63.7525(f)(4) and replace it with a 

requirement to check daily that the pressure reading is varying, change the calibration frequency 

in (f)(5) to annual and delete paragraph (f)(6). 

Response: See the response to EPA-HQ-OAR-2002-0058-1907.1, Comment Excerpt Number 

37.

Commenter Name: Matthew Todd and David Friedman

Commenter Affiliation: American Petroleum Institute (API) and National Petrochemical and 

Refiners Association (NPRA)

Document Control Number: EPA-HQ-OAR-2002-0058-2960.1
326

Comment Excerpt Number: 159

Comment: Proposed 63.7525(g)(3) specifies Check the pH meter’s calibration on at least two 

points every 8 hours of process operation. Manufacturer‘s recommendations for modern pH 

instruments, industry practice and recommended practice only call for calibration weekly. Since 

the meter is off-line during any calibration, unnecessary outages increase the risk of 

noncompliance (and per Comment VII.A.6 is a reportable deviation). We therefore, recommend 

that, if this requirement is not deleted in favor of a plan approach and use of consensus standards 

as recommended in Comment 3 above, the proposed 63.7505(d) monitoring plan address the pH 

meter calibration and other pH meter QA/QC requirements and that no specific frequency be 

cited in 63.7525(g). 

Recommendation: Remove the proposed pH meter calibration requirements and specify that pH 

meter calibration frequency be addressed in the monitoring plan. 

Response: See the response to EPA-HQ-OAR-2002-0058-1907.1, Comment Excerpt Number 

37.

Commenter Name: Matthew Todd and David Friedman

Commenter Affiliation: American Petroleum Institute (API) and National Petrochemical and 

Refiners Association (NPRA)

Document Control Number: EPA-HQ-OAR-2002-0058-2960.1

Comment Excerpt Number: 181

Comment: The proposed rule requires development of operating parameter limits based on the

values achieved during the performance test or fuel tests. However, rule requirements apply at all 

times, not just when the boiler or process heater is operating at performance test conditions. In 

many cases, the operating parameters developed during performance or fuel tests will not cover 

all operations, but will only be appropriate for certain modes of operation. For example, the 

absolute sorbent injection rate observed during the performance test conducted under full load 

will not correlate to the sorbent injection rate necessary during startup or periods of lower load. 

Frequently, sorbent injection rates are set using a feedback loop from a CEMS or CPMS to avoid 

wasting sorbent. Similarly, stack temperatures during performance tests will be different than 

stack temperatures during other types of operations and operating parameters for the oxidation 

catalyst system, may need adjustment. EPA should allow for this type of approach to set 

operating limits. 

Recommendation: Allow for adjustments in establishing operating limits for control device 

operating parameters to reflect differences between performance test conditions and the real 

world. 

Response: See the response to EPA-HQ-OAR-2002-0058-2635.1,Comment Excerpt Number 5.
327

Commenter Name: Robert D. Bessette

Commenter Affiliation: Council of Industrial Boiler Owners (CIBO)

Document Control Number: EPA-HQ-OAR-2002-0058-2702.1

Comment Excerpt Number: 189

Comment: Sorbent injection limits should not be fixed at the as tested/full-load injection rates as 

in many cases this is not considered normal boiler operation and a waste of sorbents resulting in 

excessive O&M costs to the boiler owner. EPA should allow an option to include both a feed 

forward and feed back control logics that sets injection rates based upon a feed forward operation 

signal such as gas flow rates or a feed back signal from certified CEMS (i.e. feed rates for 

mercury control are calculated based upon lb/MMacf). 

Response: Table 7 allows for scaling injection rates based on operating load. For the option 

mentioned, EPA understands the commenter's concern, and believes this situation will be best 

handled through the alternative monitoring provisions. EPA would consider this type of 

alternative through exercising its authority provided for in the general provisions.

Commenter Name: Robert D. Bessette

Commenter Affiliation: Council of Industrial Boiler Owners (CIBO)

Document Control Number: EPA-HQ-OAR-2002-0058-2702.1

Comment Excerpt Number: 203

Comment: Averaging Periods 

Emission limits should reflect intra-unit variability and averaging periods that will ensure 

consistent compliance. 

The ICI boilers burn multiple types of fuels and are subject to frequent load swings. Therefore, 

the emissions from these boilers vary over the course of a day, depending on the fuel burned and 

the required steam production. EPA acknowledged during the Phase 2 ICR test program that 

emissions from industrial boilers are variable by requesting multi-year historical stack test data 

and conducting 30-day fuel and emissions monitoring studies. One way to consider a unit’s 

variability in emissions is to set a longer averaging time for compliance with an emission limit. 

Additional variability data and CEMS data should be reviewed to support longer averaging 

times. The court reviewing the Brick MACT authorized EPA to look at intra-unit variability and 

EPA’s work on the Hazardous Waste Combustion MACT confirmed the importance of 

considering variability. EPA also acknowledged that averaging times longer than 3 hours can be 

appropriate for compliance with the condensate collection and treatment requirements in pulp 

and paper MACT Subpart S. 

Averaging times of longer than 3 hours are needed for industrial boilers, especially for boilers 

that burn multiple fuels. The facility must be able to operate the boiler in a manner that is 
328

responsive to process needs, not at full load all the time. Longer averaging periods are critical if 

the MACT limits apply during startup and shutdown. 

The Proposed Rule is inconsistent in the averaging times specified for operating parameters. The 

body of the rule specifies 3-hour parameter averages while Table 8 specifies 12-hour block 

averages be calculated for CPMS. Where a COMS is used, a daily block average is specified. 

EPA should use daily block averages for CPMS as well. A 24-hour averaging period 

acknowledges process variability, decreases the effect of short process upsets, and captures the 

variable emissions and operating characteristics of a unit over an operating day. 

There are factors beyond the boiler operator’s control that can cause emissions to vary over a 

period of days and not hours. For example, the weather will impact moisture content of solid 

fuels, which will affect how the fuels combust over a period of days, not hours. For a biomass 

boiler, the fuel supply and fuel characteristics could also vary over a period of days because mills 

have multiple biomass fuel suppliers providing both green and dry wood. For all types of boilers, 

the pollutant content of the fuel will vary over a period of days, as evidenced by the range of 

results obtained during the 30-day fuel sampling required by EPA for many ICR Phase 2 

participants. Where CEMS are the compliance method (e.g., PM and CO), we support a 30- day 

averaging period to account for operational and emissions variability. 

Response: The final rule continues to use a 12-hour block average for most parameters and a 

dialy block average for opacity. These are appropriate levels for ensuring continuous 

compliance given the operating limits being used.

Commenter Name: Randall D. Quintrell

Commenter Affiliation: Georgia Paper and Forest Products Association, GPFPA

Document Control Number: EPA-HQ-OAR-2002-0058-2905

Comment Excerpt Number: 28

Comment: Flexibility should be included in the compliance monitoring provisions, such as 

allowing the use of a CO2 CEMS as a dilutent monitor and the use of historically proven 

parametric monitoring for control device operations, such as total secondary power or scrubbant 

dP. Excessive and unnecessary provisions for other compliance monitoring must also be 

removed from the Rule before it is finalized. 

Response: The final rule does not require a CO monitor, so the CO2 diluent comment is no 

longer applicable. The Agency believes the other monitoring provisions, especially when 

coupled with the process for requesting an alternative monitoring approach under the general 

provisions, allow for adequate flexibility while also providing a basic set of approaches that can 

be employed by most sources. 

Commenter Name: Marvis A. Lewallen
329

Commenter Affiliation: Clearwater Paper

Document Control Number: EPA-HQ-OAR-2002-0058-2862

Comment Excerpt Number: 6

Comment: We encourage EPA to allow sources greater flexibility in how they establish 

parameter ranges for monitoring compliance with parameter operating limits. The proposed 

regulations require that for biomass boilers with wet scrubbers, sorbent injection or ESPs with 

wet scrubbers, that the source establishes operating parameter ranges that it must demonstrate 

compliance with. In all three instances, the operating parameter is set based on the average value 

of the parameter during the three source tests where compliance was demonstrated. The wood 

products industry has extensive experience establishing and implementing parameter values 

based on source tests under the range of operating conditions that we face. For example, the 

PCWP MACT requires that such parameters be established for certain controls. Based on 

industry experience, we know the difficulty with the approach outline by EPA in the proposed 

rule. We operate sources that are required to meet highly variable loads under a wide variety of 

temperatures and moisture levels. As a result, setting parameters based on the average of three 

runs during a particular source test has been shown to result in parameter values that do not 

allow for adequate flexibility. In order to set a reasonable value, extensive testing across different 

times of year is required. This poses an undue burden on such sources. For that reason, we 

encourage greater ability to rely on data from similar units in establishing parameters and we 

encourage EPA to allow statistical analysis of the stack test parameter results such that the 

parameter is not set at the average of the parameter values, but at the average plus two standard 

deviations so as to account for variability. At the very least, we request that scrubbers, sorbent 

injection and wet ESPs be treated no differently than fabric filters with scrubbers, where EPA 

proposed to set the parameter values for flow, temperature and pH as the lowest of the three runs 

during the performance test. 

Response: See the response to EPA-HQ-OAR-2002-0058-2635.1,Comment Excerpt Number 5.

Commenter Name: Edward Bortz

Commenter Affiliation: SP Newsprint Co LLC

Document Control Number: EPA-HQ-OAR-2002-0058-3128

Comment Excerpt Number: 6

Comment: Provide Greater Flexibility in Establishing Parameter Ranges 

We encourage EPA to allow sources greater flexibility in how they establish parameter ranges 

for monitoring compliance with parameter operating limits. The proposed regulations require 

that for biomass boilers with wet scrubbers, sorbent injection or ESP’s with wet scrubbers, that 

the source establish operating parameter ranges that it must demonstrate compliance with. In all 

three instances, the operating parameter is set based on the average value of the parameter during 

the three source tests where compliance was demonstrated. The wood products industry has 

extensive experience establishing and implementing parameter values based on source tests 

under the range of operating conditions that we face. For example, the PCWP MACT requires 
330

that such parameters be established for certain controls. Based on industry experience, we know 

the difficulty with the approach outline by EPA in the proposed rule. We operate sources that are 

required to meet highly variable loads under a wide variety of temperatures and moisture levels. 

As a result, setting parameters based on the average of three runs during a particular source test 

has been shown to result in parameter values that do not allow for adequate flexibility. In order 

to set a reasonable value, extensive testing across different times of year is required. This poses 

an undue burden on such sources. For that reason, we encourage greater ability to rely on data 

from similar units in establishing parameters and we encourage EPA to allow statistical analysis 

of the stack test parameter results such that the parameter is not set at the average of the 

parameter values, but at the average plus two standard deviations so as to account for variability. 

At the very least, we request that scrubbers, sorbent injection and wet ESPs be treated no 

differently than fabric filters with scrubbers, where EPA proposed to set the parameter values for 

flow, temperature and pH as the lowest of the three runs during the performance test. 

Response: See the response to EPA-HQ-OAR-2002-0058-2635.1,Comment Excerpt Number 5.

Commenter Name: John Hopewell

Commenter Affiliation: American Coatings Association

Document Control Number: EPA-HQ-OAR-2002-0058-2886.1

Comment Excerpt Number: 13

Comment: The CPMS QA/QC requirements are not appropriate. 

Facilities need more flexibility in development of operating parameter limit s. Sources will not 

be able to meet some operating parameter limits on startup . In addition, ACA is concerned that 

each performance test will only serve to ratchet down operating parameter limits. And, where 

facilities use CEMS, operating parameter monitoring is not necessary 

Response: 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 

emission 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 tests with less stringent operating levels than may have been initially 

determined, the source will be able to set the limits at levels appropriate for their operations 

while ensuring emission limits are met. As noted in other comments, EPA also agrees that 

CPMS are not required where the owner/operator conducts monitoring of compliance with an 

emission limit with a CEMS. With respect to the general concerns raised about QA/QC 

requirements, see the response to EPA-HQ-OAR-2002-0058-1907.1, Comment Excerpt Number 

37.

Commenter Name: J. Michael Geers
331

Commenter Affiliation: Duke Energy

Document Control Number: EPA-HQ-OAR-2002-0058-2765.1

Comment Excerpt Number: 18

Comment: EPA’s Proposed Operating Parameters Are Not Sufficiently Connected to Emission 

Limits to Be Enforceable Limits 

Duke Energy strongly disagrees with EPA’s current proposal to set enforceable operating limits 

based on control device parameters measured during performance testing. Establishment of such 

limits reduces operational flexibility, deprives sources of the use of any control device margin, 

and allows enforcement for events beyond the control of the owner/operator. 

EPA’s proposal is based the faulty assumptions that the values of the parameters identified by 

EPA have a direct relationship to the level of emissions, and that exceedances of those limits 

therefore indicate an exceedance of the emission limit as well. To the extent possible, source 

owners and operators will contract for control equipment that is designed to provide a “margin of 

compliance” with the applicable emission limitation. [Footnote: For example, it is relatively 

common for new ESPs to be purchased with extra fields and sections which will allow the source 

to continue to operate in compliance with applicable emission limits even when there are 

problems with other parts of the controls. Fabric filters and scrubbers can also be purchased with 

extra capacity (i.e., additional modules) for the same purpose.] In addition to reducing the 

possibility of an exceedance of an emission limit, this margin is intended to provide flexibility 

for the source to account for the inevitable control equipment or operational problem. Any 

source that is able to normally operate with a margin of compliance will lose part of that margin 

of compliance if they conduct performance testing under normal operations, because they will 

establish operating limits that would require them to continue to over-control forevermore. The 

only way such sources could avoid surrendering whatever margin of compliance they have 

would be to deliberately reduce performance of their controls to attempt to generate the least 

stringent operating limits that are consistent with achievement of the applicable emission 

standard. EPA’s proposal thus could have the perverse outcome of encouraging sources to focus 

their attention on learning how to manipulate their operations to allow testing as close as possible 

to their emission limit by reducing performance of their controls. 

Unfortunately, even the “detuning” of a control device during performance testing will not 

ensure that the operating limits established during the test are reasonable, or necessary for 

achievement of the applicable emission limit. As EPA has previously recognized in the context 

of the NSPS and the CAM rule, “many sources operate well within permitted limits over a range

of process and pollution control device operating parameters,” and requiring sources to 

continuously maintain parameters that “happened to exist” during the most recent performance 

test “may not be possible or wise.” 62 Fed. Reg. 54907, 54926-27. This is because control device 

parameters, such as those identified by EPA for scrubbers and ESPs, do not necessarily have a 

direct relationship to emissions, but instead are interrelated with the design of the control device 

and the interaction of various parameters. As a result, a single parameter may vary widely with 

little effect on emissions. For example, total ESP power may be completely unrelated to ESP 

performance for a multi-sectional ESP. This power approach for ESPs simply does not work and 

that fact is easily demonstrated by real world operating experience. Precipitator power will vary 

depending upon a number of factors including operating conditions, coal quality, etc, a fact that 

Duke Energy routinely sees in the operation of its own units. Similarly, scrubber pressure drop is 

a direct function of boiler load. A basic engineering principles is that pressure drop through a 
332

restriction such as a scrubber vessel is a directly related to velocity. As the velocity increases, the 

pressure drops. Recording pressure drop during a performance test will not be indicative of 

emissions levels at a different load. Industrial boilers operate at variable load levels because they 

follow process demand. As the load drops, the scrubber pressure drop decreases. This change

does not necessarily indicate a drop in scrubber performance. In fact, the scrubber performance is 

likely to improve at reduced load. Unfortunately as EPA has proposed the standard, simply 

reducing load will put a source in a condition of non-compliance.”

Similarly scrubber flow will also change depending upon operating conditions and system 

chemistry requirements such as the required slurry density. Many sources do not normally install 

flow meters in this situation and installing them in this application will be costly and fraught with 

monitoring difficulties and inaccuracies. If EPA feels that it needs a metric to ensure proper 

scrubber operation, it should limit its requirements to operating the same number 

of scrubber flow pumps that a source used during the performance test, and demonstrate that the 

flue gas is indeed going through the scrubber module and not being bypassed. 

Although EPA’s provision of a 10 percent difference from the average tested value recognizes 

some of the normal operational variability of control devices, it will not be sufficient in many 

circumstances. Without a clear correlation between such operating parameters and the applicable 

emission limit, imposition of those values as enforceable limits would unreasonably restrict 

source and control device operation and subject sources to potential enforcement without any 

evidence that an emission limits has been violated. This is particularly important where EPA’s 

proposal runs counter to basic engineering principals. 

Response: See the response to EPA-HQ-OAR-2002-0058-2635.1,Comment Excerpt Number 5.

Commenter Name: J. Michael Geers

Commenter Affiliation: Duke Energy

Document Control Number: EPA-HQ-OAR-2002-0058-2765.1

Comment Excerpt Number: 19

Comment: Operating Limits Proposing the Use of Opacity and ESP Power Are Flawed 

Under EPA’s proposal, units that do not use a wet scrubber (e.g., units with no controls or with a 

dry scrubber) must comply with an opacity limit of 10 percent based on a daily block average. 

Proposed 63.7500(a)(2) and Tables 4 and 8. [Footnote: Source owners/operators can apply to the 

Administrator for approval of an “alternative opacity emission limit” under § 63.6(h)(9). 

Proposed § 63.7570(b)(2).] Units that use an ESP in combination with a wet scrubber (and thus 

cannot monitor opacity) must comply with operating limits on the voltage and secondary current 

(or total power input) of the ESP collection plates. Proposed 

63.7530(b)(3)(ii). EPA’s proposal to use opacity and ESP voltage and power measurements as 

enforceable operating limits is flawed. The use of total power is not at all reliable as an indicator 

of ESP performance or problems. Although opacity can be used as an “indicator” of particulate 

emissions, or as a trigger to initiate corrective action on an ESP, there is not a sufficiently direct 

correlation between opacity and PM or Hg to justify imposition of an enforceable limit. 
333

For example, it is well known that the relationship between opacity and mass PM (i.e., mass 

concentration) is affected by the particulate size distribution, particle shape, and the color 

(reflectivity) of the flyash. Numerous tests have confirmed that western subbituminous coal ash 

creates considerable opacity at very low fuel gas particulate mass loading, while eastern 

bituminous coal has a higher opacity/mass relationship. Duke Energy’s experience is that opacity 

and particulate emission rates vary even when using bituminous coal from different vendors. 

Given these and other variables, the relationship simply is not sufficient to make assumptions 

based on the proposed opacity operating limit that the PM limit is not being met. 

The use of opacity as an operating limit for mercury (“Hg”) is even more problematic. Mercury 

is emitted from boilers in three forms - particle bound, oxidized, and elemental. Even if opacity 

were directly related to PM (which it is not), it would only be sensitive to particle bound Hg. 

Oxidized and elemental Hg cannot be detected at all by an opacity monitor. EPA has not 

adequately explained how this tenuous relationship can justify use of opacity as a limit that could 

create liability for violation of the Hg emission limit. 

Finally, EPA’s proposal to require the use of ESP parameters has similar flaws. Total ESP power 

input is not directly related to particulate removal performance, particularly for the modern 

multi-section ESPs that are likely to be installed to comply with a MACT. Moreover, none of the 

ESP parameters are likely to have any relationship to PM for units that also have a wet scrubber, 

because a wet scrubber is also highly effective in controlling high levels of particulate matter 

coming out of an ESP that is not performing at its intended control efficiency. 

In summary, while opacity is a useful indicator of ESP problems that should be investigated and 

corrected, ESP power is not, and the relationship between opacity to stack emissions of PM and 

Hg is not sufficient to conclude that the emission limit is being exceeded. 

Response: See the response to EPA-HQ-OAR-2002-0058-2635.1,Comment Excerpt Number 5.

Commenter Name: John C. deRuyter

Commenter Affiliation: DuPont

Document Control Number: EPA-HQ-OAR-2002-0058-2793.1

Comment Excerpt Number: 20

Comment: Operating Limits Need to Account for Inherent Variations 

EPA is proposing that operating limits established during performance testing at high load stable 

conditions be maintained during normal operations. This is an unreasonable approach that will 

result in inefficient and potentially unsafe operation of equipment. As examples, scrubbing 

systems need to be able to vary sorbent injection rates with flue gas flow rate and fuel quality In 

order to optimize performance; SDA systems could indeed plug up with excessive slurry 

injection rates, causing safety issues and major clean out costs. Activated carbon injection is 

typically fed on the basis of lb/MMacf of flue gas, and holding a lb/hr injection rate constant 

based on high rate operation will cause excessive injection at low boiler loads, wasting sorbent 

and money, and possibly causing other system problems. Scrubber flow rates and other 

parameters need to vary with operating loads and other parameters for optimum system 
334

operation. Therefore, EPA must allow for variations in all operating parameters/limits as 

appropriate for the equipment and operations involved. 

Response: See the response to EPA-HQ-OAR-2002-0058-2635.1,Comment Excerpt Number 5.

Commenter Name: J. Michael Geers

Commenter Affiliation: Duke Energy

Document Control Number: EPA-HQ-OAR-2002-0058-2765.1

Comment Excerpt Number: 20

Comment: Issues with the Use of pH and Sorbent Injection Rate for Scrubbers 

Under EPA’s proposal, units that use a wet scrubber must also comply with operating limits for 

pH, and units that use a dry scrubber must comply with an operating limit on sorbent injection 

rate. Proposed § 63.7530(b)(3)(i) and (iii). EPA’s proposal to use these parameters is subject to 

the same flaws as EPA’s other proposed operating limits -- namely the lack of a sufficient 

relationship between the parameters measured during performance testing and actual emissions. 

For example, as described above, because pH and sorbent injection rate vary with boiler load and 

coal chemistry, establishment of a limit based on conditions during performance testing may tell 

EPA little about actual emissions under other load conditions. Moreover, when EPA in 2008 

considered the relationship between liquid flow rate and PM in the context of the NSPS for 

electric steam generating units at 40 C.F.R. Subpart Da, EPA concluded that, at the level of the 

NSPS (i.e., 0.015 lb/mmBtu), PM emissions controlled by an ESP were not particularly sensitive 

to the actual liquid flow rate. EPA Response to Public Comments on Rule Amendments 

Proposed June 12, 2008 (73 FR 33642), EPA-HQ-OAR-2005-0031-0284, at 

2.5.3. 

Response: See the response to EPA-HQ-OAR-2002-0058-2635.1,Comment Excerpt Number 5.

Commenter Name: J. Michael Geers

Commenter Affiliation: Duke Energy

Document Control Number: EPA-HQ-OAR-2002-0058-2765.1

Comment Excerpt Number: 22

Comment: EPA Should Require Sources to Establish Source-Specific Control Device Parameter 

Ranges and Enforceable Response Requirements, Not Enforceable Operating Limits. 

Rather than establish enforceable operating limits, EPA should use the approach taken in the 

CAM rule and require sources to establish site-specific operating parameter ranges to define 

conditions under which compliance with the applicable limit can be reasonably assured. This 

approach already has been upheld as sufficient to satisfy the CAA’s requirements for 

demonstrating continuous compliance. See Natural Resources Defense Council v. EPA, 194 F.3d 

130 (D.C. Cir. 1999) (rejecting NRDC’s argument that the CAM rule’s “reasonable assurance of 

compliance” is not sufficient to assure continuous compliance as required by the CAA). Source 
335

owners and operators would then be required to monitor those parameters and respond to 

changes that indicate problems with the controls that could jeopardize compliance. 

Whether using a single control device or combination of devices, sources are in the best position 

to determine what parameters and levels are consistent with compliance. In many cases, multiple 

parameter relationships or supplemental operational data will provide a higher level of 

compliance assurance than the level that happens to be measured during a discrete performance 

test. This is particularly true for sources with a significant margin of compliance. In addition, 

units with significant margins of compliance should be allowed to establish operating levels by 

extrapolating parameter data beyond that obtained during a performance test based on other 

information. Allowing such extrapolations is essential for some sources to provide needed 

operational flexibility. Attempting to establish “worst case” test conditions on a scrubber or 

multi-section ESP, where the possible combinations of parameters are numerous, would at the 

least be difficult and could be impossible without a major research effort. Allowing extrapolation 

of results avoids the necessity of repeated testing. [Footnote: A similar approach has been used in 

CAM protocols, including a protocol developed by the Electric Power Research Institute (EPRI) 

for ESPs (allowing extrapolation up to 1.25 times the recorded value for measurements taken at 

less than 80 percent of the applicable emission limit).] 

Once sources have established appropriate operating parameter ranges based on data collected 

during performance tests, as well as other operating data and engineering principles, those 

parameters would be monitored and any deviation from them would trigger a requirement for 

investigation and corrective action to return the parameter to the appropriate range. Although this 

range may in some cases be similar to the minimum values that would be established under 

EPA’s proposed rule, allowing sources to respond with corrective action (rather than simply 

record exceedances and report deviations) achieves EPA’s intended result without subjecting 

sources to potential unreasonable enforcement. 

Response: See the response to EPA-HQ-OAR-2002-0058-2635.1,Comment Excerpt Number 5.

Commenter Name: David Foerter

Commenter Affiliation: Institute of Clean Air Companies

Document Control Number: EPA-HQ-OAR-2002-0058-2937.1

Comment Excerpt Number: 27

Comment: Given it is clear that some facilities will elect to utilize the injection of sorbents to 

meet the emission control standards, the following changes are suggested to ensure that ongoing 

operations of sorbent injection systems continue to meet the emission parameters established 

during the performance testing period. 

In the summary of the proposed rule (75 FR 32013) an approach whereby operating limits are 

established for various types of units is outlined. Specifically Section III.F.(3) states “For boilers 

and process heaters with sorbent injection, you would be required to measure the sorbent 

injection rate for each sorbent used during the performance tests for HCl, mercury and D/F and 

calculate the average of each sorbent for each test run. The average of the three test run averages 
336

established during the performance tests would be your site-specific minimum sorbent injection 

rate operating limit.” 

While this approach seems quite reasonable, we suggest adding the requirement to qualify the 

reactivity or specific parameters of the sorbent itself. We have experienced a wide variety of 

performance in terms of sorbent effectiveness and the standard should be modified to prevent 

facilities from utilizing a highly effective sorbent during the performance testing and then 

substituting it with a lower performing and presumably lower cost sorbent during routine 

operations. This is necessary to insure the facilities meet the goal of the standards given the 

facilities will not be subjected to CEM requirements. Therefore, ICAC recommends the 

regulatory requirement to utilize sorbents that are equally reactive and effective as those utilized 

during the performance testing. 

Response: The general requirements for testing require that the tests be conducted under normal 

conditions, which would include using the same quality sorbent during testing as is used during 

operations. This type of deliberate violation of the regulations is considered unlikely as a general 

concern, and will be best handled through effective compliance oversight and no change to the 

rule is necessary.

Commenter Name: David Foerter

Commenter Affiliation: Institute of Clean Air Companies

Document Control Number: EPA-HQ-OAR-2002-0058-2937.1

Comment Excerpt Number: 29

Comment: Sources have to measure their injection rates during the performance test with the 

average of the three test run averages setting the site-specific minimum sorbent injection rate 

operating limit. These performance tests will likely be done at full load / steady-state operation, 

however many boilers in the ICI sector have variable load conditions, and the minimum sorbent 

injection rate operating limit that is established may actually represent a waste of sorbents 

resulting in excessive O&M costs to the boiler owner. ICAC recommends a regulatory option 

that both feed-forward and feed-back control logics be allowed that set injection rates based upon 

a feed-forward operation signal such as gas flow rate or a feed- back signal from a certified 

CEMS. An example with mercury control is where variable injection feed rates for mercury 

control are automatically set based on gas flow, and the source would then have to retain the 

necessary records for inspection purposes. 

Response: Table 7 allows for scaling injection rates based on operating loads. For the 

commenter’s option, EPA understands the commenter's concern, and believes this situation will 

be best handled through the alternative monitoring provisions. EPA would consider this type of 

alternative through exercising its authority provided for in the general provisions.
337

Commenter Name: Russ A. Wozniak

Commenter Affiliation: Dow Chemical Company

Document Control Number: EPA-HQ-OAR-2002-0058-2632.1

Comment Excerpt Number: 49

Comment: EPA Should Revise the Requirements in Proposed Section 63.7525(d) Regarding 

Continuous Parameter Monitoring Systems. EPA proposes prescriptive requirements throughout 

Section 63.7525 for Continuous Parameter Monitoring Systems (CPMS) that may or may not 

align with best industry practices or manufacturer recommendations. Many of these requirements 

are similar to a rule that EPA previously proposed regarding CPMS that EPA received 

significant adverse comments on from a number of commenters. EPA has indicated that they 

plan to re-consider the need for such a rule based on the comments received. 

Some examples of the prescriptive requirements contained in Section 63.7525 of this proposed 

rule include the following items: 

(e)(2) - you must use a flow sensor with a measurement sensitivity of 2 percent of the flow rate; 

(e)(4) - you must conduct a flow sensor calibration check at least semiannually; 

(f)(4) - check pressure tap pluggage daily; and 

(g)(3) - check the pH meter’s calibration on at least two points every 8 hours of process 

operation. 

The owner/operator should be provided flexibility to define certain items such as periodic 

instrument check frequency and calibration in the site-specific monitoring plan that is required 

by section 63.7505(d). The final rule should remove the prescriptive CPMS requirements in 

section 63.7525 and replace them with a requirement for the owner/operator to define the 

frequency and method of periodic instrument checks and calibrations. The owner/operator should 

be able to rely on manufacturer recommendations, industry practices and performance history for 

these monitoring devices when defining the details of the monitoring plan. 

Specifically, Dow comments that EPA should remove the following portions of the proposed 

rule (Section 63.7525) prior to finalizing the MACT rule: 

(e)(2) 

(e)(4) 

(f)(3) 

(f)(4) 

(f)(5) 

(f)(6) 

(g)(3) 

(i)(3) 

EPA should instead require that all CPMS devices be checked and calibrated at the frequency 

noted by and in accordance with the manufacturer’s procedures and specifications or in 
338

accordance with industry practices as further defined in the monitoring plan required by section 

63.7505(d). 

Response: See the response to EPA-HQ-OAR-2002-0058-1907.1, Comment Excerpt Number 

37.

Commenter Name: Russ A. Wozniak

Commenter Affiliation: Dow Chemical Company

Document Control Number: EPA-HQ-OAR-2002-0058-2632.1

Comment Excerpt Number: 50

Comment: Setting site specific or unit specific operating parameters to levels identified during 

one time or annual stack tests is not justified and limits operations of the sources. In general, 

tests are done in a way to maximize operational flexibility. EPA must also realize that many 

boilers do not have add-on air pollution control systems and/or they may have only minimal 

amounts of HAP present and have had need for only minimal add-on controls or no need for addon controls. EPA must make allowances for these situations, and we discuss more specific 

concerns later in this comment. 

Response: See the response to EPA-HQ-OAR-2002-0058-2635.1,Comment Excerpt Number 5.

Commenter Name: Russ A. Wozniak

Commenter Affiliation: Dow Chemical Company

Document Control Number: EPA-HQ-OAR-2002-0058-2632.1

Comment Excerpt Number: 51

Comment: Establishing site specific operating limits based on an average of 3 stack tests does 

not account for variability inherent in all fuels, including natural gas and especially liquid and 

solid fuels. For example, a source would be unduly limited to a fraction of the allowable 

emission rate due to types and composition of fuels used during stack tests. Theoretically, the 

source has “room” in its allowable emissions, but the proposed rule does not provide any 

allowance for any increase in the constituent of concern in the fuel. 

Response: See the response to EPA-HQ-OAR-2002-0058-2635.1,Comment Excerpt Number 5.

Commenter Name: Russ A. Wozniak

Commenter Affiliation: Dow Chemical Company

Document Control Number: EPA-HQ-OAR-2002-0058-2632.1

Comment Excerpt Number: 52
339

Comment: In order to set acceptable operating parameters, a source may be forced to spike the 

fuel with additional material to establish an allowable product assay greater than generally run. 

Doing so can very be problematic for boilers that do not have add-on controls or only minimal 

controls. Spiking when there are no add-on controls is a very risky approach for a boiler when 

striving to achieve operational flexibility. 

Response: See response to comment EPA-HQ-OAR-2002-0058-2632.1, excerpt 54.

Commenter Name: Russ A. Wozniak

Commenter Affiliation: Dow Chemical Company

Document Control Number: EPA-HQ-OAR-2002-0058-2632.1

Comment Excerpt Number: 53

Comment: For boilers and process heaters without wet or dry scrubbers that must comply with 

an HCl emission limit, facilities must measure the average chlorine content level in the input 

fuel(s) during the HCl performance test. This is the maximum chlorine input operating limit. 

Using the average chlorine content as the limit does not recognize how an average is calculated. 

Some values will be above average and some will be below average. If the average is the limit, 

then the boiler/heater would not be allowed to use the fuel when the chlorine content is above the 

average. In order to avoid this dilemma, some degree of spiking during testing would be needed 

to get an artificial limit that is higher than the average in the fuel. As already mentioned, this is 

very problematic for units with no add-on controls and/or very low HAP concentrations. A unit 

should be allowed to back calculate from the standard what an allowable chlorine limit could be. 

As long as they are below that allowable limit, the agency’s concern should be met. The test 

would simply verify that the amount is low but not set the actual limit. Dow requests this change. 

Response: See response to comment EPA-HQ-OAR-2002-0058-2632.1, excerpt 54.

Commenter Name: Russ A. Wozniak

Commenter Affiliation: Dow Chemical Company

Document Control Number: EPA-HQ-OAR-2002-0058-2632.1

Comment Excerpt Number: 54

Comment: All sources shall be allowed to back calculate the concentration from what they are 

allowed to emit similar to provisions allowed in other MACT rules such as the Hazardous Waste 

Combustion MACT. 

HWCMACT employed a back-calculation concept called MTEC (maximum theoretical emission 

concentration) to deal with units that had a very low concentration of HAP. This concept can 

also be adjusted if the units of measurement have to be something other than emissions 

concentration, such as thermal units (#HAP/MM BTU). Such a concept would allow a facility to 
340

demonstrate compliance with emission standards without following a risky spiking approach to 

obtain operational flexibility. If the back-calculation resulted in some outlandishly high 

allowable limit, then EPA could adopt a backstop to allow some maximum multiplier of a 

historical value (e.g., 3 times the historical value). 

The alternative to this back-calculation approach would be to spike feeds during a test so a 

source would not be bound by an artificially low limit. However, for units with no add-on 

controls or minimal add-on controls, it is very difficult to spike anything without risk of a test 

failure. Dow requests that EPA make an allowance for this concern and foremost that EPA allow 

for a back-calculation type of approach to be used in the final rule.

Response: The commenter does not provide a detailed analysis of the data for how this might be 

incorporated into the final rule. Given the limited fuel variability data available for many of the 

subcategories, and the detailed statistical analysis necessary to evaluate the variability of the 

maximum fuel input this option is not pursued at this time. Further, the rule provides the facility 

with options to conduct multiple compliance tests to establish worst-case conditions in order to 

establish a mercury fuel input operating limit.

Commenter Name: Russ A. Wozniak

Commenter Affiliation: Dow Chemical Company

Document Control Number: EPA-HQ-OAR-2002-0058-2632.1

Comment Excerpt Number: 55

Comment: For boilers and process heaters with wet scrubbers, facilities must measure pressure 

drop and liquid flow rate of the scrubber during the performance test, and calculate the average 

value for each test run. The average of the three test run averages establishes the minimum sitespecific pressure drop and liquid flow rate operating levels. If different average parameter levels 

are measured during the mercury, PM and HCl tests, the highest of the average values becomes 

your site specific operating limit. If the site is complying with an HCl emission limit, it must 

measure pH of the scrubber effluent during the performance test for HCl and determine the 

average for each test run and the average value for the performance test. This establishes the 

minimum pH operating limit. Scrubber pressure drop is a function, among other things, of gas 

flow rate and boiler load. Minimum scrubber pressure drop could limit turn down of the unit. 

Dow requests that the limit be set on manufacturer’s specifications or good engineering practice. 

Response: See the response to EPA-HQ-OAR-2002-0058-2635.1,Comment Excerpt Number 5.

Commenter Name: Russ A. Wozniak

Commenter Affiliation: Dow Chemical Company

Document Control Number: EPA-HQ-OAR-2002-0058-2632.1

Comment Excerpt Number: 56
341

Comment: For boilers and process heaters with sorbent injection, a facility would be required to 

measure the sorbent injection rate for each sorbent used during the performance tests for HCl, 

mercury, and D/F and calculate the average for each sorbent for each test run. The average of the 

three test run averages established during the performance tests would be the site-specific 

minimum sorbent injection rate operating limit. If different sorbents and/or injection rates are 

used during the mercury, HCl, and D/F tests, the average value for each sorbent becomes the 

site-specific operating limit. Again, in lieu of establishing parameter limits via testing, the limits 

should be established by using manufacturer’s specifications or good engineering practice. 

Response: See the response to EPA-HQ-OAR-2002-0058-2635.1,Comment Excerpt Number 5.

Commenter Name: Russ A. Wozniak

Commenter Affiliation: Dow Chemical Company

Document Control Number: EPA-HQ-OAR-2002-0058-2632.1

Comment Excerpt Number: 57

Comment: For boilers and process heaters with fabric filters in combination with wet scrubbers, 

facilities must measure the pH, pressure drop, and liquid flow rate of the wet scrubber during the 

performance test and calculate the average value for each test run. The minimum test run average 

establishes the site specific pH, pressure drop, and liquid flow rate operating limits for the wet 

scrubber. Furthermore, the fabric filter must be operated such that the bag leak detection system 

alarm does not sound more than 5 percent of the operating time during any 6- month period 

unless a CEMS is installed to measure PM. Again, in lieu of establishing parameter limits via 

testing, the limits should be established by using manufacturer’s specifications or good 

engineering practice. 

Response: See the response to EPA-HQ-OAR-2002-0058-2635.1,Comment Excerpt Number 5.

Commenter Name: Russ A. Wozniak

Commenter Affiliation: Dow Chemical Company

Document Control Number: EPA-HQ-OAR-2002-0058-2632.1

Comment Excerpt Number: 58

Comment: For boilers and process heaters with electrostatic precipitators (ESP) in combination 

with wet scrubbers, facilities must measure the pH, pressure drop, and liquid flow rate of the wet 

scrubber during the HCl performance test and you must measure the voltage and current of the 

ESP collection fields during the mercury and PM performance test. The facility would then be 

required to calculate the average value of these parameters for each test run. The average of the 

three test run averages would establish your site-specific minimum pH, pressure drop, and liquid 

flow rate operating limit for the wet scrubber and the minimum voltage and current operating 

limits for the ESP. At low firing rates much of the particulate removal in an ESP is by gravity 

and the actual current draw may be reduced. Again, setting a parameter level during times of 
342

high load likely will limit the ability of the source to meet these requirements during times of 

lower load operation. 

Response: See the response to EPA-HQ-OAR-2002-0058-2635.1,Comment Excerpt Number 5.

Commenter Name: Russ A. Wozniak

Commenter Affiliation: Dow Chemical Company

Document Control Number: EPA-HQ-OAR-2002-0058-2632.1

Comment Excerpt Number: 59

Comment: For boilers and process heaters that choose to demonstrate compliance with the 

mercury emission limit on the basis of fuel analysis, you would be required to measure the 

mercury content of the inlet fuel that was burned during the mercury performance test. This 

value is the maximum fuel inlet mercury operating limit which may constraint operations 

depending on the specific results of the test. In line with an earlier comment, to avoid the risky 

activity of spiking to obtain maximum flexibility, Dow requests a back-calculation approach for 

mercury as well. 

Response: See response to comment EPA-HQ-OAR-2002-0058-2632.1, excerpt 54.

Commenter Name: Chris M. Hobson

Commenter Affiliation: Southern Company

Document Control Number: EPA-HQ-OAR-2002-0058-2741.1

Comment Excerpt Number: 59

Comment: In 63.7525(j)(2), EPA proposes that sources installing bag leak detectors (BLDs) 

must follow the installation, certification, and operating procedures specified in the Office of Air 

Quality Planning and Standards (OAQPS) Fabric Filter Bag Leak Detector Guidance Document 

(EPA-454/R-98-015 in addition to following the manufacturer’s specified procedures. However, 

the referenced document is based on operating and maintenance procedures for a specific type 

and model [See submittal Auburn International, Triboflow and Triboguard Dust Emission 

Monitors and Broken Bag Detectors, General Guidelines for Operation, April 1995.] of BLD and 

is inadequate for many BLD systems. RMB is unaware of any standardized certification and 

ongoing quality assurance procedures that are currently available for boiler applications. 

[Footnote: ASTM D7392 – 07 applies only to cement plants.] Therefore, we recommend that 

EPA remove the requirement that sources comply with the procedures in EPA-454/R-98-015. 

Response: The EPA BLD guidance addresses only one technology type for bag leak detectors. 

(There are several vendors that sell variations of the charge transfer technology.) However, 

proper setup and operation of a bag leak detector can vary with site-specific conditions and those 
343

conditions may dictate variances from the approach and is allowed by the guidance. The EPA 

has no reason to believe that the “Office of Air Quality Planning and Standards (OAQPS) Fabric 

Filter Bag Leak Detection Guidance" document needs updating or is inadequate. To date EPA 

has no information on any conflicts between the manufacturer’s specifications and the guidance 

document.

Commenter Name: Chris M. Hobson

Commenter Affiliation: Southern Company

Document Control Number: EPA-HQ-OAR-2002-0058-2741.1

Comment Excerpt Number: 61

Comment: EPA has specified that all parametric monitoring ranges (including pressure drop, 

scrubber pH, scrubber flow rate, sorbent injection rate, ESP voltages/currents) should not deviate 

below the operating limits established during the compliance test by more than 10%. This 

requirement is overly stringent and will likely result in excessive reporting of potential noncompliance periods. This requirement provides absolutely no compliance margin if the 

variability in any of the parameters was greater than 10% during the test since the limit is based 

on the average value observed during the test. In addition, this approach does not adequately 

account for variability due to normal operation in some cases. For instance, the requirement of a 

minimum pressure drop on a baghouse will result in the reporting of deviations during low-load 

operation. Similarly, the requirement to maintain sorbent injection rate within 10% of the rate 

established during the compliance test might result in the unnecessary reporting of deviations 

when these units fire lower pollutant-containing fuels. 

EPA should allow sources more flexibility in demonstrating proper operation of the control 

equipment by establishing operating ranges based on a typical range in performance of the 

control equipment and boiler operating conditions, similar to the approach EPA applied in the 

Periodic Monitoring and Compliance Assurance Monitoring Rules. An alternative approach to 

establishing more representative control device operating limits might be a statistical analysis of 

historical operating data during which the control device was operating properly (no 

malfunctions). The resulting operating limits could be discrete upper and lower bounds on 

certain operating parameters or a correlation between the control device operating parameter and

one or more boiler operating parameters. 

Response: See the response to EPA-HQ-OAR-2002-0058-2635.1,Comment Excerpt Number 5.

Commenter Name: Chris M. Hobson

Commenter Affiliation: Southern Company

Document Control Number: EPA-HQ-OAR-2002-0058-2741.1

Comment Excerpt Number: 63
344

Comment: The proposed rule includes operating limits for demonstrating continuous 

compliance that are based on specific operating parameters for each type of control device. Some 

of these parameters are either unnecessary, inappropriate, or could otherwise be substituted with 

parameters that are already monitored by the facility. For instance, SO2 emissions (measured by 

an existing CEMS) could be a suitable indicator for wet scrubber operation. Wet scrubber 

parameters could also be simplified based on scrubber pH and a calculated liquid to gas ratio, 

where gas flow is measured using an existing stack flow monitor and liquid injection rate is 

estimated based on the number of recycle pumps in service. For ESP-equipped units, the use of 

total power may not be representative of PM emissions since removal efficiency is dependent on 

where the power is applied in the control device. Other alternatives might include the use of an 

ESP model for predicting performance or specifying a minimum power level within each gas 

path. 

There other monitoring alternatives that would provide EPA with a reasonable assurance of 

compliance with the underlying emissions limits and yet allow the source to implement such 

monitoring more cost effectively. As noted in Comment #4, EPA should provide for greater 

flexibility in determining the appropriate control device operating parameters and how the 

indicator ranges are determined. RMB suggests that EPA implement a monitoring approach 

similar to EPA’s Compliance Assurance Monitoring Rule. 

Response: Under section 63.7500(a) and the Part 63 general provisions, an owner /operator can 

always request an alternative monitoring method. EPA agrees with the commenter's point that 

there will be situations in which alternatives to the methods specified in the rule can provide a 

reasonable assurance of compliance.

Commenter Name: Russ A. Wozniak

Commenter Affiliation: Dow Chemical Company

Document Control Number: EPA-HQ-OAR-2002-0058-2632.1

Comment Excerpt Number: 64

Comment: EPA Should Not Base the Operating Limits for the Minimum Scrubber Pressure 

Drop or Minimum Electrostatic Precipitator Current Flow Solely on Values Obtained During the 

Performance Tests. 

Pages 32013 and 32014 of the preamble and Table 7 of the proposed rule indicate that EPA 

intends to set minimum operating parameter limits for (1) pressure drop through liquid scrubbers 

and (2) the current flow for electrostatic precipitators (ESP) at levels recorded during the 

performance tests. 

The pressure drop through a liquid scrubber is a function of the gas flow rate. Therefore, the 

pressure drop experienced during the performance test, which is conducted at high boiler/heater 

output, will be higher than the pressure drop experienced during normal or reduced operations. 

Requiring that pressure drop to be maintained would require that the boiler/heater always be 
345

operated at its maximum heat input and could not be adjusted downward to met process 

requirements. This requirement is not rational since boilers and heaters do not always need to run 

at maximum heat input. This requirement would result in all boilers/heaters using liquid 

scrubbers being essentially inoperative. The boiler/heater could not operate at any rate other than 

the one rate achieved during the performance tests. The minimum pressure drop (i.e., gas flow 

rate relative to a fixed liquid flow rate) through a liquid scrubber required to achieve a desired 

performance standard is set by design calculation and/or vendor specifications. Dow suggests 

that any such operating parameter limits be based on design calculations and/or vendor 

specifications. 

Similarly, the current flow to an ESP is a function of the gas stream particle loading and 

subsequent amount of particle collection. Therefore, the current flow for an ESP during the 

performance test, when the ESP is highly particle loaded, will be higher than the current flow 

during normal or reduced operating rates. Current flow is not a controllable parameter but 

instead the result of a process due to transfer of electrical charge by a particle. When a 

boiler/heater is operating at a less than maximum burning rate, (where the gas stream can be 

expected to carry a lower particle loading), the ESP will have a lower current flow even at a 

particle removal performance that exceeds what was obtained during the performance test. 

Response: See the response to EPA-HQ-OAR-2002-0058-2635.1,Comment Excerpt Number 5.

Commenter Name: Chris M. Hobson

Commenter Affiliation: Southern Company

Document Control Number: EPA-HQ-OAR-2002-0058-2741.1

Comment Excerpt Number: 16

Comment: EPA has proposed a number of operating limits as a method of demonstrating 

continuous compliance. In addition to being generally unnecessary, many of these operating 

limits will be inappropriately determined. The operating limits are to be determined during the 

initial or annual compliance test which is to be conducted at full boiler load. Operating limits for 

scrubber pressure drop, scrubber liquid flow rate, and sorbent injection rate determined during a 

full boiler load emission test would not be appropriate for operation at other loads as each is a 

function of the volumetric flow rate of the flue gas. For some operating limits the appropriate 

value would not scale linearly with load. In some cases these inappropriately determined 

operating limits would require the owner to operate the control equipment in a costly manner that 

provides no additional environmental benefit. In other cases the limits may be physically 

impossible to achieve at various boiler loads. 

The operating limits are generally unnecessary if the stack test passes the emission limit. If, 

however, EPA requires operating limits, the agency must consider operating limits that are 

beneficial and achievable at all boiler loads. 

Response: See the response to EPA-HQ-OAR-2002-0058-2635.1,Comment Excerpt Number 5.
346

Commenter Name: Gregory A. Wilkins

Commenter Affiliation: Marathon Petroleum Company

Document Control Number: EPA-HQ-OAR-2002-0058-3119.1

Comment Excerpt Number: 2

Comment: It is recommended that EPA add clarifying language to the CO CEMS requirement 

to make clearer that CO CEMS are not required for equipment subject to work practice 

standards. 

Response: See the preamble for revisions to the CO limitations and compliance demonstration 

methods. Also, EPA agrees that a CEMS is not required to demonstrate compliance with work 

practice standards. 

Commenter Name: Jeffrey O'Hearn

Commenter Affiliation: Panolam Industries International Inc

Document Control Number: EPA-HQ-OAR-2002-0058-2749.1

Comment Excerpt Number: 5

Comment: 63.7525(d)(1) and (d)(3): A minimum of three cycles of operation (based on 15 

minute cycles) or 75% of the total cycles (if less than 15 minutes) should be acceptable for a 

valid hour of operation. 

§ 63.7525(d)(3): The loss of a 15 minute period of data should not be classified as a deviation. 

Since 3 hour averages are being required deviations should be based on missing 3 hour averages. 

A typical requirement is that there must be two hours of valid data to constitute a valid 3 hour 

average. 

Response: The final rule has clarified these issues in a manner that addresses the commenter’s 

concerns.

Commenter Name: Jeffrey O'Hearn

Commenter Affiliation: Panolam Industries International Inc

Document Control Number: EPA-HQ-OAR-2002-0058-2749.1

Comment Excerpt Number: 6

Comment: 63.7525(g)(3): The calibration check of the pH meter should be changed to a daily 

measurement rather than every 8 hours. 
347

Response: EPA agrees, and the rule has been changed. 

Commenter Name: Roy W. Wood

Commenter Affiliation: Eastman Kodak Company

Document Control Number: EPA-HQ-OAR-2002-0058-2917.1

Comment Excerpt Number: 8

Comment: Setting operating limits strictly based on values during a stack test is inappropriate. 

EPA proposes that operating parameters measured during performance tests should constitute 

minimum site-specific operating requirements subsequent to the performance test. 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. EPA should modify the 

requirements to allow consistency with equipment design requirements. Standards for scrubber 

liquid flow rate, sorbent injection rate, and electrostatic precipitator power should be based on 

manufacturer’s design requirements for equivalent performance or at a minimum the ratio of the 

scrubber liquid flow rate, sorbent injection rate, and electrostatic precipitator power to gas flow 

rate. 

With many pollution control technologies, the stack test approach to establishing operating limits 

would result in needless over-consumption of sorbents, liquids or power at great cost to the 

facility with little or no commensurate benefit to human health. 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 

required when running at a 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 flow rates and high flue gas temperatures, the flow 

rate 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 and result in higher particulate emissions due to the excess slurry. 

Scrubber liquid to gas ratios (L/G) is a well known technique for designing scrubbers that is 

already used in other MACT rules to control wet scrubber operation for both particulate and HCl. 

This approach is used in the hazardous waste MACT rule, “For high energy wet scrubbers only, 

you must establish limits on either the minimum liquid to gas ratio or . . .” 

[(40CFR63.1209(m)(1)(i)(C)) for PM and (40CFR63.1209(o)(3)(i) for HCl)] 
348

Electrostatic Precipitators (ESPs) are designed to remove particles from gas streams. ESP 

removal is typically determined by the well-known Deutsch Equation (Deutsch, W. 1922, 

Annual der Physik, 68, p.355; White, H., 1963. Industrial Electrostatic Precipitation, Addison 

Wesley, Reading, MA, p. 178 & p. 202, p. 169), which states that: 

ESP removal = 1 - exp(-Aw/Q), (1) 

where A = ESP collection area, 

w = particle migration velocity, and Q = gas flow rate through the ESP. 

Particle migration velocity can be estimated by the following equation developed by the 

precipitator expert, Harry White: 

w = kP/A (2) 

[(White, p. 178 & p. 202; Matsen, J., Fels, M., 1992. “Particulate Removal,” Encyclopedia of 

Environmental Science and Engineering, Gordon and Breach Science Pub., Brooklyn, p. 842))] 

where P = power input to the ESP (secondary power), and k is a constant based on the 

characteristics of the ESP 

Inserting equation (2) into equation (1) gives: ESP removal = 1 - exp(-kP/Q), 

Based on this equation, if kP/Q is constant, removal is constant. If kP/Q increases, then removal 

will increase. Therefore if there is a minimum kP/Q limit based on the performance test average, 

then performance will always be better than or equal to the removal efficiency demonstrated 

during the performance test. Since k is constant for an ESP, only P/Q is variable. Therefore a 

power to gas flow rate (P/Q) minimum limit based on a performance test ensures that 

performance will always be better than or equal to the removal efficiency during the performance 

test and an absolute power limit is not necessary. 

The operating limits for scrubber liquid flow rate, sorbent injection rate, and electrostatic 

precipitator should be either based on manufacturer’s design requirements for equivalent 

performance to the emissions test or the ratio of the scrubber liquid flow rate, sorbent injection 

rate, and electrostatic precipitator power to gas flow rate during the emissions test. 

Response: See the response to EPA-HQ-OAR-2002-0058-2635.1,Comment Excerpt Number 5.

Commenter Name: Mick Baranko

Commenter Affiliation: Douglas County Forest Products

Document Control Number: EPA-HQ-OAR-2002-0058-2856.1

Comment Excerpt Number: 10

Comment: We encourage EPA to allow sources greater flexibility in how they establish 

parameter ranges for monitoring compliance with parameter operating limits. The proposed 
349

regulations require. that for biomass boilers with wet scrubbers, sorbent injection or ESPs with 

wet scrubbers, that the source establish operating parameter ranges that it must demonstrate 

compliance with. In all three instances, the operating parameter is set based on the average value 

of the parameter during the three source tests where compliance was demonstrated. The wood 

products industry has extensive experience establishing and implementing parameter values 

based on source tests under the range of operating conditions that we face. For example, the 

PCWP MACT requires that such parameters be established for certain controls. Based on 

industry experience, we know the difficulty with the approach outline by EPA in the proposed 

rule. We operate sources that are required to meet highly variable loads under a wide variety of 

temperatures and moisture levels. As a result, setting parameters based on the average of three 

runs during a particular source test has been shown to result in parameter values that do not 

allow for adequate flexibility. In order to set a reasonable value, extensive testing across different 

times of year is required. This poses an undue burden on such sources. For that reason, we 

encourage greater ability to rely on data from similar units in establishing parameters and we 

encourage EPA to allow statistical analysis of the stack test parameter results such that the 

parameter is not set at the average of the parameter values, but at the average plus two standard 

deviations so as to account for variability. At the very least, we request that scrubbers, sorbent 

injection and wet ESPs be treated no differently than fabric filters with scrubbers, where EPA 

proposed to set the parameter values for flow, temperature and pH as the lowest of the three runs 

during the performance test. 

Response: See the response to EPA-HQ-OAR-2002-0058-2635.1,Comment Excerpt Number 5.

Commenter Name: David O'Keefe

Commenter Affiliation: USEC, Inc

Document Control Number: EPA-HQ-OAR-2002-0058-3122

Comment Excerpt Number: 10

Comment: Site-specific operating limits, the proposed site-specific operating limits should 

include variability and uncertainty in their establishment.A simple test average ensures the 

source will not be in compliance. Assuming a normal distribution around the average, means that 

half of the time the unit will be operating below its operating limit. The unit’s pollution control 

may be operating less efficiently during one or two of the test runs and still meet emission limits. 

The least efficient run should be the operating limit. Additionally, the pollution control 

equipment may be operating so efficiently that emissions are well below the emission limits. In 

these cases, the source should be allowed to have a less stringent operating limit. 

A better option would allow the source to establish operating limits based on design and/or 

manufacturer’s specifications. This will be more indicative of operation of pollution control 

devices than the relatively short time period involved during performance testing. It also would 

ensure the pollution control equipment is operating as designed. This is especially true for ESPs 

and baghouses where current readings and pressure drop are easily monitored. 

For systems that use injection rates of dry chemicals, again the average input has the same 

weakness as discussed in the first paragraph. Operating limits should be based on calculated 
350

injection rates and fuel analysis. This would help ensure valuable resources are not wasted and 

that they do not needlessly consume limited landfill space. 

Determination of chlorine input levels suffer from the same weaknesses in using the average as 

discussed in paragraph one, It ensures a noncompliance for half of the time. Additionally, fuel

variability during the test is unlikely to capture true avariability in coal-fired units. 

The focus should be on meeting the emission limit and not an operating limit. 

Response: See the response to EPA-HQ-OAR-2002-0058-2635.1,Comment Excerpt Number 5.

Commenter Name: Gary W. Kruger

Commenter Affiliation: Morton Salt

Document Control Number: EPA-HQ-OAR-2002-0058-2883.1

Comment Excerpt Number: 10

Comment: EPA’s Operating Limits Approach Is Not Representative. 

EPA proposes that operating parameters measured during performance tests should constitute 

minimum site-specific operating requirements subsequent to the performance test. It is not 

representative and not technically feasible in many cases to use operating conditions during 

performance tests, which are typically conducted at or near the unit’s maximum firing rate, to 

establish a minimum requirement for all possible load ranges. 

EPA sets minimum required operating parameters at high load conditions which are applicable to 

all operating conditions going forward. This approach is unacceptable. EPA’s role is not to 

dictate how a source operates each and every unit, but is instead to limit emissions impacts to the 

environment. It is unreasonable and impossible in certain cases to place many of the hard limits 

derived from the operating limits approach on a facility long term. For example, EPA provides in 

the Proposed Rule that boilers and process heaters without wet or dry scrubbers that must 

comply with an HCl emission limit must measure the average chlorine content level in the input 

fuel(s) during the HCl performance test. 75 FR 32,013. Such an operating limit would be 

unmanageable long term as it would require exact replication of the test fuel, which in some 

cases is not likely and would also eliminate the use of permitted opportunity fuels. 

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 benefit to human health. 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. The establishment of 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. 

EPA should propose provisions for each site to propose reasonable operating parameter limits 

that are appropriate and specific to the site’s process and pollution control equipment to ensure 
351

minimization of emissions. Such operating parameters should be based on ratios, such as pounds 

of sorbent per million actual cubic feet of flue gas flow, fan speed (rpm), or steam flow for 

injection systems, calcium-to-Sulfur ratio for scrubbers using lime or limestone to remove acid 

gases, or carbon-to-Hg ratio for scrubbers using carbon to remove Hg. 

Response: See the response to EPA-HQ-OAR-2002-0058-2635.1,Comment Excerpt Number 5.

Commenter Name: Michael L. Corvese

Commenter Affiliation: Thermo Fisher Scientific, Inc

Document Control Number: EPA-HQ-OAR-2002-0058-2997.1

Comment Excerpt Number: 10

Comment: The requirements in the proposed regulations section 63.7525(i)(j)(2) through (6) are 

not adequate to assure the reliability of bag leak detection systems (BLDs). Recommend that 

EPA develop and promulgate appropriate design and performance specifications and on-going 

quality assurance specifications for BLDs. 

The BLD requirements contained in the proposed regulations are not adequate to ensure that the 

devices are reliable. EPA has not developed performance specifications for BLDs such as those 

found in Appendix B of Part 60 for COMS and CEMS. Similarly there are no daily calibration 

check requirements (such as those required in 60:13 and 63.8) and there are no other on-going 

quality assurance requirements. There are also no audit techniques for these devices which are 

available to users or to regulatory agencies. There are some very brief requirements for these 

devices found in the proposed section 63.7525(i)(j)(2) through (6) which are also found in other 

EPA regulations. These include a mention of a manufacturer’s certification of the device’s 

detection limit, but there are no other quantitative performance requirements. 

Without adequate design and performance specifications for BLDs the measurement systems 

cannot be relied upon for their intended purpose by either the plant operator or the EPA and there 

is no consistent basis to evaluate expected performance, or actual performance of installed 

measurement systems. The purchaser is left only to the claims of vendors which may be incorrect 

or unfounded. The use of quality instruments is discouraged by unfair competition and low 

quality instruments. 

Response: The EPA has no reason to believe that the “Office of Air Quality Planning and 

Standards (OAQPS) Fabric Filter Bag Leak Detection Guidance" document needs updating or is 

inadequate. EPA has no knowledge that the QA procedures within the Bag Leak Detection 

Guidance is inadequate. Technical specifications, installation procedures, operation and 

maintenance procedures, quality assurance procedures, or alarm setting procedures are contained 

within the EPA guidance document for bag leak detectors and are supplemented in 

manufacturer’s specifications , installation procedures, and directions. Performance 

specifications and quality assurance procedures found in Appendix B and F, respectively, of Part 

60 are for the purpose of certifying a CEMS and for continual quality assurance for CEMS that 
352

are used for continual compliance with an emission limit and therefore are not applicable to 

BLDs. False alarms and instrument malfunctions or misapplication of BLDs is a site specific 

issue and can be averted by careful selection of an appropriate BLD and manufacturer with a 

vendor guarantee of acceptable performance. EPA’s guidance for BLDs is not a certification 

procedure like performance specifications in Appendix B of Part 60 and therefore will not 

contain tests for certification. The bag leak detection system must be certified by the 

manufacturer and not the owner/operator. The operator must consider any operational changes 

and stack gas changes when selecting an appropriate BLD. BLD setup procedures and BLD 

system adjustments found within EPA’s BLD guidance is sufficient for accounting for these 

changes. The EPA BLD guidance is applicable to charge transfer type devices but several 

different manufacturer’s instruments can be used that are applicable to this guidance. The EPA 

BLD guidance addresses only one suggested approach to the use of bag leak detectors. However, 

proper setup and operation of a bag leak detector can vary with site-specific conditions and those 

conditions may dictate variances from the approach suggested in this guidance.

Commenter Name: Gary W. Kruger

Commenter Affiliation: Morton Salt

Document Control Number: EPA-HQ-OAR-2002-0058-2883.1

Comment Excerpt Number: 11

Comment: Opacity Values Obtained During Initial Performance Tests are Not Necessarily 

Representative. 

EPA asserts performance tests must be conducted using worst case fuels with respect to 

emissions of PM, metals, HCl, and mercury (i.e., the fuel mix that results in the highest emission 

levels for these substances). The practicality of requiring worst-case fuels for performance 

testing purposes is addressed separately in these comments. However, burning worst case fuels 

may not result in the worst case opacity levels, given in-stack opacities depend on variables such 

as particle size distribution, densities, flue gas properties, stack diameters, control equipment 

performance, etc., as well as normal measurement and process variability. It is unrealistic to 

expect that worst case opacity levels will be experienced during performance tests that last a few 

hours at most. Yet affected sources could face enforcement exposure every time 3-hour average 

opacity levels exceed the maximum 1-hour value observed during the most recent performance 

test. Since opacities will naturally fluctuate due to other factors besides control device PM 

collection efficiency (not the least of which are operating load and fuel quality changes), this 

type of potential enforcement liability is unwarranted, unjustified, and unacceptable. Such a 

requirement imposes an arbitrary lowering of emission limits under other operating and fuel 

conditions. EPA provides no correlation of 3-hour block averages relative to performance test 

average opacity to show that similar units could achieve the standard. 

Morton Salt supports the use of fuel analyses and fuel supplier certification with extrapolation 

allowed from performance test levels to the emission limits as more appropriate approaches for 

assuring compliance with the total metals and mercury limits (and HCl emission limit as 

explained elsewhere in these comments). Initial performance testing, periodic emissions testing, 
353

and use of operating parameters are adequate to provide assurance of compliance without use of 

opacity monitoring. 

EPA’s theory is that the owner or operator will be able to procure a worst-case fuel that will 

maximize the fuel chlorine, mercury and/or total selected metals content without exceeding the 

Emission Limitation in Table 1. In fact, EPA suggests in §63.7520 that the owner or operator 

may have to conduct more than one performance test to accomplish this. The iterative process by 

which an owner or operator must search for fuels and then conduct performance tests until the 

worst-case fuel is found will be very time consuming and expensive and is unnecessary. 

The same result can be accomplished by requiring the owner or operator to perform the initial 

performance test using the same fuel that has typically been fired in each boiler. The results of 

the performance test can then be used to prorate the actual chlorine, mercury and/or total selected 

metals content of the fuel to the worst-case conditions that would meet the emission limits. The 

owner or operator would then simply have to maintain the fuel chlorine, mercury and/or total 

selected metals content below the prorated values established during initial performance test, 

regardless of the fuel supplier. A new performance test could then be required if the fuel 

chlorine, mercury, and/or total selected metals content exceeded the prorated values established 

during the performance test. 

Response: See generally the response to EPA-HQ-OAR-2002-0058-2635.1,Comment Excerpt 

Number 5. Also, the opacity standard applies on a daily block average basis, not a 3-hour basis.

Commenter Name: Michael L. Corvese

Commenter Affiliation: Thermo Fisher Scientific, Inc

Document Control Number: EPA-HQ-OAR-2002-0058-2997.1

Comment Excerpt Number: 11

Comment: section 63.7525(i)(j)(2) may impose inappropriate requirements or practices for 

BLDs in by requiring adherence to manufacturer’s recommendations and out dated EPA 

guidance. Recommend this section be revised or removed. 

The subject section states, “ 

(2) Each bag leak detection system must be installed, operated, calibrated, and maintained in a 

manner consistent with the manufacturer’s written specifications and recommendations and in 

accordance with the guidance provided in EPA–454/R– 98–015, September 1997. 

Unless EPA has reviewed and found the recommendations and specifications of all BLD 

manufacturer’s to be appropriate, it should not endorse or require their use. We believe some 

manufacturer’s recommendations are insufficient. Procedures that address source-specific 

applications may be superior. 

EPA’s only published guidance for setting BLD alarms (Fabric Filter Bag Leak Detection 

Guidance, EPA-454/R-98-015, September 1997) is out-of-date and applies to only one type of 

monitoring device and one type of fabric filter cleaning configuration. More general and up-to-
354

date guidance can be found in Appendix 2 to ASTM D7392-07 which applies to setting alarm 

levels for the full range of BLDs and fabric filter configurations that are encountered at cement 

kilns and kilns/in-line raw mills at plants that burn hazardous waste. EPA should update its 

published guidance to reflect various BLD designs and alarm procedures for the range of fabric 

filters and cleaning configurations. 

Response: The EPA BLD guidance addresses only one technology type for bag leak detectors. 

(There are several vendors that sell variations of the charge transfer technology.) However, 

proper setup and operation of a bag leak detector can vary with site-specific conditions and those 

conditions may dictate variances from the approach and is allowed by the guidance. The EPA 

has no reason to believe that the “Office of Air Quality Planning and Standards (OAQPS) Fabric 

Filter Bag Leak Detection Guidance" document needs updating or is inadequate. To date EPA 

has no information on any conflicts between the manufacturer’s specifications and the guidance 

document.

Commenter Name: Michael L. Corvese

Commenter Affiliation: Thermo Fisher Scientific, Inc

Document Control Number: EPA-HQ-OAR-2002-0058-2997.1

Comment Excerpt Number: 12

Comment: section 63.7525(i)(j)(3) requires manufactures to certify detection capabilities but 

fails to specify procedures or criteria. Recommend this section be revised or removed. 

The subject section states, 

“(3) The bag leak detection system must be certified by the manufacturer to be capable of 

detecting particulate matter emissions at concentrations of 10 milligrams per actual cubic meter 

or less.” 

There are no procedures or specifications for conducting tests to make this certification. This 

raises numerous questions. Are tests of the actual device required? Under what conditions are 

such tests to be conducted? How are other factors that affect BLD response such as measurement 

principle, flow velocity, actual and aerodynamic particle size, particle size distribution, particle 

density, dielectric constants, effluent conditions, etc. taken into account in this certification? Are 

the tests to be performed for each instrument or a particular model? Is the certification a one-time 

test or must it be repeated periodically? Can the certification be based simply on the judgment of 

the instrument developer without conducting any tests at all? There are no means available to the 

BLD user to verify claims made by the BLD vendor or manufacturer regarding detection 

capability. 

Response: The EPA has no reason to believe that the “Office of Air Quality Planning and 

Standards (OAQPS) Fabric Filter Bag Leak Detection Guidance" document needs updating or is 
355

inadequate. EPA has no knowledge that the QA procedures within the Bag Leak Detection 

Guidance is inadequate. Technical specifications, installation procedures, operation and 

maintenance procedures, quality assurance procedures, or alarm setting procedures are contained 

within the EPA guidance document for bag leak detectors and are supplemented in 

manufacturer’s specifications , installation procedures, and directions. EPA’s guidance for BLDs 

is not a certification procedure like performance specifications in Appendix B of Part 60 and 

therefore will not contain tests for certification. The bag leak detection system must be certified 

by the manufacturer and not the owner/operator to be capable of detecting particulate matter 

emissions at concentrations of 10 or fewer milligrams per actual cubic meter. The operator must 

consider any operational changes and stack gas changes when selecting an appropriate BLD. 

BLD setup procedures and BLD system adjustments found within EPA’s BLD guidance is 

sufficient for accounting for these changes. The EPA BLD guidance is applicable to charge 

transfer type devices but several different manufacturer’s instruments can be used that are 

applicable to this guidance. The EPA BLD guidance addresses only one suggested approach to 

the use of bag leak detectors. However, proper setup and operation of a bag leak detector can 

vary with site-specific conditions and those conditions may dictate variances from the approach 

suggested in this guidance.

Commenter Name: Paul N. Cicio

Commenter Affiliation: Industrial Energy Consumers of America

Document Control Number: EPA-HQ-OAR-2002-0058-2752.1

Comment Excerpt Number: 15

Comment: Operating Parameter Limits – Operating Parameter Limits must be established based 

on reasonable criteria and not solely based on values measured during the compliance test. 

EPA proposes that operating parameters measured during performance tests should constitute 

minimum site-specific operating requirements subsequent to the performance test. 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. 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 benefit 

to human health. 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 flow rates and high flue gas temperatures, the 

flow-rate of slurry will be relatively high. If this were established as a site-specific minimum 
356

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

low loads. One member company with solid-fuel fired boilers equipped with SDA’s 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 to the owner/operator (see Figure III-1 and III-2, of 

submittal). 

EPA should propose provisions for each site to propose reasonable operating parameter limits 

that are appropriate and specific to the pollution control equipment to ensure minimization of 

emissions. Such operating parameters should be based on ratios, such as pounds of sorbent per 

million actual cubic feet of flue gas flow for activated carbon injection systems, 

calcium-to-Sulfur ratio for scrubbers using lime or limestone to remove acid gases, liquid to gas 

ratios for wet scrubbers and power to gas ratios for electrostatic precipitators. 

Response: See the response to EPA-HQ-OAR-2002-0058-2635.1,Comment Excerpt Number 5.

Commenter Name: American Crystal Sugar Company and Michigan Sugar Company

Commenter Affiliation: Patricia Hansen and Steven Smock

Document Control Number: EPA-HQ-OAR-2002-0058-2970.1

Comment Excerpt Number: 16

Comment: The frequency of calibration for some operational monitors is excessively high. Most 

equipment is designed with greater stability than the requirement indicates. If the agency 

believes the frequency needs to be more than the manufacturer’s recommendation, it should 

provide the justification in the form of supporting studies showing calibration drift or similar 

issues. 

Response: See the response to EPA-HQ-OAR-2002-0058-1907.1, Comment Excerpt Number 

37.

Commenter Name: Bill Wemhoff

Commenter Affiliation: National Rural Electric Cooperative Association

Document Control Number: EPA-HQ-OAR-2002-0058-2835.1

Comment Excerpt Number: 25

Comment: Does not object to EPA’s general approach of using operating parameters to assure 

compliance in between stack tests. EPA has previously used this approach in the Compliance 

Assurance Monitoring (CAM) rule to assure continuous compliance with standards that do not 

already specify continuous compliance methods. Does object, however, to EPA’s proposed use 

of operating parameters as enforceable limits, and questions the achievability of the proposed 10 

percent opacity standard, particularly in the absence of any exception for startup, shutdown, or 
357

malfunction. Objects to several provisions related to proposed bag leak detection systems and the 

lack of clarity in EPA’s proposed requirements for periodic fuel analysis. 

Response: See the response to EPA-HQ-OAR-2002-0058-2635.1,Comment Excerpt Number 5. 

Other issues identified in this brief comment are addressed in the more specific concerns raised 

in other comments on the same general topic areas.

Commenter Name: Michael Hutcheson

Commenter Affiliation: Ameren Services

Document Control Number: EPA-HQ-OAR-2002-0058-2803.1

Comment Excerpt Number: 33

Comment: The use of operating limits based on average control device operating parameters 

during source testing is ill conceived and subjects sources to potential non-compliance periods 

for operation which do not affect emissions. 

Requiring sources to maintain control device operating parameters at a level equal to the average 

level achieved during compliance testing does not account for compliance margins or allow for 

normal variability in control device operating parameters or in measuring those parameters. US 

EPA should consider allowing sources to utilize control device operating curves developed by 

the manufacturer to set operating limits for the control devices based on expected control 

efficiencies. 

Response: See the response to EPA-HQ-OAR-2002-0058-2635.1,Comment Excerpt Number 5.

Commenter Name: Lee B. Zeugin

Commenter Affiliation: Utility Air Regulatory Group

Document Control Number: EPA-HQ-OAR-2002-0058-2880.1

Comment Excerpt Number: 34

Comment: UARG objects to EPA’s proposal to set enforceable operating limits based on 

control device parameters measured during performance testing. Establishment of such limits 

reduces operational flexibility, deprives sources of the use of any control device margin, and 

allows enforcement for events beyond the owner/operator’s control. 

EPA’s current proposal is based on the faulty assumptions that the values of the parameters 

identified by EPA have a direct relationship to the level of emissions, and that exceedances of 

those limits therefore indicate an exceedance of the emission limit as well. To the extent 

possible, source owners and operators will contract for control equipment that is designed to 

provide a “margin of compliance” with the applicable emission limitation.[ For example, it is 

relatively common for new ESPs to be purchased with extra fields and sections which will allow 

the source to continue to operate in compliance with applicable emission limits even when there 
358

are problems with other parts of the controls. Fabric filters and scrubbers can also be purchased 

with extra capacity (i.e., additional modules) for the same purpose.] In addition to reducing the 

possibility of an exceedance of the limit, this margin is intended to provide flexibility for the 

source to account for an inevitable control equipment or operational problem. Any source that is 

able to normally operate with a margin of compliance will loose part of that margin of 

compliance if they conduct performance testing under normal operations, because they will 

establish operating limits that would require them to continue to over-control forevermore. The 

only way such sources could avoid surrendering whatever margin of compliance they have 

would be to deliberately reduce performance of their controls to attempt to generate the least 

stringent operating limits consistent with achievement of the applicable emission standard. 

EPA’s proposal thus has the perverse result of encouraging sources to focus their attention on 

learning how to manipulate their operations to allow testing as close as possible to their emission 

limit by reducing performance of their controls. 

Unfortunately, even the “detuning” of a control device during performance testing will not 

ensure that the operating limits established during the test are reasonable, or necessary for 

achievement of the applicable emission limit. As EPA has previously recognized in the context 

of the NSPS and the CAM rule “many sources operate well within permitted limits over a range 

of process and pollution control device operating parameters,” and requiring sources to 

continuously maintain parameters that “happened to exist” during the most recent performance 

test may not be “possible or wise.” 62 Fed. Reg. 54,900, 54,907, 54,926-27. 

That is because control device parameters, such as those identified by EPA for scrubbers and 

ESPs, do not necessarily have a direct relationship to emissions, but instead are interrelated with 

the design of the control device and the interaction of various parameters. As a result, a single 

parameter may vary widely with little effect on emissions. See UARG Comments on Proposed 

National Emission Standards (Mar. 14, 2003), EPA-HQ-OAR-2002-0058-0413, Attachment C 

(incorporated by reference). For example, total ESP power may be completely unrelated to ESP 

performance for a multi-sectional ESP. Id. at 2 and Appendix 1. This power approach for ESPs 

simply does not work and that fact is easily demonstrated in the cited material. Similarly, 

because scrubber pressure drop and liquid flow rate are usually a function of boiler load, 

recording levels of those parameters above or below those recorded during a performance test are 

not necessarily indicative of emissions levels at a different load. Id at 2. Many industrial boilers 

operated at variable load levels because they follow process demand. As the load drops, the 

scrubber pressure drop also moves down. This change does not necessarily indicate a drop in 

scrubber performance. In fact, the scrubber performance is likely to improve at reduced load. 

Although EPA’s provision of a 10 percent difference from the average tested value recognizes 

some of the normal operational variability of control devices, it may not be sufficient in some 

circumstances. Without a clear correlation between such operating parameters and the applicable 

emission limit, imposition of those values as enforceable limits would unreasonably restrict 

source and control device operation and subject sources to potential enforcement without any 

evidence that an emission limits has been violated. 

Response: See the response to EPA-HQ-OAR-2002-0058-2635.1,Comment Excerpt Number 5.
359

Commenter Name: Lee B. Zeugin

Commenter Affiliation: Utility Air Regulatory Group

Document Control Number: EPA-HQ-OAR-2002-0058-2880.1

Comment Excerpt Number: 38

Comment: EPA’s proposal to require use of ESP parameters has similar flaws. Total ESP power 

input simply is not directly related to PM removal performance, particularly for the modern 

multi-section ESPs that are likely to be installed to comply with a proposed MACT. See UARG 

Comments on Proposed Reconsideration and Revision of New Source Performance Standards, 

EPA-HQ-OAR-2005-0031-0246 (Mar. 27, 2007) at 21-22, and Attachment 2 (incorporated by 

reference); UARG Comments EPA-HQ-OAR-2002-0058-0413, Attachment C, Appendix 1. 

Moreover, none of the ESP parameters are likely to have any relationship to PM at units that also 

have a wet scrubber, since those systems also are highly effective in controlling high levels of 

PM coming out of an ESP that is not performing at its intended control efficiency. See EPA-HQOAR-2005-0031-0246 at 15-16 and Attachment 2. 

Response: See the response to EPA-HQ-OAR-2002-0058-2635.1,Comment Excerpt Number 5.

Commenter Name: Lee B. Zeugin

Commenter Affiliation: Utility Air Regulatory Group

Document Control Number: EPA-HQ-OAR-2002-0058-2880.1

Comment Excerpt Number: 39

Comment: Under EPA’s proposal, units that use a wet scrubber must comply with operating 

limits for pH, pressure drop and liquid flow-rate; and units that use a dry scrubber must comply 

with an operating limit on sorbent injection rate. Proposed § 63.7530(b)(3)(i) and (iii). EPA’s 

proposal to use these parameters is subject to the same flaws as EPA’s other proposed operating 

limits -- namely the lack of a sufficient relationship between the parameters measured during 

performance testing and actual emissions. For example, as described above, because scrubber 

pressure drop, liquid flow rate, and sorbent injection rate vary with boiler load, establishment ofa 

limit based on conditions during performance testing may tell EPA little about actual emissions 

under other load conditions. Moreover, when EPA in 2008 considered the relationship between 

liquid flow rate and PM in the context of the NSPS for electric steam generating units at 40 

C.F.R. Subpart Da, EPA concluded that, at the level of the NSPS (i.e., 0.015 lb/mmBtu), PM 

emissions controlled by an ESP were not particularly sensitive to the actual liquid flow rate. 

EPA “Response to Public Comments on Rule Amendments Proposed June 12, 2008 (73 FR 

33642)” (Nov. 2008), EPA-HQ-OAR-2005-0031-0284, at § 2.5.3. 

Response: See the response to EPA-HQ-OAR-2002-0058-2635.1,Comment Excerpt Number 5.
360

Commenter Name: David M. Kiser

Commenter Affiliation: International Paper Company

Document Control Number: EPA-HQ-OAR-2002-0058-2777.1

Comment Excerpt Number: 40

Comment: EPA should not prescribe a calibration frequency for pH monitors. 

40 CFR 63.7525(g)(3) requires pH meter calibration on at least two data points every 8 hours of 

process operation. Manufacturers of pH probes for industrial service do not specify a calibration 

frequency because their monitors can be used in various process applications therefore making 

the calibration frequency very application specific. As stated by one of our pH probe vendors 

(SENSOREX Corporation), “The frequency of calibration is really determined by experience”. 

International Paper recommends that the calibration frequency be based on the site specific 

application and calibration history. Calibrations should be conducted at a frequency that 

historically demonstrates a pattern of stability; calibrations more often than that should not be 

required. For new installations, the calibration could be checked at the frequency specified in the 

proposed rule. As a pattern of longer stability is found, the time between calibrations checks 

should be increased until a stable pattern is established. 

Response: See the response to EPA-HQ-OAR-2002-0058-1907.1, Comment Excerpt Number 

37.

Commenter Name: Lee B. Zeugin

Commenter Affiliation: Utility Air Regulatory Group

Document Control Number: EPA-HQ-OAR-2002-0058-2880.1

Comment Excerpt Number: 42

Comment: Rather than establish enforceable operating limits, EPA should use the approach 

taken in the CAM rule and require sources to establish site-specific operating parameter ranges 

to define conditions under which compliance with the applicable limit can be reasonably assured. 

This approach already has been upheld as sufficient to satisfy the CAA’s requirements for 

demonstrating continuous compliance. See NRDC v. EPA, 194 F.3d 130, 135-37 (D.C. Cir. 

1999) (rejecting NRDC’s argument that the CAM rule’s “reasonable assurance of compliance” is 

not sufficient to assure continuous compliance as required by the CAA). Source owners and 

operators would then be required to monitor those parameters and respond to changes that 

indicate problems with the controls that could jeopardize compliance. 

Whether using a single control device or combination of devices, sources are in the best position 

to determine what parameters and levels are consistent with compliance. In many cases, multiple 

parameter relationships or supplemental operational data will provide a higher level of 

compliance assurance than the level that happens to be measured during a discrete performance 

test. This is particularly true for sources with a significant margin of compliance. EPA-HQOAR2002-0058-0413, Attachment C at 4. In addition, units with significant margins of compliance 
361

should be allowed to establish operating levels by extrapolating parameter data beyond that 

obtained during a performance test based on other information. Allowing such extrapolations is 

essential for some sources to provide needed operational flexibility. Attempting to establish 

“worst case” test conditions on a scrubber or multi-section ESP, where the possible combinations 

of parameters are numerous, would at the least be difficult and could be impossible without a 

major research effort. Id. Allowing extrapolation of results avoids the necessity of repeated 

testing.[ 28 A similar approach has been used in CAM protocols, including a protocol developed 

by the Electric Power Research Institute for ESPs (allowing extrapolation up to 1.25 times the 

recorded value for measurements taken at less than 80 percent of the applicable emission limit).] 

Once sources have established appropriate operating parameter ranges based on data collected 

during performance tests, as well as other operating data and engineering principles, those 

parameters would be monitored and any deviation from them would trigger a requirement for 

investigation and corrective action to return the parameter to the appropriate range. Although this 

range may in some cases be similar to the minimum values that would be established under 

EPA’s proposed rule, allowing sources to respond with corrective action (rather than simply 

record exceedances and report deviations) achieves EPA’s intended result without subjecting 

sources to potential unreasonable enforcement. 

Response: See the response to EPA-HQ-OAR-2002-0058-2635.1,Comment Excerpt Number 5.

Commenter Name: Lee B. Zeugin

Commenter Affiliation: Utility Air Regulatory Group

Document Control Number: EPA-HQ-OAR-2002-0058-2880.1

Comment Excerpt Number: 44

Comment: Under EPA’s proposal, units that use a fabric filter (whether or not using a wet 

scrubber) that choose to demonstrate continuous compliance using a BLDS (instead of 

monitoring opacity) must install, operate, calibrate and maintain a BLDS “for each exhaust stack 

of the fabric filter” consistent with the “manufacturer’s written specifications and 

recommendations” and in accordance with EPA’s “Fabric Filter Bag Leak Detection Guidance,” 

EPA-454/R-98-015 (Sept. 1997). Proposed 63.7525(j). The BLDS must be certified by the 

manufacturer to be capable of detecting PM at a concentration of 10 milligrams per actual cubic 

meter or less. Id. The BLDS must be operated such that the “system alarm does not sound more 

than 5 percent of the operating time during any 6-month period.” Proposed § 63.7530(b)(3)(iv). 

Records must be kept of each alarm period. If inspection of the bag demonstrates that no 

corrective action is required, no alarm time is counted. If corrective action is required, the alarm 

time is counted as the actual time taken to initiate corrective action with a minimum of 1 hour 

counted for each alarm. Proposed § 63.7540(a)(7). In short, EPA largely proposes to simply 

repromulgate the BLDS requirements from the 2004 final rule. When UARG questioned several 

aspects of that rule as proposed, see UARG Comments, EPA-HQ-OAR-2002-0058-0413 at 24, 

EPA simply referred back to its 1997 guidance. See EPA Response to Public Comments, EPAHQ-OAR2002-0058-0611 at 114. 
362

The proposed requirement to follow all manufacturer specifications and recommendations and 

EPA’s 1997 guidance is not reasonable. With respect to manufacturer requirements, EPA has not 

reviewed these procedures and cannot assure that a particular manufacturer’s installation, 

operation, and adjustment procedures will be compatible with the proposed or final regulatory 

requirements. Manufacturers may have written recommendations that are suitable for some 

applications and are not suitable for other applications. Many of the manufacturers also are 

foreign entities that rely on other companies to represent their products in different countries and 

develop written “recommendations.” The source owner or operator is responsible for the 

selection, installation, operation, and maintenance of the monitoring equipment. While 

manufacturer’s specifications and recommendations may be useful to a source owner/operator’s 

understanding of the equipment, they are not necessarily appropriate regulatory requirements. 

EPA has offered no data to demonstrate that any BLDS will work as the manufacturer claims. 

EPA’s guidance also has no place as a regulatory requirement. EPA’s guidance addresses only 

one type of BLDS (the “triboelectric”) and is based on information provided by a single 

manufacturer. The definition of BLDS clearly allows use of a variety of technologies, including 

electrodynamic, light scattering, and light transmittance. Proposed § 63.7575. The guidance 

explains that the alarm setting procedure is dependent on the type and configuration of the fabric 

filter and filter cleaning cycle. But it addresses only one baghouse configuration. The document 

excludes all other technologies (e.g., light scattering, light transmission, optical scintillation, and 

electro-dynamic devices). In short, the existing Guidance Document is out of date and is 

technically flawed. 

Response: The EPA has no reason to believe that the “Office of Air Quality Planning and 

Standards (OAQPS) Fabric Filter Bag Leak Detection Guidance" document needs updating or is 

inadequate. EPA has no knowledge that the QA procedures within the Bag Leak Detection 

Guidance is inadequate. Technical specifications, installation procedures, operation and 

maintenance procedures, quality assurance procedures, or alarm setting procedures are contained 

within the EPA guidance document for bag leak detectors and are supplemented in 

manufacturer’s specifications , installation procedures, and directions. Performance 

specifications and quality assurance procedures found in Appendix B and F, respectively, of Part 

60 are for the purpose of certifying a CEMS and for continual quality assurance for CEMS that 

are used for continual compliance with an emission limit and therefore are not applicable to 

BLDs. False alarms and instrument malfunctions or misapplication of BLDs is a site specific 

issue and can be averted by careful selection of an appropriate BLD and manufacturer with a 

vendor guarantee of acceptable performance. EPA’s guidance for BLDs is not a certification 

procedure like performance specifications in Appendix B of Part 60 and therefore will not 

contain tests for certification. The bag leak detection system must be certified by the 

manufacturer and not the owner/operator. The operator must consider any operational changes 

and stack gas changes when selecting an appropriate BLD. BLD setup procedures and BLD 

system adjustments found within EPA’s BLD guidance is sufficient for accounting for these 

changes. The EPA BLD guidance is applicable to charge transfer type devices but several 

different manufacturer’s instruments can be used that are applicable to this guidance. The EPA 

BLD guidance addresses only one suggested approach to the use of bag leak detectors. However, 
363

proper setup and operation of a bag leak detector can vary with site-specific conditions and those 

conditions may dictate variances from the approach suggested in this guidance. 

Commenter Name: Lee B. Zeugin

Commenter Affiliation: Utility Air Regulatory Group

Document Control Number: EPA-HQ-OAR-2002-0058-2880.1

Comment Excerpt Number: 45

Comment: According to the preamble, EPA intends to propose (1) that units with wet scrubbers 

and an ESP and/or fabric filter establish and comply with ESP operating parameters and/or a 

BLDS, and (2) that units without a wet scrubber comply with an opacity standard, unless they 

have a fabric filter, in which case they must use a BLDS. 75 Fed. Reg. at 32,013-14. In other 

words, (1) a source with an ESP without a wet scrubber would not have the option of monitoring 

ESP parameters in lieu of opacity, (2) a unit with a fabric filter without a wet scrubber would not 

have the option of monitoring opacity in lieu of a BLDS, and (3) a unit without a wet scrubber 

that has an ESP and a fabric filter would only use a BLDS. However, that is not what the 

proposed rule language requires. 

First, the rule clearly provides that use of a BLDS if optional, at least for a unit with a dry control 

system. Proposed §§ 63.7525(j)(“[i]f you elect to use a fabric filter bag leak detection system”), 

63.7530(b)(3)(iv) (“[t]he operating limit for boilers or process heaters with fabric filters that 

choose to demonstrate compliance through bag leak detection systems”); 63.7540(a)(7) (“[i]f 

your unit is controlled with a fabric filter, and you demonstrate continuous compliance using a 

[BLDS]”), Table 4 (establishing an opacity option for units that operate dry control systems) 

(emphasis added). Second, the rule appears in one place to require all units with an ESP to 

establish minimum voltage and secondary current (or total power), but in other parts clearly 

limits use of ESP operating parameters to units with wet scrubbers. Proposed § 63.7530(b)(3)(ii) 

(“[f]or an [ESP] you must establish the minimum voltage and secondary current (or total power 

input”), Table 4 (“option only for [units] that operate additional wet control systems”), and Table 

7 (“option only for units with additional wet scrubber control”). Third, the rule does not reflect 

any exemption from opacity monitoring for units with a fabric filter and a BLDS. Proposed 

Table 4 (requiring for an ESP either an opacity standard for dry control systems, or ESP 

parameters for wet control systems). In short, not only does the preamble conflict with the rule, 

the rule itself is internally inconsistent. 

UARG understands that units with wet control systems cannot monitor opacity and as a result 

must use some other technique. As a result, for units with wet scrubbers, UARG supports the use 

of ESP parameters as indicator monitoring as described in section D.2. However, if such 

parameters are sufficient for units with wet scrubbers, UARG does not understand why they also 

would not be sufficient for units with dry controls. As a result, EPA should remove the rule 

language restricting use of ESP parameters to units with wet controls and offer source 

owners/operators the choice. For units with fabric filters, EPA should revise its preamble to be 

consistent with the proposed rule, which clearly allows fabric filter equipped units with dry 

control systems the choice of using opacity instead of a BLDS. EPA also should revise proposed 
364

§ 64.7530(b)(3)(ii) to make clear that units complying with an opacity standard do not have to 

establish ESP operating parameters. 

Response: The lack of an opacity standard option for units controlled with a fabric filter is 

intentional as EPA does not consider opacity to be a strong operating standard for ensuring 

continued operation of a fabric filter in conformance with the conditions achieved during the 

most recent performance test demonstrating compliance with the emission limit. For an ESP 

without a wet scrubber, EPA does consider it appropriate to allow for opacity or ESP power 

parameters to be used for ensuring continuous compliance. The final rule reflects these 

adjustments.

Commenter Name: Traylor Champion

Commenter Affiliation: Georgia-Pacific LLC

Document Control Number: EPA-HQ-OAR-2002-0058-2745.1

Comment Excerpt Number: 52

Comment: The re-calibration requirement for flow sensors and pressure gauges should be 

annually or at the frequency specified by the manufacturer. 

In the proposed rule [§63.7525(e)(4)], EPA would require that flow meters be recalibrated twice 

a year. In order to properly calibrate a flow meter to a scrubber, for example, it must be taken 

off-line, which would mean that the boiler and scrubber would need to be shut down. This would 

be extremely burdensome for pulp and paper and wood product facilities. Most industrial boilers 

are taken out of service only on an annual basis for major maintenance and insurance 

inspections. The calibration of flow meters and other CPMS could be coordinated with this 

annual shutdown without loss of production. 

Manufacturers of some types of flow meters such as magnetic flow meters or coriolis meters 

recommend re-calibration on a less frequent basis- typically every three years. These meters are 

extremely stable and do not need to be calibrated as frequently as other devices. EPA recognized 

this in its Mandatory Reporting of Greenhouse Gases final rule [40 CFR Part 98]. At 40 CFR 

98.34(b)(1)(C)(ii), the Agency requires that Tier 3 oil and gas meters be recalibrated “....either 

annually, at the minimum frequency specified by the manufacturer or the interval specified by 

the industry consensus standard practice used.” EPA should be consistent in this Boiler MACT 

rule. 

Response: See the response to EPA-HQ-OAR-2002-0058-1907.1, Comment Excerpt Number 

37.

Commenter Name: Christopher S. Colman

Commenter Affiliation: Hovensa LLC
365

Document Control Number: EPA-HQ-OAR-2002-0058-2863.1

Comment Excerpt Number: 53

Comment: Proposed Rule Language §63.7525(d)(4): 

“You must determine the 3-hour block average of all recorded readings, except as provided in 

paragraph (c)(3) of this section.” 

Comments: 

Section 63.7525(d) provides the requirements for installation and operation of each continuous 

parameter monitoring system (CPMS). As defined in Table 8 of the proposed rule, the 

compliance with operating limits shall be demonstrated by reducing the parameters to 12-hour 

block averages. Therefore, the averaging period for CPMS should be based on 12-hour block 

average for all recorded readings. 

Response: The 3-hour reference has been corrected in the final rule.

Commenter Name: Traylor Champion

Commenter Affiliation: Georgia-Pacific LLC

Document Control Number: EPA-HQ-OAR-2002-0058-2745.1

Comment Excerpt Number: 53

Comment: The re-calibration requirement for pressure gauges should be annually or at the 

frequency specified by the manufacturer 

In the proposed rule [§63.7525(f)(5)], EPA would require that all pressure gauges be calibrated 

quarterly and transducer calibrations monthly. Similar to flow meters, to properly calibrate a 

pressure transmitter, it must be taken off-line, which would mean that the boiler and scrubber 

would need to be shut down. This would be extremely burdensome for pulp and paper and wood 

product facilities. Most industrial boilers are taken out of service only on an annual basis for 

major maintenance and insurance inspections. The calibration of flow meters and other CPMS 

could be coordinated with this annual shutdown without loss of production 

Response: See the response to EPA-HQ-OAR-2002-0058-1907.1, Comment Excerpt Number 

37.

Commenter Name: Traylor Champion

Commenter Affiliation: Georgia-Pacific LLC

Document Control Number: EPA-HQ-OAR-2002-0058-2745.1

Comment Excerpt Number: 54

Comment: It is unnecessary to check pressure taps daily for pluggage 

In the proposed rule [§63.7525(f)(4)], EPA would require that all pressure taps be checked for 

pluggage daily. This is an unnecessary burden on an industrial facility – there are other, more 
366

practical, methods available for assuring that pressure taps are not plugged. If a pressure tap 

becomes plugged, the reading on the instrument will either drop to zero or will cause the output 

to be unresponsive to process changes, in other words the output will “straight line” rather than 

move in response to normal process variation. To assure that instruments are reading properly, 

EPA could require that each facility inspect the output from each monitoring system daily to 

assure that the system is functioning properly. The Agency promulgated a similar approach for 

the NESHAP for Chemical Recovery Combustion Sources at Kraft, Soda, Sulfite and StandAlone Semichemical Pulp Mills [see 40 CFR 63.866(a)(2)(ii)]. 

Response: See the response to EPA-HQ-OAR-2002-0058-1907.1, Comment Excerpt Number 

37.

Commenter Name: Traylor Champion

Commenter Affiliation: Georgia-Pacific LLC

Document Control Number: EPA-HQ-OAR-2002-0058-2745.1

Comment Excerpt Number: 55

Comment: The calibration procedures for pH monitors must be made more reasonable. In the 

proposed rule [§63.7525(g)(3)], EPA would require that pH monitor calibrations be performed 

on two points every 8 hours. In some instances it is 

difficult to remove an in-line pH sensor from the process. EPA should include an option of 

taking a sample of the process fluid back to the laboratory to be measured using a calibrated, 

temperature compensated pH meter to verify the reading of the in-line device. 

Industrial pH meters are stable over a longer period than 8 hours and need not be 

calibrated on such a short frequency. This is also burdensome on a facility since 

this would require a trained instrument technician to perform the calibration, and many facilities 

(especially smaller wood products plants such as a sawmill) do not have instrument technicians 

available on a 24-7 basis. 

In an earlier EPA proposal [Performance Specifications and Quality Assurance 

Requirements for Continuous Monitoring Parameters and Amendments to Standards of 

Performance for New Stationary Sources; National Emission Standards for Hazardous Air 

Pollutants for Source Categories, 73 Federal Register 59956 (October 9, 2008)] the Agency 

proposed that calibrations of pH meters be done weekly. This is standard practice at GP 

locations. 

Response: See the response to EPA-HQ-OAR-2002-0058-1907.1, Comment Excerpt Number 

37.

Commenter Name: Lee B. Zeugin
367

Commenter Affiliation: Utility Air Regulatory Group

Document Control Number: EPA-HQ-OAR-2002-0058-2880.1

Comment Excerpt Number: 59

Comment: Proposed § 63.7525(e),(f),(g),(h)and(i) provide criteria for selection, installation, and 

quality assurance of any required “flow measurement device,” “pressure measurement device,” 

“pH measurement device,” voltage and secondary amperage (for total power input) monitoring 

equipment, and sorbent injection monitoring equipment. 75 Fed. Reg. at 32,056. On October 9, 

2008, EPA proposed PS 17 and amendments to the Part 63 general provisions to address 

selection and installation of CPMS and ongoing quality assurance of data from CPMS (in 

Procedure 4). 73 Fed. Reg. 59,956 (Oct. 9, 2008). Proposed PS 17/Procedure 4 covers CPMS 

used to measure and record temperature, pressure, liquid flow rate, gas flow rate, mass flow rate, 

pH, or conductivity on a continuous basis. UARG submitted detailed comments objecting to 

several aspects of EPA’s proposal, including EPA’s proposal to make the final specifications 

applicable in lieu of requirements in the individual Part 63 subparts, without any revision of 

those subparts to consider or reference applicability of the new requirements. UARG Comments, 

EPA-HQ-OAR-2006-0640-0064 (Feb. 5, 2009) (incorporated by reference). Although EPA has 

since indicated in its regulatory agenda its intention to issue a supplemental proposal to address 

comments received on that proposal, EPA has not withdrawn its prior proposal. As a result, 

UARG continues to object to EPA’s proposed approach and to any automatic applicability of 

additional requirements to this rule without subsequent proposal and revision of this rule. EPA 

has adequate opportunity to propose whatever performance specifications it deems appropriate in 

this rulemaking. 

Response: The Agency acknowledges the commenter's concerns on the continuous parameter 

monitoring system performance specifications and quality assurance procedures proposal, but 

notes that this action is for the Boiler MACT proposal. The Agency agrees with the commenter 

that the Agency is able to propose appropriate performance specifications in this and any other 

rulemaking. In keeping with this ability, the Agency developed and proposed specific 

requirements for performance specifications for this rule, allowing source owners or operators to 

develop plans customized for their sites. Source owners or operators are encouraged to build on 

their existing practices, rather than start from scratch, to minimize the burden associated with 

providing a continuous assurance of compliance as required by the statute.

Commenter Name: Traylor Champion

Commenter Affiliation: Georgia-Pacific LLC

Document Control Number: EPA-HQ-OAR-2002-0058-2745.1

Comment Excerpt Number: 63

Comment: GP believes that secondary voltage is more indicative of precipitator performance 

Secondary voltage and current or total power have been traditionally used to monitor ESP 

performance and, in fact, provide a good measure of how much “work” the ESP is doing in terms 

of transfer of electrostatic charge to particles in the gas stream. However, these indicators 
368

provide relevant emissions information only to the extent that parameters such as particle loading 

to the ESP, particle size, particle resistivity, gas temperature, gas moisture content, etc. remain 

constant. Changes in these particle and gas parameters will often result in changes in measured 

secondary current and calculated total power that do not reflect the ESP’s emission rate. 

This is especially problematic for units with highly variable steam loads and/or highly variable 

fuels such as the combination fuel boilers at pulp & paper mills or the hogged fuel boilers at 

building products facilities. When monitoring secondary voltage/amperage or total power for 

these type boilers against a parameter operating limit set during a high steam load/worst-case 

fuel test, GP has often seen reduced secondary amperage and total power when the boiler is 

operating under more routine conditions. This can give the appearance of a deviation from the 

parameter operating limit when the unit is, in fact, operating at a significantly lower emission 

rate. 

Secondary voltage alone, however, tends to provide more reliable tracking of ESP emissions 

performance with higher total secondary voltage correlating well with higher ESP performance 

and lower emission rates. Since higher ESP inlet loading tends to increase spark rate triggering 

automatic voltage controls to reduce secondary voltage applied to the ESP’s discharge 

electrodes, a high steam load/worst case fuel test will typically yield a minimum total secondary 

voltage parameter. Operation under less challenging conditions will typically be reflected in 

lower inlet loading to the ESP, fewer sparks, higher total secondary voltage, and lower 

emissions. 

Vendors of electrostatic precipitators agree with GP’s assessment 

We have reviewed these issues with one of our primary ESP vendors, PPC Industries, and PPC’s 

Chief Engineer has confirmed our experience on this issue in a letter shown in Appendix C of the 

submittal. Excerpts from the PPC letter are reproduced below: 

“Secondary voltage alone is a much better parameter, since it is a direct 

measure of the potential between the charging electrode and the grounded electrode. Secondary 

milliamps [current] are relatively unimportant as long as 

enough electrons are present to insure charging.” 

?“Another reason to use secondary voltage only as the monitoring parameter is because it is the 

main driving force in the separation of the dust particles from the flue gas stream....Obviously, 

the higher the voltage the stronger the 

particles are attracted to the grounded electrode. For this reason, the precipitator’s automatic 

voltage control system is designed to constantly drive secondary voltage to the highest 

sustainable level in order to optimize performance.” 

“In the case of milliamps [current], we need only enough current flow to provide sufficient 

electrons to charge the incoming particles....As a matter of fact, high current is undesirable since 

the precipitator generates ozone and the unused electrons are simply parasitic load.” 

GP urges EPA to allow for the use of total secondary voltage (defined as the sum of the 

secondary voltage recorded for each of the ESP’s electrical fields) 

instead of total power as an operating parameter limit to be established during the initial 

performance test. While this could be accomplished via a request to EPA for approval of 

alternative monitoring, amendment of the proposed rule to explicitly allow for this option would 

be a far more efficient resolution. 
369

Response: As a general rule, ESP performance improves as total power input increases. This

relationship is true when particulate matter and gas stream properties (such as PM concentration, 

size distribution, resistivity, and gas flow rate) remain stable and all equipment components 

(such as rappers, plates, wires, hoppers, and transformer-rectifiers) operate satisfactorily. In an 

ESP with many fields, the power distribution also plays a key role in the performance of the 

ESP, and monitoring should be by field. The secondary voltage drops when a malfunction, such 

as grounded electrodes, occurs in the ESP. When the secondary voltage drops, less particulate is 

charged and collected. Also, the secondary voltage can remain high but fail to perform its 

function if the collection plates are not cleaned, or rapped, appropriately. If the collection plates 

are not cleaned, the current drops. Thus, since the power is the product of the voltage and the 

current, monitoring the power input will provide a reasonable assurance that the ESP is 

functioning properly. In other words, problems that would be detected by monitoring other 

parameters individually also will be manifested in the power input. If the commenter can 

demonstrate that the secondary voltage alone can identify issues with poor performance of 

collection plates, then the commenter may submit a request for an alternative monitoring 

approach as noted in the comments.

Commenter Name: Lee B. Zeugin

Commenter Affiliation: Utility Air Regulatory Group

Document Control Number: EPA-HQ-OAR-2002-0058-2880.1

Comment Excerpt Number: 69

Comment: To reduce manpower requirements most sources will likely attempt to automate as 

much of the reporting and record keeping as possible. The equipment costs alone for 

implementing an automated (to the extent possible) data collection and report generation system 

for a unit with multiple controls is likely to be very high and there may be little opportunity for 

standardization of the software. In short, UARG does not believe that EPA, in proposing its 

enforceable operating limit approach, has adequately estimated or considered the data 

management costs of its proposal and requests that the Agency do so. 

Response: EPA uses a cost model to estimate monitoring costs for its rules that include the full 

lifecycle of monitoring, including reporting and recordkeeping.

Commenter Name: Jim Griffin

Commenter Affiliation: American Chemistry Council

Document Control Number: EPA-HQ-OAR-2002-0058-2792.1

Comment Excerpt Number: 161

Comment: The proposed rule is inconsistent in the averaging times specified for operating 

parameters. The body of the rule specifies 3-hour parameter averages while Table 8 specifies 12-

hour block averages be calculated for CPMS. Where a COMS is used, a daily block average is 

specified. We support daily block averages for CPMS as well. A 24-hour averaging period 
370

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. 

Response: Parameter monitoring is generally on a 12-hour basis, except for opacity which 

remains on a daily block average basis.

Commenter Name: Jim Griffin

Commenter Affiliation: American Chemistry Council

Document Control Number: EPA-HQ-OAR-2002-0058-2792.1

Comment Excerpt Number: 163

Comment: The CPMS QA/QC Requirements are not Appropriate. Quality Assurance (QA) 

procedures for Continuous Parameter Monitoring Systems (CPMS) are best defined and 

implemented by the owner/operator of each CPMS. Preventative maintenance and sensor 

calibration for both process and control device monitoring is oftentimes accomplished during an 

annual outage, with some sensors only needing calibration once every 5 years. We believe that a 

more appropriate requirement is for sources to develop site-specific CPMS QA plans that are 

self-implemented and maintained on site for inspections and audits. Utilizing facility specific 

information to develop a QA Plan will ensure that unnecessary and arbitrary calibration 

frequencies do not result in either a potential safety incident or environmental releases during the 

accuracy audits. 

Today’s state-of- the-art sensors and electronic transmitters, power supplies, etc. do not require 

the repeated checks and inspections proposed. In addition, newer digital communications 

technologies can incorporate advanced sensor diagnostics, reducing the need for labor intensive 

field inspections. Facilities have learned through experience what sensors and CPMS system 

components perform best in their environment. Although we do not believe that this information 

should drive EPA to require state of the art equipment, we do believe that the range of equipment 

in use by industry necessitates a site-specific approach to a QA/QC program. 

The establishment of fixed calibration intervals, as EPA proposes, is contrary to standard 

metrology practice. NCSL International, an ANSI-accredited consensus standards developer for 

metrology standards, has a long-established Recommended Practice for determination of 

appropriate calibration intervals for measurement systems. This Practice recognizes that 

calibration intervals need not (in fact, must not) be set at arbitrary, fixed intervals to achieve 

acceptable data quality. The National Institute of Standards and Technology, the U.S. 

government agency concerned with the quality and reliability of measurement data, does not 

require fixed calibration intervals. Other U.S. government agencies such as NASA also do not 

require fixed calibration intervals. Acceptable calibration intervals are based on past experience 

and failure rates. Using this approach, calibration intervals can be determined that provide the 

required data quality at the least cost. This reliance on fixed interval QA/QC checks seems to be 

a remnant of the Agency’s initial promulgation of Appendix F about a quarter century ago. At 

that time, Appendix F applied to CEMS – a fairly new technology at that time. Many of these 

early instruments suffered from drift, non-linearity, and other performance issues that required 
371

frequent checks. Computerized control was virtually unknown. Today’s instruments are 

generations away from those early CEMS. They are stable, rugged, and reliable. EPA should 

develop a QA/QC rule that acknowledges the complex instruments in use today. 

The QA/QC process is not intended to detect failures. In most cases, failure of a sensor or other 

measurement system component is immediately recognizable in the data itself. One knows that a 

thermocouple has failed if the thermal oxidizer is operating and the temperature is reported as -

20 °F. One does not need a QA/QC check to detect the failure. The QA/QC process is designed 

to correct drift, biases, and other more subtle data quality issues. Most of the reliability issues 

that the QA/QC process is designed to correct are known and predictable and therefore can be 

taken into account when establishing calibration intervals. 

A flexible calibration interval does not imply an arbitrary calibration interval. Proper calibration 

intervals are established by experience. This experience may come from other systems installed 

at the source, from known failure rates of system components, from vendors, or from 

installations at similar facilities. Also, initial calibration intervals are not fixed, they are adjusted 

based on experience. As an example, if a system on a yearly check cycle is failing, that cycle 

should be reduced to once every six months. If a system is consistently passing a six-month 

QA/QC check, that check may be increased to annual. 

Response: See the response to EPA-HQ-OAR-2002-0058-1907.1, Comment Excerpt Number 

37.

Commenter Name: Jim Griffin

Commenter Affiliation: American Chemistry Council

Document Control Number: EPA-HQ-OAR-2002-0058-2792.1

Comment Excerpt Number: 164

Comment: Semi-Annual Flow Sensor Calibration Check Is Not Always Necessary. Some flow 

sensors only need calibration once every 5 years and some flow meters are calibrated by the 

manufacturer and cannot be calibrated in the field. For some flow tubes, there is nothing to wear 

or break, so frequent calibration is not needed. Calibration is only accomplished by removing the 

flow tube and sending it offsite, so this can only be done during a scheduled shutdown of a unit, 

which does not typically happen on a semi-annual basis. Recalibrations should be done at the 

unit’s normal maintenance shutdown frequency since electronic flow sensors do not drift and it 

may not be possible to take devices out of service for calibration without adversely affecting 

operation. Historical calibration data has proven that the manufacturer’s recommended 

frequencies for calibration are more than adequate to ensure accuracy. 

Response: See the response to EPA-HQ-OAR-2002-0058-1907.1, Comment Excerpt Number 

37.
372

Commenter Name: Jim Griffin

Commenter Affiliation: American Chemistry Council

Document Control Number: EPA-HQ-OAR-2002-0058-2792.1

Comment Excerpt Number: 165

Comment: Checking Pressure Tap Pluggage Daily, Pressure Gauge Calibration Quarterly And 

Transducer Calibration Monthly Are Onerous Requirements. These are extremely onerous 

requirements and do not reflect common practice or experience in industrial applications. 

Electronic devices experience very little drift, and calibrations at least annually would be more 

than adequate unless specific applications are shown to experience problems. Some pressure 

sensors only need calibration once every 5 years. OSHA considers annual testing of 

instrumentation to be adequate for most critical safety interlock applications. There is no reason 

to calibrate (audit and inspect) CPMS systems 4-12 times as often. Even the CEM performance 

specifications do not require inspections and calibrations as often as the proposed rule. 

Response: See the response to EPA-HQ-OAR-2002-0058-1907.1, Comment Excerpt Number 

37.

Commenter Name: Jim Griffin

Commenter Affiliation: American Chemistry Council

Document Control Number: EPA-HQ-OAR-2002-0058-2792.1

Comment Excerpt Number: 166

Comment: Proposed Requirement To Conduct Calibration Checks Any Time The Sensor 

Exceeds The Manufacturer’s Specified Maximum Operating Pressure Range Or Install A New 

Pressure Sensor Is Not Justified. ACC believes that this requirement is not justified. Calibration 

or replacement should only be required if the instrument’s reading is suspect. 

Response: See the response to EPA-HQ-OAR-2002-0058-1907.1, Comment Excerpt Number 

37.

Commenter Name: Jim Griffin

Commenter Affiliation: American Chemistry Council

Document Control Number: EPA-HQ-OAR-2002-0058-2792.1

Comment Excerpt Number: 167

Comment: It Is Not Always Necessary To Check A Ph Meter’s Calibration On At Least Two 

Points Every 8 Hours Of Process Operation. The length of time to check the calibration of a pH 
373

meter is entirely site specific. The proposed frequency is excessive, as most facilities calibrate 

pH meters weekly, especially if they are not exposed to a corrosive environment. One set 

frequency for all instruments regardless of the sophistication of the instrument and regardless of 

the service environment for the instrument is not appropriate. In other words, one size does not 

fit all. Autocalibration systems are available for around $30,000 per application, which adds to 

the already significant control, testing, and monitoring costs for this rule if this requirement is 

retained. 

Response: See the response to EPA-HQ-OAR-2002-0058-1907.1, Comment Excerpt Number 

37.

Commenter Name: Jim Griffin

Commenter Affiliation: American Chemistry Council

Document Control Number: EPA-HQ-OAR-2002-0058-2792.1

Comment Excerpt Number: 168

Comment: EPA should allow facilities to establish site-specific QA/QC plans for CPMS that 

take their specific operating conditions into account and establish the appropriate inspection and 

calibration intervals for each type of monitoring device. 

Response: See the response to EPA-HQ-OAR-2002-0058-1907.1, Comment Excerpt Number 

37.

Commenter Name: Jim Griffin

Commenter Affiliation: American Chemistry Council

Document Control Number: EPA-HQ-OAR-2002-0058-2792.1

Comment Excerpt Number: 176

Comment: FACILITIES NEED MORE FLEXIBILITY IN DEVELOPMENT OF OPERATING 

PARAMETER LIMITS. The proposed rule requires development of operating parameter limits 

(OPLs) based on the values achieved during the performance test. In many cases, these levels 

will be appropriate only for certain modes of operation. For example, the absolute sorbent 

injection rate observed during the performance test conducted under full load will not correlate to 

the sorbent injection rate necessary during startup or periods of lower load. Frequently, sorbent 

injection rates are set using a feedback loop from a CEMS or CPMS to avoid wasting sorbent. 

EPA should allow more flexible approaches to set operating limits, acknowledging that operating 

parameters can vary with operating conditions such as load and fuel quality. 

Response: See the response to EPA-HQ-OAR-2002-0058-2635.1,Comment Excerpt Number 5.
374

Commenter Name: Jim Griffin

Commenter Affiliation: American Chemistry Council

Document Control Number: EPA-HQ-OAR-2002-0058-2792.1

Comment Excerpt Number: 178

Comment: Waiver of OPLs is Needed During Stack Testing. We are concerned that the ongoing 

testing requirements in the proposed rule will result in a continual ratcheting down of OPLs 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 

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, Subpart EEE 

for Hazardous Waste Combustors, allow for a waiver of the operating limits during stack testing 

(see 63.1207(h)) and we believe this should be included in the final rule. 

WHERE FACILITIES USE CEMS, OPERATING PARAMETER MONITORING IS NOT 

NECESSARY. EPA should incorporate flexibility into the final rule for facilities using CEMS 

that are either required by the rule or installed for compliance monitoring. For example, the final 

rule should clarify that when PM CEMS are installed and the facility is using a wet scrubber for 

PM control, scrubber parameter monitoring is not necessary. Sources using PM CEMS should 

also not be subject to an opacity limit or required to install COMS. For sources using SO2 CEMS 

that have acid gas controls, scrubber parameter monitoring would not be necessary if the control 

device captures both HCl and SO2. Low SO2 emissions or high SO2 removal would indicate low 

HCl emissions since HCl is preferentially treated before SO2, so the SO2 concentration or 

removal percentage could be used as a surrogate parameter to ensure compliance with the HCl 

emission limit. For sources using HCl CEMS, scrubber parameter monitoring should not be 

required. 

Response: The final rule does clarify that parameter monitoring associated with PM control is 

not required when a PM CEMS is used. If a PM CEMS is used for compliance, the final rule 

likewise does not require compliance with an opacity standard under this subpart. Also, see the 

response to EPA-HQ-OAR-2002-0058-3213.1, Comment Excerpt Number 301. For the HCl 

issue, see the response to EPA-HQ-OAR-2002-0058-3137.1, Comment Excerpt Number 59.

Other - Testing and Monitoring

Commenter Name: Carter Strickland, Jr

Commenter Affiliation: New York City Department of Environmental Protection

Document Control Number: EPA-HQ-OAR-2002-0058-1600.1

Comment Excerpt Number: 3
375

Comment: Allow for emergency exemptions. Given the importance of maintaining sewage 

treatment capacity at all times, including during gas disruptions that may require the use of more 

oil than usual or other operational adjustments, and the obligations to continue operations under 

the Clean Water Act and implementing authorities, the NESHAP rules should include an 

emergency exemption for wastewater treatment facilities that would allow temporary 

exceedances without accruing violations 

Create new limits or allow for additional time to comply. These rules may require significant 

changes in operations or investments in upgrades, yet the applicable date is the date of the rule 

proposal in June 2010. DEP’s significant existing fleet of 68 boilers may require a transition 

period to meet the new emission standards. Even new boilers that are currently being installed 

may have not been designed with specifications meeting the new standards given that the design 

and scoping of such contract could not have anticipated the proposed emission levels. The rules 

should allow for a transition period during which information is gathered about emission levels 

and any need for compliance plans to reduce emissions, but in which penalties or violations are 

waived. 

Response: Exemption from testing is allowed for units where it is impracticable to test and we 

have included exemptions for certain units as a result of the inability to test for emissions. EPA 

disagrees that exemptions should be made for individual sectors as many affected sources play 

an integral role in providing essential services or goods to our economy. Sources can petition the 

administrator for an extension on a site-specific basis.

Commenter Name: Carter Strickland, Jr

Commenter Affiliation: New York City Department of Environmental Protection

Document Control Number: EPA-HQ-OAR-2002-0058-1600.1

Comment Excerpt Number: 6

Comment: The EPA should also consider incentivizing switches to cleaner fuels by waiving or 

modifying the stack testing requirement for fuel oil mode if major source boilers are firing ultralow sulfur diesel fuel oil. Several DEP boilers use that fuel and will readily meet most if not all 

of the new emissions standards, and DEP believes that the $100,000 per year in testing will not 

be a justified expense. 

Response: The work practice standards are established for subcategories where it is infeasible to 

test. Many units firing ultra low sulfur diesel fuel oil, including some units in the phase II ICR 

test program, demonstrated the ability to measure emissions of HAP and therefore a work 

practice standard and test waiver is not provided to units firing ultra low sulfur fuel oil.

Commenter Name: Houston Public Hearing Transcript

Commenter Affiliation: See transcript for detailed list of commenters
376

Document Control Number: EPA-HQ-OAR-2002-0058-1876

Comment Excerpt Number: 7

Comment: Streamline the performance tests, monitoring and other compliance 

demonstration requirements such as that are aligned with 

emission testing and reporting requirements for other 

air emission regulations by streamlining performance 

Response: For the operations and facilities subject to the rule, we believe that the combination 

of periodic compliance emissions testing and continuous monitoring of operational and 

parametric control measure conditions is appropriate for assuring ongoing compliance.

Commenter Name: Fred L. Taylor

Commenter Affiliation: Troy Lumber Company

Document Control Number: EPA-HQ-OAR-2002-0058-1879

Comment Excerpt Number: 3

Comment: We fail to understand the reasoning for annual stack testing when, historically, we 

have been required to test only upon initial start-up and after major modifications to the boiler. 

Also, the history of stack testing of boilers shows them to be amazingly consistent in results. 

Why should we spend $5,000 to $15,000 a year for stack and fuel testing just to get the same 

answer year after year? 

Response: We disagree with assertions by several commenters that the performance 

testing requirements are excessive. 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. A CEMS may be used as an option and, if so, 

annual performance testing is not required for the pollutant being measured by a CEMS. Also, 

because of the test data we have seen on dioxin/furan emissions, only an initial compliance test 

will be required for that pollutant.

Commenter Name: Michael L. Steele

Commenter Affiliation: CraftMaster Manufacturing, Inc

Document Control Number: EPA-HQ-OAR-2002-0058-1907.1

Comment Excerpt Number: 6

Comment: The requirement for annual stack testing seems excessive given the required scope of 

testing. A unit will operate per continuously monitored parameters developed during successful 

stack test therefore the risk of a significant change in emissions should be low. Testing shouJd be 
377

required no more frequency than every five (5) years, unless a change in method of operation 

that could potentially affect emissions is proposed. 

Response: See the response to EPA-HQ-OAR-2002-0058-1879, Comment Excerpt Number 3.

Commenter Name: Richard Holland

Commenter Affiliation: Packaging Corporation of America

Document Control Number: EPA-HQ-OAR-2002-0058-2385

Comment Excerpt Number: 4

Comment: The Agency issued an Information Collection Request (ICR) in June 2009 that 

required recipients to conduct mandatory performance tests for select pollutants in order to fill 

data gaps in emission test data that EPA identified relative to CISWI units. This facility received 

an ICR and was required to perform stack tests for cadmium, lead, mercury (Hg), dioxin/furan 

(D/F), carbon monoxide, condensible PM and PM2.5. The ICR prescribed 2-hour test runs for 

Hg and 4-hour test runs for D/F or, in lieu of the specified run durations, alternative minimum 

sample volumes. The demands that this exercise placed on the stack testing contractor’s staff, 

mill personnel overseeing the testing, and mill operations staff was extreme due to the duration 

of the test runs. 

The proposed rule requires that 4-hour stack test runs be performed annually for the worst-case 

fuel mix for the respective parameter of interest. We wonder if the Agency appreciates the 

magnitude of labor and cost associated with this requirement. An additional compounding issue 

is the probable lack of qualified stack testing contractors if/when the rule goes into effect. 

Assuming that over 10,000 industrial boilers are affected by the rule and that the annual stack 

testing requirements must be satisfied for the entire population of affected units within a narrow 

window of time (e.g., within 10 – 12 months of the effective date of the rule), it is unlikely that 

there will be sufficient qualified stack testers to go around. Further, testing for sensitive

parameters like Hg and D/F requires an experienced stack testing team that understands the 

pitfalls associated with the test methods. Factor in fatigue due to performing extended stack tests 

(even for experienced teams) and the stage is set for a high probability of questionable results. 

Finally, the proposed rule requires performance stack testing while combusting “worst-case” fuel 

blends. This requirement multiplies the number of stack tests required as a function of fuels 

combusted at a facility as well as the parameter in question. To wit, it is entirely probable that a 

facility might need to conduct a set of 4-hour performance tests for D/F using one fuel blend, 

another set of tests for Hg using a different fuel blend, yet another set of tests for hydrogen 

chloride using a third fuel blend, etc. The costs associated with this kind of complicated testing 

matrix are multiples greater than what we incurred at our Counce facility to satisfy the ICR – and 

something that we believe is entirely unnecessary. 

We find it disturbing that the Agency is requiring annual stack testing despite the fact that there 

is no legal requirement for annual testing under MACT (or in the court order). By design, MACT 
378

is a technology-driven standard. Initial performance tests have been used for all other pulp and 

paper industry MACTs to demonstrate that the technology is capable of meeting the standard; 

any on-going testing falls under the purview of the respective States. 

While the original Boiler MACT rule required annual PM testing (3 one-hour runs using EPA 

Method 5), many pulp and paper sources have to do anyway so it was not particularly 

objectionable. Also, that rule allowed facilities to opt out of Hg, hydrogen chloride and Total 

Select Metals stack testing via once-in-five-years fuel testing to demonstrate compliance. The 

point is this; the testing burden associated with the proposed MACT is magnitudes of order 

greater than the original Boiler MACT – and unnecessarily so. 

PCA urges EPA to review the comments submitted by the Georgia Paper and Forest Products 

Association that specifically addresses testing issues. 

We urge the Agency to modify the stack testing requirements to mirror earlier MACTs (e.g., 

Subpart S, Subpart MM) wherein performance testing consists of three 1-hour tests and testing is 

limited to an initial performance test (not annual testing) to demonstrate the efficacy of the 

control technology. 

Response: See the response to EPA-HQ-OAR-2002-0058-1879, Comment Excerpt Number 3. 

Commenter Name: Ashley Peterson

Commenter Affiliation: American Meat Institute

Document Control Number: EPA-HQ-OAR-2002-0058-2382.1

Comment Excerpt Number: 6

Comment: We suggest that annual stack testing is not necessary in order to demonstrate 

compliance with emission limits. Performing a stack test on each boiler annually is burdensome 

and provides no additional valuable information or safeguard. One test is sufficient as is required 

for current new construction permits. If the stack test is passed at that time, emissions from the 

system will not appreciably change unless the system is modified. 

Response: See the response to EPA-HQ-OAR-2002-0058-1879, Comment Excerpt Number 3.

Commenter Name: Robin Mills Ridgway

Commenter Affiliation: Purdue University

Document Control Number: EPA-HQ-OAR-2002-0058-2782.1

Comment Excerpt Number: 7

Comment: Annual testing frequency is unworkable for continuously operating and maintained 

plants like Purdue’s Wade Utility Plant 
379

§63.7515(a)’s timing requirement is too restrictive for plants that have outstanding annual 

maintenance programs. As an example, Purdue annually shuts down each of its boilers for days 

or a week at a time in succession to perform annual maintenance. Though Purdue’s current 

RATA and Title V annual testing program conducts testing every fall, the timing of the testing 

from year to year can vary by a month or two. This means that a unit tested in November of one 

year may not be back on line exactly 12 months later. The 10 to 12 month requirement in the 

proposed rule does not allow for plant equipment availability schedules and would result in 

annual testing being preformed earlier and earlier in the year as the years go on. This would 

result in Purdue having to eventually test at times of the year where no steam load was available 

to support a stack test. 

Purdue requests that EPA change the proposed 10-12 month frequency to 10-14 months or, 

alternately, require sources to test within the same calendar quarter in successive years. For 

example if a source conducts the initial performance test during the 4th quarter of a calendar 

year, then successive annual testing must also be performed during the 4th quarter. It could be 

performed earlier in the year as well, but not later than 4 quarters after the last test. 

Additionally, EPA should consider borrowing from New Source Performance Standard Subpart 

Y—Standards of Performance for Coal Preparation and Processing Plants § 60.255 (b)(1)(iii), 

which provides: An owner or operator of an affected facility that has not operated for the 60 

calendar days prior to the due date of a performance test is not required to perform the 

subsequent performance test until 30 calendar days after the next operating day. 

Response: The final rule requires annual tests to be performed no more than 13 months after the 

prior test.

Commenter Name: Rich Raiders

Commenter Affiliation: Arkema, Inc

Document Control Number: EPA-HQ-OAR-2002-0058-2751.1

Comment Excerpt Number: 9

Comment: The Boiler and CISWI standards regulate a variety of pollutants, some of which may 

not be present in the combustion stream nor emitted from the products of combustion. For 

instance, many CISWI units combust organic streams or organic and aqueous mixtures that do 

not contain halogen concentrations beyond trace salt chlorides. The potential of such a unit to 

emit HCl, chlorine, or dioxins and furans (“D/F”) is insignificant. These same streams often do 

not contain detectible amounts of metal HAP or metallic CISWI constituents. The potential of 

such units to emit cadmium, lead, and mercury, among other metals, is minimal. In these 

situations, EPA should allow affected sources to combine a one-time compliance stack test with 

process knowledge of the material being combusted to streamline the compliance demonstration 

for certain parameters. We understand that EPA has far less flexibility in streamlining 

compliance demonstrations for common products of combustion, such as particulate matter, 

oxides of nitrogen (“NOx”), and sulfur dioxide (“SO2”). But when feasible, EPA should allow 
380

owners and operators to use process knowledge and chemistry to show that some regulated 

emissions are not of concern from certain regulated units. 

Response: See the response to EPA-HQ-OAR-2002-0058-1879, Comment Excerpt Number 3.

Commenter Name: Steven M. Maruszewski

Commenter Affiliation: The Pennsylvania State University

Document Control Number: EPA-HQ-OAR-2002-0058-2729.1

Comment Excerpt Number: 14

Comment: Test interval - §63.7515 

Testing Interval Proposed rule requires testing every ten to twelve months. For Universities, 

testing is performed at the height of the heating demand system. Testing 

on a ten to twelve month schedule will slowly move the test period forward in the year. 

Eventually, testing will be required to be accomplished during low load periods leading to 

wasted fuel use and unnecessary generation of air emissions. 

The University is requesting that this time frame be extended to ten to fourteen months or use 

language such as “between November 1st and February 28th” in specific cases. This would allow 

load following facilities to test during high demand months. 

Response: See the response to EPA-HQ-OAR-2002-0058-2782.1,Comment Excerpt Number 7.

Commenter Name: Stephen R. Gossett

Commenter Affiliation: Eastman Chemical Company

Document Control Number: EPA-HQ-OAR-2002-0058-3137.1

Comment Excerpt Number: 53

Comment: Frequency of testing is unreasonable and out of character with other MACT and 

NSPS standards and other state performance testing requirements. EPA has proposed the most 

aggressive performance testing requirements we are aware of on the largest MACT source 

category it has addressed to date. The Hazardous Waste Combustor MACT (Subpart EEE), for 

example requires a Comprehensive Performance Test (CPT) only once every 5 years (and, for 

some units, a confirmatory test for D/Fs in between CPTs). Many MACT standards and NSPS 

standards only require one initial performance test unless there is a physical change to the control 

device. In Tennessee for example, Eastman has for years performed particulate matter 

performance tests on coal-fired boilers on a 4 year frequency, and this only applies to boilers 

over 250 mmBtu/hr rated capacity. 

Taking the Eastman plant in Tennessee as an example, we have 10 coal-fired boilers and three 

units that would fall in the Gas 2 subcategory. This would mean we would be conducting stack 

tests at the facility at a frequency greater than once per month for the first three years of 
381

compliance, and this is just for this one regulation. We believe this is clearly an unreasonable 

requirement. 

Response: See the response to EPA-HQ-OAR-2002-0058-1879, Comment Excerpt Number 3.

Commenter Name: Stephen R. Gossett

Commenter Affiliation: Eastman Chemical Company

Document Control Number: EPA-HQ-OAR-2002-0058-3137.1

Comment Excerpt Number: 55

Comment: EPA states in the preamble (page 32033), “Additionally, this proposed rule would 

require annual performance tests to ensure, on an ongoing basis, that the air pollution control 

device is operating properly and its performance is not deteriorating.” EPA is over-reaching with 

this argument. The continuous parametric monitoring requirements proposed in Table 8 (fabric 

filter bag leak detection, electrostatic precipitator power input, opacity monitoring, wet scrubber 

pressure drop and flow rate, etc) provide ample assurance the control equipment are not 

deteriorating and are operated properly. 

Response: See the response to EPA-HQ-OAR-2002-0058-1879, Comment Excerpt Number 3.

Commenter Name: Britt S. Fleming

Commenter Affiliation: Auto Group

Document Control Number: EPA-HQ-OAR-2002-0058-2775.1

Comment Excerpt Number: 59

Comment: Proposed 63.7515 Subsections (a) and (e) – The definition of the annual time period 

requirement for performance testing needs to be revised. The requirement to have annual tests 

completed between 10 and 12 months after the previous performance test may be too restrictive 

and sources should be allowed to use a more flexible definition of the annual frequency to allow 

for seasonal variations. Having “annual” defined as less than a full year could result in a situation 

where a boiler’s annual test must be performed when there is not adequate cold weather load. For 

example, if the first test is performed in January, then 11 months later in December, then 11 

months later in November, then October, then September when the boiler may normally be 

shutdown or not able to operate at high enough temperatures to achieve maximum operating 

conditions. This will also create a problem with the “maximum normal operating load 

requirement” during performance tests specified at § 63.7520(c). EPA needs to amend this 

requirement to provide additional flexibility to accommodate seasonal firing and variability. 

Proposed 63.7515 Subsection (a) – Requiring annual stack testing for all boilers regardless of 

size does not make sense and must be revised. Most Title V permits require performance testing 

to demonstrate compliance with emission limits within the year prior to permit expiration, or at 

least once per permit cycle (once every 5 years). Thus, sources already are required to 
382

demonstrate compliance through emission testing approximately every 5 years. More frequent 

testing only makes sense for boilers and process heaters that have exceeded the emission limit. 

The Auto Group recommends that only boilers over 100 mmBtu/hr be subject to the periodic 

testing and then only when necessary to demonstrate compliance with applicable emission limits, 

once every 5 years. 

Response: See the response to EPA-HQ-OAR-2002-0058-1879, Comment Excerpt Number 3.

Also, see the response to EPA-HQ-OAR-2002-0058-2782.1,Comment Excerpt Number 7.

Commenter Name: Timothy Hunt

Commenter Affiliation: American Forest and Paper Association (AF&PA)

Document Control Number: EPA-HQ-OAR-2002-0058-3213.1

Comment Excerpt Number: 278

Comment: The proposed rule requires annual emissions testing (once every 10 to 12 months). 

See 63.7515 (a). The requirement to conduct testing every 10 to 12 months will result in an 

increased burden in some calendar years. Therefore, we request that if the requirement for annual 

stack testing is retained, that the frequency for stack testing be changed to once every 10 to 14 

months. This will help reduce the annual costs of the rule to offset the increased fuel costs 

facilities may incur during stack tests to accommodate the requirement to burn the worst case 

fuel mix. Requiring annual testing and restricting the allowable window between tests also will 

result in a resource burden if all facilities are doing annual stack testing at the same time. There 

are a limited amount of stack testing contractors available, and a small window for conducting 

testing may result in some facilities not being able to find a qualified testing firm. 

Response: See the response to EPA-HQ-OAR-2002-0058-2782.1,Comment Excerpt Number 7.

Commenter Name: Timothy Hunt

Commenter Affiliation: American Forest and Paper Association (AF&PA)

Document Control Number: EPA-HQ-OAR-2002-0058-3213.1

Comment Excerpt Number: 279

Comment: That said, the proposed requirement for annual stack testing is unreasonable and out 

of character with other MACT and NSPS standards and other state performance testing 

requirements. EPA has proposed the most aggressive performance testing requirements we are 

aware of on the largest MACT source category it has addressed to date. The Hazardous Waste 

Combustor MACT (Subpart EEE) for example requires a comprehensive performance test only 

once every 5 years. Many MACT standards and NSPS only require one initial performance test 

(e.g., pulp and paper MACT standards under Subparts S and MM) unless there is a physical 

change to the control device that would increase emissions. The purpose of the initial 

performance test is to ensure that the technology installed is capable of meeting the emission 

limits. EPA has proposed extensive monitoring and recordkeeping that is meant to ensure 
383

continuous compliance with the emission standards. Therefore, the frequency of stack testing 

should be reduced to once every 5 years. 

Response: See the response to EPA-HQ-OAR-2002-0058-1879, Comment Excerpt Number 3.

Commenter Name: Timothy Hunt

Commenter Affiliation: American Forest and Paper Association (AF&PA)

Document Control Number: EPA-HQ-OAR-2002-0058-3213.1

Comment Excerpt Number: 280

Comment: The requirement for annual stack testing in 63.7515 provide no relief for limited use 

units. As discussed earlier in these comments, we believe that limited use units are eligible for 

subcategorization under this rule, and should also be eligible for reduced testing frequencies if 

they only operate a few hours per year or do not operate at all in a calendar year. Starting up 

these boilers for the express purpose of testing them creates an unnecessary expense in terms of 

both operational and testing cost, wastes fuel, and causes emissions that could be avoided. 

Response: Limited use units are subject only to biennial tune-up requirements under the final 

rule.

Commenter Name: Robert D. Bessette

Commenter Affiliation: Council of Industrial Boiler Owners (CIBO)

Document Control Number: EPA-HQ-OAR-2002-0058-2702.1

Comment Excerpt Number: 132

Comment: Emissions Testing 

A.EPA’s Proposed Performance Testing Requirements Are Excessive and 

Should Be Reduced to a Reasonable and Appropriate Level. 

The proposed performance testing requirements do pose a significant burden. 

This frequency of testing is unreasonable and out of character with other MACT and NSPS 

standards and other state performance testing requirements. EPA has proposed the most 

aggressive performance testing requirements we are aware of on the largest MACT source 

category it has addressed to date. The Hazardous Waste Combustor MACT (Subpart EEE), for 

example requires a Comprehensive Performance Test only once every 5 years. Many MACT 

standards and NSPS standards only require one initial performance test unless there is a physical 

change to the control device. 

Response: See the response to EPA-HQ-OAR-2002-0058-1879, Comment Excerpt Number 3.
384

Commenter Name: Randall D. Quintrell

Commenter Affiliation: Georgia Paper and Forest Products Association, GPFPA

Document Control Number: EPA-HQ-OAR-2002-0058-2905

Comment Excerpt Number: 2

Comment: One aspect of the unnecessary and unreasonable burden that the Rule would impose 

is the frequency of testing required. The Rule requires both initial and annual compliance testing 

for five (5) different parameters, all equally detailed. However, annual testing is not required by 

the governing statute, by precedent, or by the Court. In fact, the proposed level of testing is 

contrary to the principle adhered to in prior MACT rules whereby an Initial Performance Test 

("IPT") is required to ensure that the technology installed is capable of meeting the emission 

limits imposed by the respective MACT regulation. In these instances, records of the operating 

conditions of the control technology during the IPT combined with continuous parameter 

monitoring is deemed sufficient to document the level of control achieved and provide a method 

for monitoring on-going performance. The stated purpose of the MACT regulation is to establish 

the maximum achievable control technology (specifically defined as the average of the top 12% 

of performers in any class of units) and require that all affected units achieve such level of 

control technology. The goal is to bring the balance of the affected units up to the performance 

level averaged by the top performers. The Initial Performance Test is the tool used to 

demonstrate the technological capability of the controls and as long as the unit/control 

technology is operated within the demonstrated range of operation, the technology has proven 

capable and continuous parametric monitoring is established for compliance assurance. There is 

no requirement or need for ongoing testing under MACT. 

Response: See the response to EPA-HQ-OAR-2002-0058-1879, Comment Excerpt Number 3.

Commenter Name: Randall D. Quintrell

Commenter Affiliation: Georgia Paper and Forest Products Association, GPFPA

Document Control Number: EPA-HQ-OAR-2002-0058-2905

Comment Excerpt Number: 7

Comment: Although the testing frequency is specified as "annually" in the Rule, this term is 

defined to mean "every 10-12 months." In reality, this amounts to a de facto 10 month (or less) 

testing schedule. No affected unit could reasonably wait until the 12th month and risk being 

unable to get the operating conditions, fuel conditions, supplies and/or testing companies 

available to perform the huge testing program that is proposed annually by the current Rule. For 

any facility that has multiple units to test, producing all the required test conditions could take 

weeks or months just to get through a single round of tests. The requirement to repeat this 

burdensome, costly and time-consuming exercise at 10-month intervals is unnecessary to 

demonstrate compliance with the Rule and is egregiously unreasonable. Periodic testing must be 

deleted from the final Boiler MACT Rule. The decisions should be left to the States as the 

delegated agencies to determine appropriate testing frequency in Title V permits. 
385

Response: See the response to EPA-HQ-OAR-2002-0058-2782.1,Comment Excerpt Number 7.

Commenter Name: Randall D. Quintrell

Commenter Affiliation: Georgia Paper and Forest Products Association, GPFPA

Document Control Number: EPA-HQ-OAR-2002-0058-2905

Comment Excerpt Number: 20

Comment: Dioxin/furan testing is very specialized and expensive. Such testing requires highly 

trained personnel and highly specialized labs to accurately analyze and interpret the data. These 

firms must have excellent QA/QC track records. There are only a few such testing companies 

and laboratories in the US that meet these criteria. If the approximately 51 boilers in Georgia 

(not to mention the hundreds and possibly thousands of boilers in other states) all have to 

contract for these limited services there is simply no way the testing can be completed 

competently as required — much less repeated again and again every 10 months! 

Imposing such testing requirements on the regulated community in the face of these facts is not 

only unreasonable but it is arbitrary and capricious. The MACT testing requirement should be 

limited to an Initial Performance Test to relieve this unnecessary and unreasonable burden. 

Response: Annual dioxin/furan testing is not required under the final rule.

Commenter Name: Donald R. Schregardus

Commenter Affiliation: Department of Defense

Document Control Number: EPA-HQ-OAR-2002-0058-2763.1

Comment Excerpt Number: 23

Comment: EPA should revise the requirement to conduct an annual performance test within 10-

12 months after the previous performance test. 

If the current regulation is not revised, this requirement will result in a "creeping’. effect that has 

the potential to move annual performance testing earlier and earlier each successive year. There 

are many variables beyond the control of the facility in terms of performance testing, some of 

which include weather, facility maintenance schedules and contractor availability. An example 

of the "testing creep" is provided in the following timeline [See submittal for Table, Example 

Proposed Stack Testing Timeline] 

To accomplish the annual testing requirement without introducing ‘creep’ in the schedule, a 

modification to §63.7515(a) that sets the testing calendar based on the anniversary of the original 

test date or the anniversary of the deadline for demonstrating initial compliance would resolve 

the issue. For example, if original performance test is done on 31 July, the rule could require that 

each subsequent annual performance test must be conducted each year anytime between 1 June 

and 31 July. 
386

Revise §63.7515(a) to prevent the rule from requiring more than one test per calendar year. The 

following is an example of how 63.7515(a) could be revised. 

§ 63.7515 When must I conduct subsequent performance tests or fuel analyses? 

(a) You must conduct all applicable performance tests according to §63.7520 on an annual basis, 

unless you follow the requirements listed in paragraphs (b) through (e) of this section. Annual 

performance tests must be completed! • • • ; - .’each year during the two month period 

preceding the anniversary of the completion of the initial performance test, unless you follow the 

requirements listed in paragraphs (b) through (e) of this section. 

Response: See the response to EPA-HQ-OAR-2002-0058-2782.1,Comment Excerpt Number 7.

Commenter Name: Chris Greissing

Commenter Affiliation: Industrial Minerals Association

Document Control Number: EPA-HQ-OAR-2002-0058-2740.2

Comment Excerpt Number: 28

Comment: 63.7515. When must I conduct subsequent performance tests or fuel analyses? 

(a)You must conduct all applicable performance tests according to 63.7520 on an annual basis, 

unless you follow the requirements listed in paragraphs (b) through (e) of this section. Annual 

performance tests must be completed between 10 and 12 months after the previous performance 

test, unless you follow the requirements listed in paragraphs (b) through (e) of this section. 

The soda ash companies recommend EPA provide greater flexibility for applicable performance 

tests. In the absence of meeting the requirements in paragraphs (b) and (e) for an exception to 

this requirement (and which will not be available for the first 3 years of the rules application), 

limiting performance tests to a two-month limit is inconsistent with operational realities. Boilers 

are subject to scheduled maintenance outages that may interfere with the ability to test within the 

narrow two-month window each year. Further, the requirement to do each test within the 10-12 

month window will in practice require that sources conduct testing more often than annually 

because each testing interval will be less than 12 months. EPA should amend this provision to 

authorize boiler owners to conduct annual performance tests once each calendar year but no 

sooner than six months after the previous test. 

Response: See the response to EPA-HQ-OAR-2002-0058-2782.1, Comment Excerpt Number 7.

Commenter Name: David A. Buff

Commenter Affiliation: Golder Associates Inc

Document Control Number: EPA-HQ-OAR-2002-0058-2801.1

Comment Excerpt Number: 58
387

Comment: Due to the complexity and expense, need reduced frequency of stack testing for D/F, 

similar to what has been afforded to the Portland Cement industry (testing once every 3 years). 

Response: Annual testing is not required for D/F under the final rule.

Commenter Name: Robert D. Bessette

Commenter Affiliation: Council of Industrial Boiler Owners (CIBO)

Document Control Number: EPA-HQ-OAR-2002-0058-2702.1

Comment Excerpt Number: 134

Comment: EPA states in the preamble, "[a]dditionally, this proposed rule would require annual 

performance tests to ensure, on an ongoing basis, that the air pollution control device is operating 

properly and its performance is not deteriorating." 75 FR 32033. EPA is over-reaching with this 

argument. The continuous parametric monitoring requirements proposed in Table 8 of the 

Proposed Rule (fabric filter bag leak detection, electrostatic precipitator power input, opacity 

monitoring, wet scrubber pressure drop and flow rate, etc) provide ample assurance the control 

equipment is not deteriorating and are operated properly. 

Response: See the response to EPA-HQ-OAR-2002-0058-1879, Comment Excerpt Number 3.

Commenter Name: Matthew Todd and David Friedman

Commenter Affiliation: American Petroleum Institute (API) and National Petrochemical and 

Refiners Association (NPRA)

Document Control Number: EPA-HQ-OAR-2002-0058-2960.1

Comment Excerpt Number: 166

Comment: For sources and pollutants where continuous emission monitoring is not required, but 

controls are installed and control parameter monitoring is used to demonstrate compliance, 

annual performance testing imposes an unreasonable and unnecessary burden and repeat stack 

testing is only justified if the fuel, and therefore the control inlet pollutant concentration, 

increases significantly. No other MACT rule we are aware of requires repeat performance testing 

where parametric monitoring is used to assure compliance and experience demonstrates that 

repeat performance testing is wasteful and unnecessary. 

Recommendation: Revise 63.7515(a) to exclude boilers and process heaters from the annual 

performance testing requirement for pollutants that are controlled with add-on control devices 

that are being continuously monitored for compliance using continuous parameter monitors. 

Response: See the response to EPA-HQ-OAR-2002-0058-1879, Comment Excerpt Number 3.
388

Commenter Name: Matthew Todd and David Friedman

Commenter Affiliation: American Petroleum Institute (API) and National Petrochemical and 

Refiners Association (NPRA)

Document Control Number: EPA-HQ-OAR-2002-0058-2960.1

Comment Excerpt Number: 167

Comment: Provisions should also be included in the final regulation to allow sources to spread 

out the testing load over the repeat interval. Many major sources will have tens of boilers and 

process heaters that have to be tested. Having to manage that many performance tests is a 

tremendous effort and will significantly impact permitting authorities and process operations. It 

takes weeks of engineering and technical effort to organize a single stack test and to arrange for 

the needed operating and fuel conditions for the unit being tested. There is no compliance 

justification for imposing such massive burdens on sources or regulators all at once. Allowing 

this testing to be spread throughout the year will lessen the tremendous strain this rulemaking 

will impose on source, regulatory and stack testers. 

Recommendation: Add provisions to allow sources, with permitting authority agreement, to 

adjust the performance testing schedule to spread the workload out throughout a calendar year. 

Response: See the response to EPA-HQ-OAR-2002-0058-2782.1,Comment Excerpt Number 7.

Commenter Name: Matthew Todd and David Friedman

Commenter Affiliation: American Petroleum Institute (API) and National Petrochemical and 

Refiners Association (NPRA)

Document Control Number: EPA-HQ-OAR-2002-0058-2960.1

Comment Excerpt Number: 174

Comment: Despite the Agency‘s unsupported assumption that activated carbon injection will 

control dioxin/furans at gas-fired boilers and process heaters, there are no proven controls for 

dioxins/furans in such equipment. Thus, it is hard to understand what purpose annual stack tests 

serve. Dioxin/furan generation is a function of the stack temperature profile and the presence of 

chlorine. High levels of dioxin/furans only occur where stack gas is held in a particular, narrow 

temperature range, for relatively long periods and before dispersion. Thus, if an initial test 

indicates low dioxin/furan, the level will remain low and follow-up testing only wastes 

resources. Even where chlorine is present and stack temperature conditions are in the 

dioxin/furan formation window, the initial test will indicate whether the emission limitation is a 

problem. If so, sources will take whatever steps are available to meet the emission limitation, 

rerun the performance test to demonstrate compliance and continue to operate the boiler or 

process heater in that mode. It would be reasonable for the Agency to require that the site 

establish operating parameters in such cases to demonstrate ongoing compliance, but repeated 

performance tests would serve no purpose even in those cases. 

Recommendation: Eliminate the requirement for annual dioxin/furan performance tests. Instead 

require an initial dioxin/furan performance test and retesting if the unit is modified. This also 
389

would be consistent with the requirements in the Hazardous Waste Combustor NESHAP (Part 63 

Subpart EEE), which addresses combustors that are far more likely than industrial, commercial 

and institutional boilers and process heaters to generate dioxin/furans. 

Response: Annual dioxin/furan testing is not required under the final rule.

Commenter Name: Matthew Todd and David Friedman

Commenter Affiliation: American Petroleum Institute (API) and National Petrochemical and 

Refiners Association (NPRA)

Document Control Number: EPA-HQ-OAR-2002-0058-2960.1

Comment Excerpt Number: 177

Comment: Proposed 63.7515 requires, in several paragraphs, that annual performance tests be 

performed between 10 and 12 months after the previous performance test. A similar requirement 

is included in the proposal for tune-ups. We support the concept of providing a window for such 

testing, rather than requiring the test be performed on the same day every year, but this window, 

forces more frequent testing than annual and causes sources to change the month of testing every 

year, making compliance more difficult. For instance if a test is done in May one year, it must be 

done in April or May of the following year. Since good practice requires some allowance for 

problems and possible delay or retesting, prudent sources will test in April. Then the next year‘s 

test would be in March, etc. Under the proposed system, testing is actually required more 

frequently than annually, a fact not reflected in the record or cost analyses. We suggest 63.7515 

be revised to specify annual tests may be done at any time in the same calendar quarter as the 

initial testing was done, regardless of the particular month in which the testing occurred. If a 

boiler or process heater does not operate during the quarter, testing should be required within 30 

days after restart. 

Recommendations: Revise the performance test frequency language so tests may be done in the 

same calendar quarter as the initial test was done in years when they are due. Add provisions for 

boilers and process heaters that are out-of-service during the quarter they are due for tune-up. 

Response: See the response to EPA-HQ-OAR-2002-0058-2782.1,Comment Excerpt Number 7.

Commenter Name: Matthew Todd and David Friedman

Commenter Affiliation: American Petroleum Institute (API) and National Petrochemical and 

Refiners Association (NPRA)

Document Control Number: EPA-HQ-OAR-2002-0058-2960.1

Comment Excerpt Number: 178

Comment: Because there will be thousands and thousands of such tests between this rule and 

the area source rule, provision is needed to allow sources to move the testing to other quarters, 

with agreement of the permitting authority. Stack testing, source and local Agency resources are 
390

limited and workload needs to be spread throughout the year to allow these resources to be 

efficiently utilized. 

Recommendations: Allow for changing performance test timing to allow sources to spread out 

the effort throughout a year. 

Response: See the response to EPA-HQ-OAR-2002-0058-2782.1, Comment Excerpt Number 7.

Commenter Name: Jeffrey R.Klieve

Commenter Affiliation: Monsanta Company

Document Control Number: EPA-HQ-OAR-2002-0058-2754.1

Comment Excerpt Number: 6

Comment: In light of this significant testing cost, Monsanto requests that USEPA reduce the 

sampling frequency from annual to once every third year or longer. 

Response: See the response to EPA-HQ-OAR-2002-0058-1879, Comment Excerpt Number 3.

Commenter Name: Eric Trauner

Commenter Affiliation: Citizen

Document Control Number: EPA-HQ-OAR-2002-0058-2768

Comment Excerpt Number: 8

Comment: Stack testing demands should be lowered to biennial at first, then trending toward 

once per five years after two successful tests. It must be underlined that there are relatively few 

stack testing firms that are qualified to conduct such testing, and excessive testing will result in a 

rush of unqualified, inexperienced stack testers hitting the market. In turn, there would be a rush 

of flawed emissions data hitting the very database that US-EPA is seeking to create. 

Response: See the response to EPA-HQ-OAR-2002-0058-1879, Comment Excerpt Number 3.

Commenter Name: Dave Copeland

Commenter Affiliation: Praxair Inc

Document Control Number: EPA-HQ-OAR-2002-0058-3141

Comment Excerpt Number: 8

Comment: Stack testing 

The requirements in 63.7515(a) for performance testing on an annual basis are overly 

burdensome and not justified for the amount sources that are subject to the rule. The alternatives 
391

presented in 63. 7515 (b)-(e) do not go far enough to minimize the burden this places on the 

regulated industry as well as the regulating authorities that review and witness stack testing 

projects. It is appropriate that all testing requirements be consistent with Title V renewal periods 

and this testing should occur every 5 years. 

Recommendation: Modify 63.7515(a) from requiring performance testing on an annual basis to 

once every 5 years to correspond with the Title V permit cycle. This will more efficiently utilize 

the regulated communities’ resources as well as the overseeing agencies resources. 

Response: See the response to EPA-HQ-OAR-2002-0058-1879, Comment Excerpt Number 3.

Commenter Name: John Hopewell

Commenter Affiliation: American Coatings Association

Document Control Number: EPA-HQ-OAR-2002-0058-2886.1

Comment Excerpt Number: 17

Comment: EPA should allow less frequent stack testing . Facilities should be able to test one 

unit if it is representative of multiple units (e.g., same size/type/fuel) at the facility 

Response: See the response to EPA-HQ-OAR-2002-0058-1879, Comment Excerpt Number 3.

Commenter Name: Pamela F. Faggert

Commenter Affiliation: Dominion

Document Control Number: EPA-HQ-OAR-2002-0058-2908.1

Comment Excerpt Number: 28

Comment: The proposed Section 63.7515 requires annual performance tests to be conducted 

between 10 and 12 months from the previous test, except for some provisions that allow 

extending the testing to no more than 36 months. This calendar month schedule does not take 

into account the actual operations of the unit and provides a very narrow window and little 

flexibility to conduct the testing. Some units may only operate a few months of the year or 

seasonally, and therefore are required to test more frequently based on operating hours than units 

that are based loaded. These units tend to be more difficult to schedule testing and under this rule 

would likely have to be operated solely to conduct the testing. This 10 to 12 month window 

might be impossible to meet if the unit is in a planned or unplanned outage during the 2 month 

window. We recommend that any annual performance testing be modeled after the provisions of 

Part 75 (Appendix B 2.3.1) which allows for these normal issues of operating frequency and test 

scheduling by using "4 QA Operating Quarters" as the basis of timing annual tests. If a unit 

operates less than 168 hours in a quarter, it is not counted as a quarter in the testing schedule. We 

also recommend the "Grace Period" provisions under Part 75 (Appendix B 2.3.3) be incorporated 

to allow for outage situations and for unforeseen testing problems. This allows the testing to be 

completed within 720 unit operating hours after the test is normally required to be completed. 
392

Response: See the response to EPA-HQ-OAR-2002-0058-2782.1, Comment Excerpt Number 7.

Commenter Name: Pamela F. Faggert

Commenter Affiliation: Dominion

Document Control Number: EPA-HQ-OAR-2002-0058-2908.1

Comment Excerpt Number: 30

Comment: EPA Should Provide a Reduced Testing Option for DioxinlFurans 

Proposed Section 63.7515 requires annual stack testing. While there are some provisions to 

decrease the frequency to 24 or 36 months for some pollutants, that option is not provided for 

dioxin/furan tests. There are also no provisions for non-operating quarters for grace periods 

(similar to those provisions in 40 CFR Part 75) to manage the testing. This means units will have 

to be operated specifically to conduct testing. 

Dioxin/furan testing is very expensive (EPA estimates testing may range from $15,000 to 

$50,000) and there are only a limited number of laboratories qualified to perform such testing. In 

addition, dioxin/fin-an emissions are very low, and differences in test results from year-to-year 

could just as likely be the result of measurement issues as changes in actual emissions. The 

proposed rule already requires sources to confirm that there are no changes in the operation of an 

affected unit or control equipment that could increase emissions9. For these reasons, EPA should 

allow such tests to qualify for reduced testing under Section 63.7515(c) and should consider 

biennial or triennial testing for dioxin/furans. Since these values might be too close to the 

detection limits to determine 75% of the limit, any test results below the detection limit should 

be allowed the extension. EPA should also consider eliminating dioxin/furan testing 

requirements all together for limited-use (low capacity factor) units. To the extent testing is 

required, EPA should include a provision that allows additional time (beyond the 60 days from 

when field sampling is terminated in the proposed rule) to submit the results of dioxin/furan 

tests. Method 23 procedures for dioxin/furans require intense laboratory procedures for which, as 

noted earlier, there are only a limited number of qualified laboratories. 

Response: Annual testing for dioxin/furan emissions is not required under the final rule.

Commenter Name: Russ A. Wozniak

Commenter Affiliation: Dow Chemical Company

Document Control Number: EPA-HQ-OAR-2002-0058-2632.1

Comment Excerpt Number: 40

Comment: EPA provides no insight or justification in the preamble or otherwise for requiring 

annual retesting. Annual retesting is an unnecessary and burdensome requirement. Emission 

testing is costly and it must be coordinated with necessary plant operations and the availability of 

testing contractors. None of these factors are trivial and such frequent testing for low HAP 

emission rates is not needed. One of the most strenuous MACT standards, the Hazardous Waste 
393

Combustion MACT Section 63.1207(d)(1), requires initial retesting after 5 years. Dioxin/Furan 

retesting is only required for facilities with D/F emission limits. A number of the MACT 

Standards do not include retesting requirements unless the source is modified in a manner that 

would adversely affect compliance with the emission standard. Dow has a small internal 

emission testing organization and we estimate that the cost to conduct an annual emission test for 

all five air contaminants is $53,000 for each emission source in the "Other Gas" category. This 

annual cost for testing each emission source is excessive, and we urge EPA to finalize a rule that 

requires testing after a five year period or upon a significant change to a boiler or process heater. 

Response: See the response to EPA-HQ-OAR-2002-0058-1879, Comment Excerpt Number 3.

Commenter Name: Russ A. Wozniak

Commenter Affiliation: Dow Chemical Company

Document Control Number: EPA-HQ-OAR-2002-0058-2632.1

Comment Excerpt Number: 42

Comment: EPA’s Final Rule Should Allow Testing on Only One Source among a Group of 

Equivalent Sources. EPA should further simplify the initial performance testing and any periodic 

emission testing requirements such that one source can be tested among a group of equivalent 

sources. An example of equivalent sources may be three boilers that have the same maximum 

heat input capacity and that combust the same fuels. EPA has already issued National Stack 

Sampling Guidance to assist both the agency and stakeholders to identify sources that are 

equivalent. The inclusion of such provisions in the final rule will help to minimize the cost of 

emission testing without sacrificing the quality of emissions data from these sources. Although 

under a different program, EPA has long made such allowances under the RCRA BIF program 

for units that are equivalent. 

Response: The NESHAP program and the RCRA BIF program are not equivalent and EPA has 

the requirement to ensure that units are meeting the emission levels of the average of the top 

twelve percent of sources in a given source category. Based on the dataset used to establish the 

emission limits for this final rule, variation in emissions were noted despite similar controls 

installed on the unit. Multiple factors contribute to the emissions of HAP from a boiler and 

therefore, EPA has decided to test all units that are subject to emission limits.

Commenter Name: Laura Colban

Commenter Affiliation: Skanden Energy

Document Control Number: EPA-HQ-OAR-2002-0058-2876.1

Comment Excerpt Number: 2

Comment: The cost of annual testing is prohibitively high. The annual testing requirement is 

cost prohibitive for all thermal biomass systems, regardless of size. Annual testing may be 

feasible for boilers generating electricity, which receive substantial tax incentives, but it is not 
394

feasible for thermal-only systems. Many of our customers are rural schools, municipal buildings, 

greenhouses and similar. They are located in remote areas, far from experts capable of testing 

emissions. Recently, I tried to obtain comprehensive emissions testing for a boiler located at a 

public school in central Maine. Eventually I found one firm in New York and one in 

Massachusetts that were capable of doing the required tests. The cost of bringing these firms to 

central Maine, was nearly $20,000. This is equal to about 1/2 of a teacher’s salary. There is no 

possibility that a public school can afford to pay this testing fee even once, let alone annually. 

The best solution is to require an annual fuel test, to ensure that fuels do not contain high levels 

of toxins, and a one-time certification of boilers, whereby firms such as Skanden Energy, would 

be required to have one unit tested and third-party certified. 

Response: See the response to EPA-HQ-OAR-2002-0058-1879, Comment Excerpt Number 3.

Commenter Name: Gene Barr

Commenter Affiliation: Pennsylvania Chamber of Business and Industry

Document Control Number: EPA-HQ-OAR-2002-0058-3161

Comment Excerpt Number: 2

Comment: Emergency or back-up units should be subject to testing requirements in proportion 

to the limited extent to which those units are actually used. Application of this principle can. 

provide another example of how the goals of environmental. improvement and economic 

efficiency are not mutually exclusive. 

Response: Limited-use units are subject only to biennial tune-up requirements.

Commenter Name: Russell Strader

Commenter Affiliation: Boise Cascade, LLC

Document Control Number: EPA-HQ-OAR-2002-0058-2825

Comment Excerpt Number: 3

Comment: EPA should make testing and continuous monitoring more reasonable. 

Boise Cascade recommends that the stack testing frequency be reduced to once every 5 years at 

least for pollutants for which a pollution control device is used to meet the limits. Typically 

Pollution control devices are continuously monitored with suitable parametric methods that 

assure the units are being properly operated and maintained. Therefore, stack testing is not 

necessary to demonstrate compliance. More frequent stack testing for pollutants not controlled 

by a PCD may be reasonable unless suitable parametric monitoring can also reasonably 

demonstrate compliance with the emission limits. 

Response: See the response to EPA-HQ-OAR-2002-0058-1879, Comment Excerpt Number 3.
395

Commenter Name: James C. Jackson

Commenter Affiliation: Boise, Inc

Document Control Number: EPA-HQ-OAR-2002-0058-2855.1

Comment Excerpt Number: 5

Comment: Concerning stack/fuel testing, a one year testing frequency is too often. Due to the 

number of pollutants regulated, mobilization, the long test runs and the sophisticated laboratory 

analysis required (particularly for dioxin), Boise estimates that a round of compliance testing 

could cost at least $35,000. Further given various operating scenarios, it may be necessary to 

perform multiple stack tests for various fuel mixtures in order to assure compliance under 

various operating situations. Boise recommends that stack/fuel testing frequency be decreased to 

once every five years which is equal to the frequency of Title V permit renewals. Continuous 

parametric monitoring systems provide adequate assurance that a boiler is continuously 

operating in a compliant manner in the interim between stack tests. 

Response: See the response to EPA-HQ-OAR-2002-0058-1879, Comment Excerpt Number 3.

Commenter Name: Wayne J. Galler and Deborah A. Phillips

Commenter Affiliation: Georgia Industry Environmental Coalition, Inc

Document Control Number: EPA-HQ-OAR-2002-0058-2882.1

Comment Excerpt Number: 8

Comment: The stack testing requirements EPA has proposed as part of the Boiler MACT Rule 

are excessive and present an unreasonable economic burden, especially for smaller companies, 

without providing much additional environmental benefit. Annual stack testing is not required by 

the Clean Air Act, however, EPA is mandating this frequency for the first three years after the 

Rule goes into effect. The initial performance test and multiple monitoring requirements for each 

HAP is sufficient to verify compliance with the MACT standard. However, if EPA does not 

agree to eliminate the annual testing requirements, 

then EPA should at a minimum, reduce the testing frequency to once per Title V Permit cycle to 

provide some financial relief. 

Response: See the response to EPA-HQ-OAR-2002-0058-1879, Comment Excerpt Number 3.

Commenter Name: John M. Irving

Commenter Affiliation: Burlington Electric Department

Document Control Number: EPA-HQ-OAR-2002-0058-2954.1

Comment Excerpt Number: 8

Comment: Annual stack testing, fuel analysis, and work practice standards are burdensome and 

costly. We propose that the frequency for stack testing and fuel analysis coincide with operating 
396

permit renewals, if initial tests indicate that the regulated HAPs are greater than individual HAP 

thresholds; otherwise the unit would not need to test. 

Response: See the response to EPA-HQ-OAR-2002-0058-1879, Comment Excerpt Number 3.

Commenter Name: Richard Krock

Commenter Affiliation: The Vinyl Institute

Document Control Number: EPA-HQ-OAR-2002-0058-2944.1

Comment Excerpt Number: 8

Comment: The proposed rule requires annual emissions testing, i.e., once every 10 to 12 

months. The requirement to conduct testing every 10 to 12 months will result in an increased 

burden in some calendar years. There are a limited number of stack testing contractors available 

nationally. As a result, there may, in practice, be a small window for conducting such testing 

depending on the availability of qualified testing firms. Accordingly, VI recommends that if the 

requirement for annual stack testing is retained, the frequency for stack testing should be 

changed to once every 10 to 14 months. This would help reduce the annual costs of the rule, 

including offsetting the increased fuel costs to facilities from the requirement to burn the worstcase fuel mix during such tests. 

Response: See the response to EPA-HQ-OAR-2002-0058-2782.1,Comment Excerpt Number 7.

Commenter Name: Paul J. Allen

Commenter Affiliation: Constellation Energy

Document Control Number: EPA-HQ-OAR-2002-0058-3164

Comment Excerpt Number: 10

Comment: Comprehensive source testing every five years would be sufficient Annual source 

testing of mercury, HC1 and Dioxin/Furans is onerous and expensive. The source testing for 

these constituents should be once every 5 years, and if two samples indicate "non-detect", testing 

should not be required for the fuel type being burned at the facility. The CO and PM surrogates 

should be used as emission indicators, and the emission data compiled for the Title V Permits, 

(CEMS data for CO and annual source test data for PM) can be provided to the EPA on an 

annual basis. 

Response: See the response to EPA-HQ-OAR-2002-0058-1879, Comment Excerpt Number 3.

Commenter Name: Tom Midyett

Commenter Affiliation: Tennessee Paper Council

Document Control Number: EPA-HQ-OAR-2002-0058-2691.1
397

Comment Excerpt Number: 10

Comment: The Agency issued an Information Collection Request (ICR) in June 2009 that 

required recipients to conduct mandatory performance tests for select pollutants in order to fill 

data gaps in emission test data that EPA identified relative to CISWI units. Packaging 

Corporation of America’s Counce, TN mill received an ICR and was required to perform stack 

tests for cadmium, lead, mercury (Hg), dioxin/furan (D/F), carbon monoxide, condensable PM 

and PM2.5. The ICR prescribed 2-hour test runs for Hg and 4-hour test runs for D/F or, in lieu of 

the specified run durations, alternative minimum sample volumes. The demands that this 

exercise placed on the stack testing contractor’s staff, mill personnel overseeing the testing, and 

mill operations staff was extreme due to the duration of the test runs. 

The proposed rule requires that 4-hour stack test runs be performed annually for the worst-case 

fuel mix for the respective parameter of interest. EPA clearly does NOT appreciate the 

magnitude of labor and cost associated with this requirement. An additional compounding issue 

is the lack of qualified stack testing contractors if/when the rule goes into effect. Assuming that 

in excess of 10,000 industrial boilers are affected by the rule, and that the annual stack testing 

requirements must be satisfied for the entire population of affected units within a narrow window 

of time (e.g., within 10 – 12 months of the effective date of the rule, and annually thereafter), it is 

highly unlikely that there will be a sufficient number of qualified stack testers available. Further, 

testing for sensitive parameters like Hg and D/F requires a highly experienced stack testing team 

that understands the intricacies of associated with the test methods. Factor in fatigue due to 

performing extended stack tests (even for experienced teams) and the stage is set for a high 

probability of questionable or inaccurate results. 

Response: See the response to EPA-HQ-OAR-2002-0058-1879, Comment Excerpt Number 3.

Commenter Name: Tom Midyett

Commenter Affiliation: Tennessee Paper Council

Document Control Number: EPA-HQ-OAR-2002-0058-2691.1

Comment Excerpt Number: 11

Comment: The proposed rule requires performance stack testing while combusting “worst-case” 

fuel blends. This requirement multiplies the number of stack tests required as a function of fuels 

combusted at a facility as well as the parameter in question. To wit, it is entirely probable that a 

facility might need to conduct a set of 4-hour performance tests for D/F using one fuel blend, 

another set of tests for Hg using a different fuel blend, yet another set of tests for hydrogen 

chloride using a third fuel blend, etc. The costs associated with this kind of complicated testing 

matrix are multiples greater than what was incurred at the PCA-Counce facility to satisfy the 

ICR – and something the TPC believes is entirely unnecessary. 

Response: See the response to EPA-HQ-OAR-2002-0058-1879, Comment Excerpt Number 3.
398

Commenter Name: Tom Midyett

Commenter Affiliation: Tennessee Paper Council

Document Control Number: EPA-HQ-OAR-2002-0058-2691.1

Comment Excerpt Number: 12

Comment: We disagree with the Agency requiring annual stack testing, because there is no legal 

justification for annual testing under MACT (or in the court order). By design, MACT is a 

technology-driven standard. Initial performance tests have been used for all other pulp and paper 

industry MACTs to demonstrate that technology is capable of meeting the standard; any ongoing testing falls under the purview of the respective States. 

While the original Boiler MACT rule required annual PM testing (3 one-hour runs using EPA 

Method 5), many pulp and paper sources were doing this anyway so it was not particularly 

objectionable. Also, that rule allowed facilities to opt out of Hg, hydrogen chloride and Total 

Select Metals stack testing via once-in-five-years fuel testing to demonstrate compliance. The 

point is this; the testing burden associated with the proposed MACT is magnitudes of order 

greater than the original Boiler MACT – and totally unnecessarily so. We ask the Agency to 

modify the stack testing requirements to mirror earlier MACTs (e.g., Subpart S, Subpart MM) 

wherein performance testing consists of three 1-hour tests and testing is limited to an initial 

performance test (not annual testing) to demonstrate the efficacy of the control technology. 

Response: See the response to EPA-HQ-OAR-2002-0058-1879, Comment Excerpt Number 3.

Commenter Name: Gary W. Kruger

Commenter Affiliation: Morton Salt

Document Control Number: EPA-HQ-OAR-2002-0058-2883.1

Comment Excerpt Number: 14

Comment: EPA also states in the preamble, additionally, this proposed rule would require 

annual performance tests to ensure, on an ongoing basis, that the air pollution control device is 

operating properly and its performance is not deteriorating. 75 FR 32,033. This simply isn’t 

necessary as the continuous parametric monitoring requirements proposed in Table 8 of the 

Proposed Rule (fabric filter bag leak detection, opacity monitoring, etc) provide ample assurance 

the control equipment is operated properly and performance is not deteriorating. 

Response: See the response to EPA-HQ-OAR-2002-0058-1879, Comment Excerpt Number 3.

Commenter Name: Mark W. Kowlzan

Commenter Affiliation: Packaging Corp. of America

Document Control Number: EPA-HQ-OAR-2002-0058-2913.1

Comment Excerpt Number: 14
399

Comment: We find it disturbing that the Agency is requiring such extensive annual stack testing 

despite 

the fact that there is no legal requirement for annual testing under MACT (or in the court order). 

By design, MACT is a technology-driven standard. Initial performance tests have been used for 

all other pulp and paper industry MACTs to demonstrate that the technology is capable of 

meeting the standard; any on-going performance testing falls under the purview of the respective 

States under Title V operating permits. Moreover, the purpose of the extensive continuous 

compliance monitoring required in the rule is to assure on-going compliance, making the 

requirement for repeated, frequent performance testing unnecessary, arbitrary and extremely 

burdensome. Such a requirement, memorialized in a regulation, makes it virtually impossible to 

modify in the future. 

While the original Boiler MACT rule required annual PM testing (three l-hour runs using EPA 

Method 5) that many pulp and paper sources are already required to conduct for other 

compliance demonstration, this PM testing was not particularly objectionable. Also, that rule 

allowed facilities to opt out of Hg, hydrogen chloride and Total Select Metals stack testing via 

once-in-five-years fuel testing to demonstrate compliance. The point is this; the testing burden 

associated with the proposed MACT is magnitudes of order greater than the original Boiler 

MACT - and unnecessarily so. 

Response: See the response to EPA-HQ-OAR-2002-0058-1879, Comment Excerpt Number 3.

Commenter Name: American Crystal Sugar Company and Michigan Sugar Company

Commenter Affiliation: Patricia Hansen and Steven Smock

Document Control Number: EPA-HQ-OAR-2002-0058-2970.1

Comment Excerpt Number: 15

Comment: The requirement under §63.7575 to perform annual performance tests between 10 

and 12 months after the previous performance test is not feasible for seasonally operated, or 

campaign-based, facilities such as sugar beet plants. If a facility is always shut down (idle) 

during a set period, such as summer months, the gradually rotating stack test requirement of less 

than 12 months will eventually require the facility to test during normal scheduled downtime, 

forcing facilities into violation. This condition needs to be changed to allow a longer period of 

leeway with respect to annual compliance tests. The 9 to 15 month re-testing window allowed for 

Municipal Waste Combustors regulated under Section 129 of the Clean Air Act would be a more 

appropriate window. 

Response: See the response to EPA-HQ-OAR-2002-0058-2782.1, Comment Excerpt Number 7.

Commenter Name: Jerry Osheka

Commenter Affiliation: PPG Industries
400

Document Control Number: EPA-HQ-OAR-2002-0058-2938.1

Comment Excerpt Number: 16

Comment: Annual Performance Tests for Demonstrating Compliance is Overly Burdensome 

and Unreasonable. The proposed rule requires annual performance testing (once every 10 to 12 

months). See 63.7515 (a). The proposed requirement for annual performance testing is 

unreasonable and out of character with other MACT and NSPS standards and other state 

performance testing requirements. EPA has proposed the most aggressive performance testing 

requirements we are aware of on the largest MACT source category it has addressed to date. The 

Hazardous Waste Combustor MACT (Subpart EEE) for example requires a Comprehensive 

Performance Test only once every 5 years. Many MACT standards and NSPS only require one 

initial performance test unless there is a physical change to the control device that would 

increase emissions. The purpose of the initial performance test is to ensure that the technology 

installed is capable of meeting the emission limits. EPA has proposed extensive monitoring and 

recordkeeping that is meant to ensure continuous compliance with the emission standards. 

Therefore, the frequency of stack testing should be reduced to once every 5 years. 

Response: See the response to EPA-HQ-OAR-2002-0058-1879, Comment Excerpt Number 3.

Commenter Name: Edward E. Quick

Commenter Affiliation: Celanese International Corp

Document Control Number: EPA-HQ-OAR-2002-0058-2840.1

Comment Excerpt Number: 18

Comment: Emission testing requirements should be changed to be consistent with the 5-year 

Title V permit review cycle. 

In the preamble, EPA acknowledges that the cost of testing small boilers and process heaters is 

prohibitive. While the cost of emissions testing larger units is less prohibitive, EPA must 

consider these costs when establishing the frequency of testing. 

The benefits of testing more frequently than every 5 years do not justify the costs. HAP 

emissions significantly change only when operating parameters change or significant design 

changes occur. Absent significant modifications to an affected source, properly-established 

parameters are sufficient to ensure that emissions will not significantly change over time. 

Significant modifications will be tested under the provisions for new and modified sources, and 

do not need to be considered in ongoing test requirements. 

In addition, other regulations support a 5-year testing cycle. For example, 40 CFR §75 requires 

low mass emissions units to establish NOx emissions curves based on testing conducted every 5 

years. Several states require that testing be conducted upon each 5-year Title V permit renewal. 

Nearly all affected sources are required to have Title V Permits. The Title V permitting program 

provides the appropriate vehicle to implement a 5-year test requirement. 

Response: See the response to EPA-HQ-OAR-2002-0058-1879, Comment Excerpt Number 3.
401

Commenter Name: Steven G. Hanson

Commenter Affiliation: Graphic Packaging International

Document Control Number: EPA-HQ-OAR-2002-0058-2723.1

Comment Excerpt Number: 23

Comment: EPA’s proposed requirements for annual performance testing represent an 

unnecessary burden to regulated facilities with little environmental benefit. For other MACT 

regulations, EPA has ypically required an initial performance test which then establishes 

continuous monitoring requirements for demonstrating ongoing compliance. 

GPI — Macon Mill requests that EPA reconsider the proposed requirements for annual 

compliance testing and rely on the previous methodology of an initial compliance test with 

ongoing compliance monitoring. 

Response: See the response to EPA-HQ-OAR-2002-0058-1879, Comment Excerpt Number 3.

Commenter Name: Lee B. Zeugin

Commenter Affiliation: Utility Air Regulatory Group

Document Control Number: EPA-HQ-OAR-2002-0058-2880.1

Comment Excerpt Number: 24

Comment: To address the possibility that a source might be unable to conduct a required 

periodic stack test prior to its deadline due to some unanticipated event, such as a unit outage, 

UARG requests that EPA consider including a “grace period” for periodic testing similar to the 

period provided for performance of relative accuracy test audits under the Acid Rain Program, 

40 C.F.R. Part 75, Appendix B, § 2.3.3. Such a grace period allows a source time to complete 

testing after coming back on-line, but does not extend the deadline for future testing. Inclusion of 

an explicit grace period would benefit sources and EPA by eliminating the need for submission 

of source specific petitions to seek minor extensions of testing deadlines to address such events. 

Response: See the response to EPA-HQ-OAR-2002-0058-2782.1, Comment Excerpt Number 7.

Commenter Name: Barry Christensen

Commenter Affiliation: Occidental Chemical Corp

Document Control Number: EPA-HQ-OAR-2002-0058-2848.1

Comment Excerpt Number: 25

Comment: Clarification is needed as to how temporary tube blowing is factored into compliance 

tests for particulate matter. It is unclear to what extent these periods have been factored into the 
402

data base for coal and oil fired units or are to be considered during the performance tests for 

particulate. 

Response: Data for the best performing units in the subcategory show that the units achieved 

the levels of emissions upon which the floors are based. For liquid, while units blowing soot 

were not identified as best performers, emission controls can be installed to meet the floor levels, 

or sources may choose to change their fuel mix to comply with the standards. For coal units, coal 

units ranked #5, #11, and #18 all had tests associated with soot blowing and these units were 

identified in the top performing units.

Commenter Name: Bill Wemhoff

Commenter Affiliation: National Rural Electric Cooperative Association

Document Control Number: EPA-HQ-OAR-2002-0058-2835.1

Comment Excerpt Number: 26

Comment: Generally supports EPA’s proposal to use periodic performance tests, rather than 

CEMS, as the primary method for determining compliance with emission limits when limits 

cannot be met based on fuel analysis. NRECA believes that such periodic tests will ensure on an 

ongoing basis that the air pollution control device is operating properly and its performance has 

not deteriorated. 

Response: EPA acknowledges the commenter’s support.

Commenter Name: Jim Griffin

Commenter Affiliation: American Chemistry Council

Document Control Number: EPA-HQ-OAR-2002-0058-2792.1

Comment Excerpt Number: 192

Comment: EPA Should Allow Less Frequent Stack Testing. Proposed section 63.7515(a) 

requires annual emissions testing (once every 10 to 12 months). In some calendar years, a 

requirement to conduct testing every 10 to 12 months will result in an increased burden. 

Therefore, if the requirement for annual stack testing is retained, we request that the frequency 

for stack testing be changed to once every 10 to 14 months. This will help reduce the annual 

costs of the rule to offset the increased fuel costs facilities may incur during stack tests to 

accommodate the requirement to burn the worst case fuel mix. Requiring annual testing and 

restricting the allowable window between tests also will result in a resource burden if all 

facilities are doing annual stack testing at the same time. There are a limited amount of stack 

testing contractors available, and a small window for conducting testing may result in some 

facilities not being able to find a qualified testing firm. 

That said, the proposed requirement for annual stack testing is unreasonable and out of character 

with other NESHAP and NSPS standards and other state performance testing requirements. EPA 
403

has proposed the most aggressive performance testing requirements we are aware of on the 

largest MACT source category it has addressed to date. The Hazardous Waste Combustor 

MACT (Subpart EEE) for example requires a Comprehensive Performance Test only once every 

5 years. Many MACT standards and NSPS only require one initial performance test unless there 

is a physical change to the control device that would increase emissions. The purpose of the 

initial performance test is to ensure that the technology installed is capable of meeting the 

emission limits. EPA has proposed extensive monitoring and recordkeeping that is meant to 

ensure continuous compliance with the emission standards. If these extensive monitoring and 

recordkeeping provisions are finalized, the frequency of stack testing should be reduced to once 

every 5 years. 

Response: See the response to EPA-HQ-OAR-2002-0058-2782.1,Comment Excerpt Number 7.

Also, see the response to EPA-HQ-OAR-2002-0058-1879, Comment Excerpt Number 3.

Commenter Name: Jim Griffin

Commenter Affiliation: American Chemistry Council

Document Control Number: EPA-HQ-OAR-2002-0058-2792.1

Comment Excerpt Number: 193

Comment: EPA Should Add An Exclusion From Annual Testing Requirements For Limited Use 

Units. The requirement for annual stack testing in proposed section 63.7515 provides no relief 

for limited use units. As discussed earlier in these comments, we believe that limited use units 

should be subcategorized under this rule, and should also be eligible for reduced testing 

frequencies if they only operate a few hours per year or do not operate at all in a calendar year. 

Starting up these boilers for the express purpose of testing them creates an unnecessary expense 

in terms of both operational and testing cost, wastes fuel, and causes unnecessary HAP 

emissions. Therefore, limited use boilers should only be subject to one-time testing as long as 

they are operated less than 10% of the available operating time in a year. 

Response: Limited use units are subject only to a biennial tune-up requirement.

Commenter Name: Jim Griffin

Commenter Affiliation: American Chemistry Council

Document Control Number: EPA-HQ-OAR-2002-0058-2792.1

Comment Excerpt Number: 198

Comment: Facilities Should Be Able To Test One Unit If It Is Representative Of Multiple Units 

At The Facility. A measure that would reduce the cost of complying with the proposed rule 

would be to allow facilities to group like units and test one representative boiler instead of 

requiring testing of each and every boiler at the facility. For example, if a facility has multiple 25 

MMBtu/hr boilers that are of the same design and fire the same fuel, they should be able to test 

one of these boilers to represent emissions of the rest of the group. The periodic testing could 
404

"rotate" among the boilers in the group. This option would reduce the cost associated with 

emissions testing for facilities with many similar boilers. 

Response: See response to EPA-HQ-OAR-2002-0058-2632.1, Comment Excerpt Number 42.