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## EPA's Responses to Public Comments on EPA's National Emission Standards for Ha zardous Air Pollutants for Major Source Industrial Commercial Institutional Boilers and Process Heaters

Chapter 11 (Missing from Original Volume 2 EPA

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Comments letters and transcripts of the public hearings are also available electronically through h ttp://www.regulations.gov by searching Docket ID EPA

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- 0058.2 FOREWORD

This document provides EPA's responses to public co mments 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 3 2005. 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 publi c hearings are available at the EPA Docket Center Public Reading Room. Comments letters and transcripts of the public hearings are also available electronically through h ttp://www.regulations.gov by searching Docket ID EPA

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Due to the si ze 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 lett er or public hearing transc ript.

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 secti on 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/Comme rcial/Institutional Boilers (Docket ID: EPA

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- 0790); Identification of Non

- Hazardous Secondary Materials That Are Solid Waste (Docket ID: EPA

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- 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

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– 0119).

Given the identical proposal dates, and the related nature of these other rules, many commenters submitted comments to this rulemaking docket t hat 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, t his 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 document s prepared for these thr ee other rulemakings as they may contain topics relevant to these other rulemakings.3 

### Table of Contents Testing and Monitoring

................................ ................................ ................................ ................... 4
St ack 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

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### Testing and Monitoring

Stack Test Methods

Commenter Name: Dwayne Arino Commenter Affiliation: Jeld

- Wen, Inc Document Con trol Number: EPA

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- 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 2 8 data is inappropriate in this case. The comme n ter 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 Yo rk City Department of Environmental Protection Document Control Number: EPA

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- 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. Acc ording 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 us ing approved methods for particulate matter, me rcury, 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
note d 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 Comme nter Affiliation: CraftMaster Manufacturing, Inc5 Document Control Number: EPA

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- 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. Testi ng 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 co mmenters 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

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- 2797.1 Comment Excerpt Number: 21

Comment: The performance testing requirements need to be more clear (e.g. as the AWC and A F&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 som e 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 c reate 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 propo sed 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 to6 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. F or 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 bo iler 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 fo r 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 Gro up Document Control Number: EPA

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- 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; how ever, 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 determin in g 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

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- 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

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- 1907.1, Comment Excerpt Num ber 8.

Commenter Name: Britt S. Fleming Commenter Affiliation: Auto Group Document Control Number: EPA

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- 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 pollutan ts 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 a ccurately 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

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- 1907.1, Comment Excerpt Number 8.

Commenter Name: Timothy Hunt Commenter Affiliation: American Forest and Paper Association (AF&PA) Document Control Number: EPA

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- 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 ho ur 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

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- 1907.1, Comment Excerpt Number 8.

Commenter Name: Timothy Hunt8 Commenter Affiliation: American Forest and Paper Association (AF&PA) Document Control Number: EPA

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- 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 conti nuous 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

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- 2905 Comment Excerpt Number: 8

Comment: The Rule also p roposes 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 b ased 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 drawin g 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 l onger 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 quantit ation limit of 6 mg filter catch. B y 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 co mmon 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 t o 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, subs tituting 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 floor9 data and subsequent performance test data, to have the data r eported 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

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- 1907.1, Comment Excerpt Number 8.

Also, w e 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 acco unt 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 F orest Products Association, GPFPA Document Control Number: EPA

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- 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 b e 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 Met hod 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 diff iculty 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 operat ions, 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 g oes 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 c onditions 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 lim its 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 while10 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

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- 1907.1, comment excerpt number 8 in response to four hour testing.

Commenter Name: Walter Tyler Commenter Affiliation: Invista Document Control Number: EPA

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- 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 Boile r 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 emissi on 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 traditio nal 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 benefi t. 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

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- 1907.1, Comment Excerpt Number 8.

C ommenter Name: Randall D. Quintrell Commenter Affiliation: Georgia Paper and Forest Products Association, GPFPA Document Control Number: EPA

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- 2905 Comment Excerpt Number: 17

Comment: On page 32052 of the Federal Register, EPA notes: You mu st 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 hig hest 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 thes e 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 ste am 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
ope rational 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 ty pical 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

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, Comment Excerpt Number 10.

Commenter Name: Robert D. Morrison Commenter Affiliation: Abbott Laboratories Document Control Number: EPA

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- 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, Meth od 320 (instrumental sampling via FTIR) was accepted as an alternative. Abbott’s experience with Method 26 for HCl from a coal

- fired unit has been12 inconsistent and subject to interferences. Abbott’s recent experience with the FTIR method was good. This wou ld 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 approv ed 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 i nclude 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 co llection 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

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- 2 801.1 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

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Commenter Name: David A. Buff Commenter Affiliation: Golde r Associates Inc Document Control Number: EPA

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- 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: R obert D. Bessette Commenter Affiliation: Council of Industrial Boiler Owners (CIBO) Document Control Number: EPA

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- 2702.1 Comment Excerpt Number: 136

Comment: As discussed elsewhere in these comments, CIBO does not believe D/F standards sho uld 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 pr oposed 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 Affi liation: Council of Industrial Boiler Owners (CIBO) Document Control Number: EPA

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- 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 tha t 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 perfo rmance at the extremely low proposed emission limit levels. Therefore, CIBO recommends14 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 EPA

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- 3 213.1 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

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- 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). Requ iring 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 pr ocess 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 th e 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 Na tional Petrochemical and Refiners Association (NPRA) Document Control Number: EPA

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- 2960.1 Comment Excerpt Number: 16815 Comment: According to proposed 63.7525(c), stack tests must be performed at maximum normal operating load. This will requ ire 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 th ese high rates, fuel will be wasted, for boilers excess steam or hot water will have to be vented to the atmosphere and extra CO 2 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 CO 2 , criteria pollutants and HAPs. For standby and emergency boilers and process heaters, essentially all the firin g 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 req uire 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 boile r 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 emis sions 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

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- 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 spec ified 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 an d 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 emission s 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 de veloped 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

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- 1907.1, Comment Excerpt Num ber 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

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- 2960.1 Comment Excerpt Number: 176

Comment: Proposed Table 5 requires determining O2 and CO 2 during every performance test. For CO and dioxin/furan performance tests CO 2 is not needed because the emission limit is a concentration limit. For the other tests, either O2 or CO 2 can be used fo r the F

- factor calculation. Since O2 is needed for adjusting the measured results to the specified O2 level, measuring CO 2 is not needed for these tests either. Thus, CO 2 should be removed from the performance test requirements in Table 5. If sources wish to measure CO 2 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 CO 2 during performance tests optional.17 Response: EPA agrees with the commenter. Sources should correct for O 2 or CO 2 , and t here is no need to measure both during all performance tests. However, O 2 must be measured during the CO and dioxin tests.

Commenter Name: Jon T. Howard Commenter Affiliation: We ston Solutions, Inc Document Control Number: EPA

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- 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 f or 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 cri teria 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

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- 1907.1, Com ment Excerpt Number 8.

Commenter Name: Steve Smith Commenter Affiliation: LyondellBasell Industries Document Control Number: EPA

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- 3118.1 Comment Excerpt Number: 3

Comment: Many Gas 2 streams (e.g., petrochemical fuel gas) are often in tegrated 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 re finery. 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 oper ations 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 t he rule that will allow “Gas 2” units to qualify as “Gas 1.”

Commenter Name: Jon T. Howard Commenter Affiliation: Weston Solutions, Inc18 Document Control Number: EPA

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- 2737.1 Comment Excerpt Number: 3

Comment: EPA Method 29 allows the test er 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 lev els 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 incl uded. 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 repo r ted 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 Admin i strator for each and every Method 29
test.

Commenter Name: H. Allen Faulkn er Commenter Affiliation: Ascend Performance Materials, LLC Document Control Number: EPA

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- 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 parame ters. 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

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- 1907.1, Comment Excerpt Number 8.

Commenter Name: Jeffrey R.Klieve Commenter Affiliation: Monsanta Company Document Control Numbe r: EPA

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- 2754.1 Comment Excerpt Number: 519 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 2 009 on a coal

fired 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 s ample 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 cos t, 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 lim it.

Response: See response to EPA

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- 2775.1, Comment Excerpt Number 62.

Commenter Name: John C. Hendricks Commenter Affiliation: American Electric Power Document Control Number: EPA

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- 2703.1 Comment Excerpt Number: 6

C omment: 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

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- 2737.1 Comment Exc erpt 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 encourage20 EPA to evaluate the inclusion of this data in the st andard 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 Meth od 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 qu estions (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 (varia bility) into account in setting the standard.

Commenter Name: Jeffrey R.Klieve Commenter Affiliation: Monsanta Company Document Control Number: EPA

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- 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 als o 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

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- 2775.1, Comment Excerpt Number 62.

Commenter Name: Pamela F. Faggert Commenter Affiliation: Dominion Document Control Number: EPA

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- 2908.1 Comment Excerpt Number: 1121 Comment: EPA should also clarify the CO methods that are allowed under the rule (for example, the same op tions 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 b oiler 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 Numb er: EPA

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- 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 me thods) 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 Num ber: EPA

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- 2886.1 Comment Excerpt Number: 18

Comment: Four hour runs are not necessary for all pollutants

Response: See response to EPA

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- 1907.1, Comment Excerpt Number 8.

Commenter Name: David Foerter Commenter Aff iliation: Institute of Clean Air Companies Document Control Number: EPA

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- 2937.1 Comment Excerpt Number: 4122 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 H g, 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 po wer 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 concentrati ons (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: Do w Chemical Company Document Control Number: EPA

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- 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 T est 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 eac h 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 mini mum 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 th e 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

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- 1907.1, Comment Excerpt Number 8.

Comme nter Name: Chris M. Hobson Commenter Affiliation: Southern Company Document Control Number: EPA

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- 2741.1 Comment Excerpt Number: 56

Comment: Many of the test runs were conducted using sampling times that did not meet the minimum required sa mpling 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 te st 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

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- 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: Th e 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, the refore 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 d isagree 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 N ame: Chris M. Hobson Commenter Affiliation: Southern Company Document Control Number: EPA

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- 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 co nsistent 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 provi de 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

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- 1907.1, Commen t Excerpt Number 8.

Commenter Name: Russ A. Wozniak Commenter Affiliation: Dow Chemical Company Document Control Number: EPA

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- 2632.1 Comment Excerpt Number: 88

Comment: Section 63.7520(e) Should Be Amended to Allow Utilization of Altern ate 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. Do w 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 determin in g 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 Commente r Affiliation: Kentucky Division of Air Quality Document Control Number: EPA

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- 3176.225 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

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- 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 co mpliance 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 Usin g 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 consi der 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 Met hod 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 th e 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 acc urate 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 ap ply 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

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- 2998.1 Comment Excerpt Number: 10

Comment: M ethod 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 indi cate 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 Me thod 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 an d Deborah A. Phillips Commenter Affiliation: Georgia Industry Environmental Coalition, Inc Document Control Number: EPA

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- 2882.1 Comment Excerpt Number: 10

Comment: EPA has also proposed to change the testing methodology in a manner that wi ll 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 particulate27 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 ru ns, 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 i ncrease in the financial burden that our companies will have to bear.

Response: See response to EPA

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- 2775.1, Comment Excerpt Number 62.

Commenter Name: Mark W. Kowlzan Commenter Affiliation: Packaging Corp. of America Document Control Number: EPA

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- 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 an d 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 mi ll 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 annuall y in 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. There will be a lack of qualified stack resting contractors if/when the rule goes i nto 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 effec tive 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 pro posed 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 ent irely 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 th an 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 minimu m 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
componen t 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

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- 2849.1 Comment Excerpt Number: 14

Comment: ACCCI supports EP A’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 metal s 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 d ew 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 distortio ns 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 bene fits 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 appro ximately 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 Me thod 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 interpreting29 the rule after fi nalization, 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 o ther 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 conta in 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

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- 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 accorda nce 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 Propose d 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 prese nt, will be contained within the solid particulate matter entrained in30 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, includ ing 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 i n 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 i n 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 l ocated 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 fil ter 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 app roved 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 cos t 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 S ubpart 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 r esource 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 ru ns 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 dat a 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. Z eugin 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 Analyze r 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 thi s 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 tec hnical 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 3 0B 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.

Comme nter 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 u se 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 Par ticulate Matter33 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 demonst rating 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 Aff iliation: 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 met hods 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 include s 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

Comme nt: 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 o f 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., M ethods 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'Keefe34 Comment er 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

- h our 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 detect ed 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 f ollowed 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 adequat e. 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 ru ns 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 h ours 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 a ssociated with extended test run. See response to EPA

- HQ

OAR

- 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 Documen t 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 pub lished 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. Dem psey 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 Compl iance 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 foc us 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 tempera ture 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
approx imately 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 within36 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 t he 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 comp liance 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 MA CT 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

- mercu ry 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

- Pacifi c 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 l imits. 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 Measuremen t 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 c onvenience 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 sou rce 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

- 2880.137 Comm ent 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 promul gated 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 sorben t 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 collab oration 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 Exce rpt 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 3192 6; 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: 19638 Comment: E PA 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 opt ion 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
pe rformance 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 ai r 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 emissio ns 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

- t o

- 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 by39 commenter]. Each fuel source (i.e. animal litter, trees, etc.) has different const ituents. 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 upt ake 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 con tinuous monitoring of operational and parametric control measure conditions is appropriate for assuring ongoing compliance. Using the alternative monitoring procedures of the general provisions, t he rule allows for the source owner or operator to install a nd 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. T he 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 ins trument 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. Ot herwise, the high bias could potentially cause the facility to be noncompliant.

Response: The proposed rule does not require Hg CEMS.

Commenter Name: Peter Zalzal40 Commenter Affiliation: Environmental Defense Fund Document Control Number: EPA

- HQ

- OAR

- 2 002

- 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 fr om 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 mercu ry 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]onsumptio n 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 state s, 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 fre shwater 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, Mississ ippi, 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 63 0,000 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/ Hom e/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/ex posure.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 threa tened 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., drawi ng), 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

- press ure 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 res earch 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 de termined 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 c ardiovascular 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 A ND 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 ensur e 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 monitorin g 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

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- 2937.1, Comment Excerpt Number 42.

Commenter Name: Rich Raiders Commenter Affiliation: Arkema, Inc Document Control Number: EPA

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- 2751.1 Comment Exc erpt 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 contro l 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 re gulated 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 opt ing 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 applicat i ons and the general provisions will allow for use of CEMS as alternatives to other monitoring in other applica tions. 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 demonstr ating compliance with this rule

.

Commenter Name: Peter Zalzal Commenter Affiliation: Environmental Defense Fund Document Control Number: EPA

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- 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 c ontinuously 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 an43 indication of cumulativ e 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 concen trations 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

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Commenter Name: Peter Zalzal Commenter Affiliation: Environmental Defense Fund Document Control Number: EPA

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- 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 a dvanced 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). Th e 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: NESCAUM44 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 ki lns 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

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- 2869.1, Comment Excerpt Number: 2.

Commenter Name: Peter Zalzal Commenter Affiliation: Environ mental Defense Fund Document Control Number: EPA

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- 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 ADVA NCED 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 th e 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%20H g%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 th at 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, expres sly noting the protocol’s applicability to Hg CEMS installed on other facilities. [Footnote: Portland Cement MACT at 185 (concluding the45 NIST protocol is “fully capable of properly measuring the performance of gaseous Hg CEMS in many applications, includin g 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 S HEET 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

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- 2869.1, Comment Excerpt Number: 2.

Commenter Name: Michael Palazzolo Commenter Affiliation: Alcoa Inc Document Contro l Number: EPA

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- 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 o f 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 precede nts 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 s ystems that addresses this concern. We have not included any specific minimum46 data availability requirement. We believe that numerical missing data allowances quickly become targets or excuses, not incentives to conduct monitoring in a manner consistent w ith 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 a ffected 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 c alculations 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 po or 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 Affil iation: Louisiana Mid

- Continent Oil and Gas Association Document Control Number: EPA

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- 2699.1 Comment Excerpt Number: 14

Comment: Continuous monitors not needed on work practices. EPA should revise the proposed regulatory text to reflect E PA’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

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- 3137.1 Comment Excerpt Number: 58

Comment: Continuous emission monitoring systems (CEMS) should be allowed in lie u 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 proposed47 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

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- 2751.1, Comment Excerpt Number 6.

Commenter Name: Stephen R. Gossett Commenter Affiliation: Eastman Chemical Company Document Control Number: EPA

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- 3137.1 Comment Excerpt Number: 60

Comment: The provi sion 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 con trol 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 capricio us 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

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- 2967.1, Comment Excerpt N umber 13.

Commenter Name: N/A Commenter Affiliation: Sierra Club, Clean Air Task Force, Earthjustice, and Natural Resources Defense Council Document Control Number: EPA

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- 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

- bas ed standards. In its recent final MACT rulemaking for the Portland cement48 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 sim ilarly 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 r equirements, 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 proced ures of the general provisions, t he 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
sp ecifications 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

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- 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 m eans 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,

u ndertaken 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 fals eness of that assumption.

Response: See response to Document Control Number: EPA

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- 3187.1, Comment Excerpt Number: 70.

Commenter Name: Mike D. Craig Commenter Affiliation: New Energy Corp. Document Control Number: EPA

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- 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 show49 that NEC is at

— 50% of the PM limit. A Meth od 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 f inal 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 sit uations.

Commenter Name: Henry T. Graham Commenter Affiliation: Louisiana Chemical Association Document Control Number: EPA

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- 2731.1 Comment Excerpt Number: 14

Comment: EPA should revise the proposed regulatory text to reflect EPA’s inte nt, 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

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- 2699.1, Comment Excerpt Number 14.

Commenter Name: W. Randall Rawson Commenter Affiliation: American Boiler Manufacturers Association Document Control Number: EPA

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- 2698.1 Comment Excerpt Number: 22

Comment: * ABMA believes that the monitoring and CEMS requirements of th e 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 s uch 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 limitat ions and compliance demonstration methods. PM CEMS can demonstrate compliance with the rule's stringent emission limits.

Commenter Name: Matthew Todd and David Friedman50 Commenter Affiliation: American Petroleum Institute (API) and National Petrochemica l and Refiners Association (NPRA) Document Control Number: EPA

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- 2960.1 Comment Excerpt Number: 148

Comment: Proposed 63.7505(d) contains requirements applicable to any continuous monitoring system (CMS) associated with demonstrating compli ance 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 s ources with existing monitoring plans under part 60, App endix B that meet the requirements of 63. 7 525 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 Co ntrol Number: EPA

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- 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 r outine 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 a ctivities 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 as51 deviations under this rule and Title V in the cost and burden analyses or the Information C ollection 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

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- 2967.1, Comment Excerpt Number 13. Regarding cost s, 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 Proc ess 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

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- 2702.1 Comment Exc erpt 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 i nput, 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 mercur y. 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 used52 in lieu of scrubber parameter monitoring. EPA’s proposal to require sorbent input rates to an SDA to meet or exceed the rates dem onstrated in the performance test will be problematic and could result in a waste of sorbent.

Response: See the response to EPA

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- 2751.1, Comment Excerpt Number 6. For the HCL issue, see the response to EPA

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- 3137.1, Comme nt Excerpt Number 59.

Commenter Name: Robert D. Bessette Commenter Affiliation: Council of Industrial Boiler Owners (CIBO) Document Control Number: EPA

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- 2702.1 Comment Excerpt Number: 161

Comment: CEMS, COMS, or CPMS Regarding Deviation s. 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 monitor ing 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 CE MS 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 conditi ons 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 propo sed §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

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- 2967.1, Comment Excerpt Number 13.

Commenter Name: Steve Smith Commenter Affiliation: LyondellBasell Industries Document Control Number: EPA

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- 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

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- 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 6 0 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 r ule. 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

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- 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.

Respon se: 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

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- 2920.1 Comment Excerpt Number: 3054 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 sta ffing 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, EP A 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 flexibi li ties in the r ule 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 param etric control measure conditions is appropriate for assuring ongoing compliance.

Commenter Name: Pamela F. Faggert Commenter Affiliation: Dominion Document Control Number: EPA

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- 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 adjustm ents)." 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 th at 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 out

of

- control periods that could result in some failures of applicable performance specificatio ns. 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) t o 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 in55 order to bring it back into control. EPA’s propo sed 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

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- 2967.1, Comment Excerpt Number 13.

Commenter Name: David Foerte r Commenter Affiliation: Institute of Clean Air Companies Document Control Number: EPA

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- 2937.1 Comment Excerpt Number: 42

Comment: There are circumstances where the use of electronic, or “real

- time” Hg CEMS are beneficial. These include, a mong 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 performan ce (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. Monitori ng 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 sta ck 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 S tandards and Technology ( NIST) traceable, would undergo regular service, maintenance and calibrations, and would meet agreed

upon 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, t he rule all ows for the source owner or operator to install and operate continuous emissions monitoring systems in lieu of some testing and56 parametric monitoring. This process requires source owners to propose site

- specific monitoring plans for approval. These plans w ould 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

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- 2937.1 Comment Excerpt Number: 43

Comment: In the Clean Air Mercury Rule, EPA recogni zed 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 cont inuously 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 gr eater 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 kn owing 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 indus tries, 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 mon itoring 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”, rel eased 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

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- 2937.1, Comment Excerpt Number: 42.

Commenter Name: Russ A. Wozniak57 Commenter Affiliation: Dow Chemical Company Document Control Number: EPA

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- 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 co nstitutes 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 MAC T 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) ar e 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

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- 2967.1, Comment Excerpt Number 13.

Commenter Name: Chris M. Hobson Commenter Affiliation: Southern Company Document Control Number: EPA

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- 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 certif ication.

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 Contro l Number: EPA

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- 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 exper ience 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 t he 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 pro poses 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 monitorin g requirements.

Response: See response to EPA

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- 2967.1, Comment Excerpt Number 13.

Commenter Name: Jim Weeks Commenter Affiliation: Michigan Municipal Electric Association Document Control Number: EPA

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- 2795.1 Comment Ex cerpt 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 requiremen ts. 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 meeting59 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 f rom 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 i t 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 demon strate 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

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- 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 ai r 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 notabl y 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 c rude 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_Neuer

Etscheidt_dioxins_MSWI_gas_ashes_startup_shutdown.pdf] CEMS equipment for many of these pollutants has been test ed 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

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- 2937.1, Comment Excerpt Number 42.60 Commenter Name: Rachel Smolker Commenter Affiliation: Biofuelwatch Document Control Number: EPA

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- 2805.1 Comment Excerpt Number: 11

Comment: An additional reason that annual and/or quarterly tes ting 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 compos ition 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 mate rials.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 definitio n 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. Retr ieved 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 a nd 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 de bris 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

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- 2805.1, Comment Excerpt Number: 10.

Commenter Name: Jim Eubank Commenter Affiliation: Kentucky Division of Air Quality61 Document Control Nu mber: EPA

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- 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 wi ll heavily influence the emissions of both HAPs.

Response: See the response to EPA

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- 2751.1, Comment Excerpt Number 6.

Commenter Name: David W. Peightal Commenter Affiliation: Dakota Gasification Company Document Control Number: EPA

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- 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 Consult ants Document Control Number: EPA

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- 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 facilit y 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 meas ure conditions is appropriate for assuring ongoing compliance.

Commenter Name: Lee B. Zeugin Commenter Affiliation: Utility Air Regulatory Group Document Control Number: EPA

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- 2880.162 Comment Excerpt Number: 60

Comment: EPA proposes to re quire 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 d eviation 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 EP A 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 enforceme nt (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 mainten ance 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 correct ive action, or be calibrated in order to bring it back into control.

Response: See response to EPA

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- 2967.1, Comment Excerpt Number 13.



### CO CEMS

Commenter Name: Brian Swanson Commenter Affiliation: CMC Solutions and CMC Support Docume nt Control Number: EPA

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- 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 h eater 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 c ompliance 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 pre dictive 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 MMBt u 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 secti on 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 w ere 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 perf ormance 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 maintenanc e cost with a robust model developed and in place. PEMS used for compliance are certified according to the rigorous standards specified using PS

16 (Part 60) or Subpart E (Part 75). These certifications require the PEMS to pass a relative accuracy test au dit (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 an alysis, 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 compli ance 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 f

or 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 othe r 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 enh anced 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 operatio ns 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 inpu ts 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 ongoi ng 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 non

operating 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. Subseq uently, 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) o r high

pollutant 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 traini ng 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 a n 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
pr edictions. 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 w ith 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 te sts, 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 procedu res 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, a nd 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 Oc t 30, 1997 THW

- 31 ? Air Techniques Inc. Boiler #1 ? Air Techniques Inc. Boiler #2 ? Mobley

- Degussa 8/30/2000 Boiler #366 ? 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 Se rvices 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 ga s 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 compli ance with the standards would require an alternat iv e 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 Numbe r: EPA

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- 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.

Resp onse: 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

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- 1910.1 Comment Excerpt Number : 467 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, documentati on 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 Nam e: Robin Mills Ridgway Commenter Affiliation: Purdue University Document Control Number: EPA

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- 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

co ntinuous 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 sour ce 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 t o 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 to68 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 discussio n 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

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- 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 e mission 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 demons tration methods.

Commenter Name: Robin Mills Ridgway Commenter Affiliation: Purdue University Document Control Number: EPA

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- 2782.1 Comment Excerpt Number: 4

Comment: Alternative Monitoring for CO69 Purdue requests that EPA consider all owing 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 CO 2
. The lb/MMBTU would allow use of existing CO 2 CEMS as CO 2 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.

Comment er Name: Lisa Beal Commenter Affiliation: Interstate Natural Gas Association of America Document Control Number: EPA

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- 2756.1 Comment Excerpt Number: 4

Comment: Section 63.7525(a) should be revised to clearly indicate that CO CEMS are not

r equired 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 7 5 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, ex perience 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 cont inuous 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 En vironmental Services, Air Resources Division Document Control Number: EPA

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- 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 th at 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 t he CO limitations and compliance demonstration methods.

Commenter Name: Britt S. Fleming Commenter Affiliation: Auto Group Document Control Number: EPA

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- 2775.1 Comment Excerpt Number: 24

Comment: (13) Proposed § 63.7525(a), which requi res 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 gas

fired boilers/process heate rs 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 revisi ons to the CO limitations and compliance demonstration methods.

Commenter Name: Stephen R. Gossett Commenter Affiliation: Eastman Chemical Company Document Control Number: EPA

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- 3137.1 Comment Excerpt Number: 38

Comment: Revisions are n eeded 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 n umerical 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 Cont rol Number: EPA

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- 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) em ission 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 (CO 2 ), either as the diluent gas or to demonst rate compliance with other emissions standards. Many added CO 2 CEMS as a result of the recent Greenhouse Gas Reporting Rule. Sources which use CO 2 diluent gas monitoring in lieu of O2 diluent gas monitoring typically utilize dilution

- extraction sampling an d 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 dilution

extraction 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 su ch 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 infea sibility 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 o f heat input (lb/mmBtu). This would be consistent with most other emission standards in this rule, and with many other emissions72 monitoring requirements outside this rule (e.g., NSPS). This alternative standard would require only moderate, reasonable modif ications to dilution

- extraction CEMS that monitor CO 2 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 w ithout 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&P A) Document Control Number: EPA

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- 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 am ong 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

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- 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 sho uld 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 Respo nse: 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

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- 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 greate r 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 meth ods.

Commenter Name: Randall D. Quintrell Commenter Affiliation: Georgia Paper and Forest Products Association, GPFPA Document Control Number: EPA

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- 2905 Comment Excerpt Number: 26

Comment: One issue related to continuous monitoring pro visions in the proposed Rule is the diluent used for correcting the CO CEMS. PS2 allows the use of either 02 or CO 2 for this purpose. Several of our units are required to have CO 2 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 fact or 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 CO 2 concentrations and EPA Method 10 is specified for the measurement of CO concentrations. The proposed Rule at 75 FR 63.75 25(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 specifie d at §63.7525(a)(1) for the CO74 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 concent ration. PS 2, however, allows the use of either a CO 2 or 02 diluent analyzer to calculate the 02 correction. CO 2 is commonly used by other CEMS (NO,, SO2, etc.) because CO 2 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 CO 2 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 4 A 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 bo iler/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 CO 2 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

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- 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 re quires 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 monitori ng 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 ex clude 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 burdens ome 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

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- 2801.1 Comment Excerpt Number: 51

Comment: As in the original Industrial Boiler MACT rule, it wo uld 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 t han 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 revis ions 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

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- 2702.1 Comment Excerpt Number: 57

Comme nt: 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 ma nufacturing 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, dependin g 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. I mportantly, 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 under76 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

concen tration 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
met hods.

Commenter Name: Robert D. Bessette Commenter Affiliation: Council of Industrial Boiler Owners (CIBO) Document Control Number: EPA

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- 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 w ith 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

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- 2702.1 Comment Excerpt Number: 127

Comment: EPA proposed Carbon Monoxide limits listed in parts per million (ppm) cor rected 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 (CO 2 ), either as the diluent gas or to demonstrate compliance with other emissions standards. Sources which use C O 2 diluent gas monitoring in lieu of O2 diluent gas monitoring typically utilize dilution

- extraction sampling and conditioning77 systems, where compressed air is used to dilute the flue gas sample prior to being analyzed in a pollutant monitor. Dilution

- extr action 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 dilution

extraction sampling systems would be unable to adapt or expand their existing CEMS to monitor O2, those sou rces 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 sho uld 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 emis sions monitoring requirements outside this rule (e.g., NSPS). This alternative standard would require only moderate, reasonable modifications to dilution

- extraction CEMS that monitor CO 2 instead of O2 as the diluent gas. EPA could devise a CO lb/MMBtu stan dard 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

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- 2702.1 Comment Excerpt Number: 128

Comment: One member company project s 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 ar e 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.

Com menter Name: Robert D. Bessette Commenter Affiliation: Council of Industrial Boiler Owners (CIBO) Document Control Number: EPA

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- 2702.1 Comment Excerpt Number: 13178 Comment: E. The CO CEMS requirement for units Less Than 100 MMBtu is unreaso nable. 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 s uch 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 p rovide 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 Ins titute (API) and National Petrochemical and Refiners Association (NPRA) Document Control Number: EPA

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- 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. T he 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, regardles s 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 heat er.

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 Aff iliation: American Petroleum Institute (API) and National Petrochemical and Refiners Association (NPRA) Document Control Number: EPA

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- 2960.1 Comment Excerpt Number: 152

Comment: Where CO CEMS are not required (e.g., boilers and process hea ters 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 d emonstration methods.

Commenter Name: David Foerter Commenter Affiliation: Institute of Clean Air Companies Document Control Number: EPA

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- 2937.1 Comment Excerpt Number: 39

Comment: There is a fundamental thermodynamic application for c ombustion 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 red uces 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 con clusion 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

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- 2002

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- 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 inc ludes 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 incl ude 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: Ame rican Electric Power Document Control Number: EPA

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- 2002

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- 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 i ncluded in the rule as an acceptable diluent. CO 2 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 prea mble for revisions to the CO limitations and compliance demonstration methods.81 Commenter Name: Pamela F. Faggert Commenter Affiliation: Dominion Document Control Number: EPA

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- 2002

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- 2908.1 Comment Excerpt Number: 7

Comment: EPA should also cl arify 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 re visions to the CO limitations and compliance demonstration methods.

Commenter Name: Marvis A. Lewallen Commenter Affiliation: Clearwater Paper Document Control Number: EPA

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- 2002

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- 2862 Comment Excerpt Number: 8

Comment: We also request that E PA 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 significa nt 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 requiri ng 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 Regula tory Response Group Document Control Number: EPA

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- 2002

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- 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 Bonist all Commenter Affiliation: NewPage Corp Document Control Number: EPA

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- 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 th e 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

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- 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 demonstr ating 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 requiremen t 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 ap proach 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 requiremen t for PM CEMS is retained for these larger83 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 t he 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 Affil iation: Dow Chemical Company Document Control Number: EPA

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- 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 orde r 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 o perations. 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 ran ge 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 th e 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 pream ble 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 Shou ld 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, op erate, 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 Refi nery 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 inst ead 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 an d 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 monit or 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 continuou s 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

- e ffective 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.

T he 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

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- 2002

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- 2632.1 Comment Excerpt Number: 39

Comment: Dow comments that EPA should require CO and O2 CEMS only for un its 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 an d 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 mo nitoring 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 p ayback 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 instal lation 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 o ne (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 Compa ny 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 fi nalized 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 malf unction 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: Ch ris 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 (CO 2 ) as the diluent for calculating emiss ion 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 CO 2 monitors.

Response: See the preamble for revisions to the CO limitations and complianc e demonstration methods.

Commenter Name: Chris M. Hobson Commenter Affiliation: Southern Company Document Control Number: EPA

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- 2002

- 0058

- 2741.1 Comment Excerpt Number: 71

Comment: It is recommended that Section 63.7525(a)(i) and (ii) be revised t o 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 wi th 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 D ocument 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/mm Btu) listed for units which install and operate dilution

- extractive CEMS which measure emissions on a wet

basis.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 pr oposed 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 de signed 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 boile rs 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.

Resp onse: 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 proposed89 emission limits per this rule. This is evident given the absenc e 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.

Re commendation: 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: B ethany 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 em ission 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 32 014, 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 languag e 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 sect ion 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 emissio n 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 equipment90 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 t he CO limitations and compliance demonstration methods.

Commenter Name: William C. Herz Commenter Affiliation: The Fertilizer Institute Document Control Number: EPA

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- 2002

- 0058

- 2874.1 Comment Excerpt Number: 3

Comment: TFI requests confirmation th at 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 compli ance 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 in itial 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

- 2 910.1 Comment Excerpt Number: 491 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 no t 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 I ndustries 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 comp liance 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 feasib le, 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 emissio ns 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

- 20 02

- 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 addi tion 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 facto rs. 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 method s.

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 CO 2 as an alternative to O2. Some facility’s CEMs are now using CO 2 as the diluent instead of O2. The trend is that more and more sources are converting to CO 2 diluent when upgrading their CEMs due to other regulations, such as the Greenhouse Gas Reporting Rule.

Response: See t he 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 commo n 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 sh ut 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 sa me 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 i n 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: EP A 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 na tural 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
cap acity 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: 1094 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 maj or 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 otherwis e 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 perio dic 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

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- 3179 Comment Excerpt Number: 10

Comment: The requirement for a CEMS for units larger than 100 MMBtu/hr for CO monitoring

s hould 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 Contr ol Number: EPA

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- 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 typica lly 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 demonst ration methods.

Commenter Name: Richard Rosvold Commenter Affiliation: Xcel Energy Services, Inc Document Control Number: EPA

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- 2002

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- 2955.1 Comment Excerpt Number: 12

Comment: For units that are required to install CO CEMs, the regulation sh ould allow either carbon dioxide (CO 2 ) or oxygen (02) to be used as the diluent. Allowing a facility to use CO 2 as the diluent would allow the direct measurement of CO 2 to be used for the recently promulgated Mandatory Greenhouse Gas Reporting Rule. We sug gest that facilities be allowed to use either an 02 or CO 2 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

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- 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

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- 2002

- 0058

- 2875.196 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% O 2, 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 tradin g program. As a result, Citizens has a CEM system installed to measure emissions of NOx, using CO 2 as the diluent gas and for the calculation of heat input. The existing CEMs system is a dilution

extraction system, which will not accommodate an O 2 CEM, nec essary 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 CO 2 analyzer is necessary for that pro gram. Allowing the demonstration of CO compliance using lb/ MMBTU would allow use of existing CO 2 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 mainte nance of the 02 CEM.

Response: See the preamble for revisions to the CO limitations and compliance demonstration methods. The O 2 monitoring in the final rule is used to document compliance with an O 2 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 t hen 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

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- 2857.1 Comment Excerpt Number: 14

Co mment: 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 equipmen t 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

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- 2002

- 0058

- 3176.2 Comment Excerpt Number: 1697 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

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- 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 l imitations and compliance demonstration methods.

Commenter Name: Bill Wemhoff Commenter Affiliation: National Rural Electric Cooperative Association Document Control Number: EPA

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- 2002

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- 2835.1 Comment Excerpt Number: 24

Comment: Concerns rega rding 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 de monstration methods.98 Commenter Name: David O'Keefe Commenter Affiliation: USEC, Inc Document Control Number: EPA

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- 3122 Comment Excerpt Number: 26

Comment: CO CEMS. The proposal requires a CO CEMS for units with heat input greater or
eq ual 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

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- 2002

- 0058

- 2 849.1 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, pr oposed §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 parame ter 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 heat er 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

acc ordance 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 litt le 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 demon stration methods.99 Commenter Name: Kevin M. Dempsey Commenter Affiliation: American Iron and Steel Institute Document Control Number: EPA

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- 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 63.7 510(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 f or 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 heat er 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

a ccordance 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 shoul d 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

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- 2002

- 0058

- 2880.1 Comment Excerpt Number: 46

Comment: EPA proposes to require all units with heat in put 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 o f 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 P S 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 Commente r Affiliation: Utility Air Regulatory Group Document Control Number: EPA

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- 2880.1 Comment Excerpt Number: 47

Comment: Perhaps more significant, however, are EPA’s expectations for accuracy under the “relative accuracy specification.” When E PA 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

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- 2880.1 Comment Excerpt Number: 48101 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 th e 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 t o 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 N umber: EPA

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- 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 a t § 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 perce nt 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 reconside r 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 pre amble for revisions to the CO limitations and compliance demonstration methods.

Commenter Name: Christopher S. Colman Commenter Affiliation: Hovensa LLC Document Control Number: EPA

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- 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 propose d 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

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- 2002

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- 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 CO 2 ), 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 acc uracy 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 an d can accurately measure CO 2 , 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 conversions103 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

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- 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

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- 0058

- 2875.1, Comment Excerpt N umber 13.

Commenter Name: Lee B. Zeugin Commenter Affiliation: Utility Air Regulatory Group Document Control Number: EPA

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- 2002

- 0058

- 2880.1 Comment Excerpt Number: 51

Comment: Finally, in the preamble, EPA states that its proposal would require u nits 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 conduc ting 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 ini tial 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 fo r revisions to the CO limitations and compliance demonstration methods.

Commenter Name: Traylor Champion Commenter Affiliation: Georgia

- Pacific LLC Document Control Number: EPA

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- 2745.1 Comment Excerpt Number: 59

Comment: In the propose d 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 installe d 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 Comme nter Affiliation: Georgia

- Pacific LLC Document Control Number: EPA

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- 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 de monstrate 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

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- 2002

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- 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 CO 2 or O2 diluent analyzer to calculate the O2 correction. CO 2 is commonly used by other CEMS (NOx, SO2, etc.) because CO 2 analyzers are generally considered to be more reliable and stable than O 2 monitors. Many existing boilers/process heaters with existing CEMS will already have a CO 2 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
p roposed rule appears to require the use of an O2 diluent gas analyzer only. While the use of CO 2 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 explic itly allow for its use would be a far more efficient resolution.105 Response: See the response to EPA

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- 2875.1, Comment Excerpt Number 13.

Commenter Name: Lee B. Zeugin Commenter Affiliation: Utility Air Regulatory Group Document Control Number: EPA

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- 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 (CEM S). 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
pe rformance 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 pro posed 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 p pmv 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 dail y 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 specificatio n 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 pe rmits 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 C ommenter Affiliation: Utility Air Regulatory Group Document Control Number: EPA

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- 2880.1 Comment Excerpt Number: 99106 Comment: Although no specific quality assurance requirements are contained in the proposed rule, RMB is concerned that EPA m ight 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

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- 2002

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- 2880.1 Comment Excerpt Number: 100

Comment: Another non

- trivial issue posed by Procedure 1 is the definition of an "out

- of

control" 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, Procedu re 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.

Respons e: See the preamble for revisions to the CO limitations and compliance demonstration methods.

Commenter Name: Lee B. Zeugin107 Commenter Affiliation: Utility Air Regulatory Group Document Control Number: EPA

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- 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 emissi on limit (i.e., x ppm by volume, dry basis corrected to 3% 02). By choosing 02 as the basis for correction (instead of CO 2 ), EPA has precluded the use of dilution

- based monitoring systems, which have proved to be so reliable and accurate in other regulator y programs such as EPA’s Acid Rain Program. Dilution

- based systems measure on a wet basis and can accurately measure CO 2 . Dilution

- based systems cannot be used to measure 02 and generally do not measure on a dry basis. The monitoring and compliance determi nation 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

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- 0058

- 2875.1, Comment Excerpt Number 13.

Commenter Name: Jim Griffin Commenter Affiliation: American Chemistry Council Document Control Number: EPA

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- 2002

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- 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 inf ormation 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 opera tion 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 emissio n limits will be tested at representative operating conditions through performance stack tests.



### PM CEMS

Commenter Name: MSI

- Mechanical Systems, Inc108 Commenter Affiliation: MSI

- Mechanical Systems, Inc Document Control Number: EPA

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- 084 8.1 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 b oilers 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 com pliance 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

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- 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 applicat ions. 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 in stallation 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 ens uring 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 o f 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 chan ges. 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

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- 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 subcate gories 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 un it 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 liq uid

- 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 coal

fired 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: Dakot a Gasification Company110 Document Control Number: EPA

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- 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 m oni toring 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 continuou s 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 numerica l 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

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- 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. W e 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 appr oach, or other approaches that are acceptable to EPA, by conducting field tests at representative sources.111 Response: Continuation of Document Control Number: EPA

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- 2997.1. See response to Comment Excerpt Number: 3.

Commenter Name: Ni laksh Kothari Commenter Affiliation: Manitowoc Public Utilities Document Control Number: EPA

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- 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 mm Btu/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 Partic ulate 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 equipmen t 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. Cor vese Commenter Affiliation: Thermo Fisher Scientific, Inc Document Control Number: EPA

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- 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 Rel ative 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 Re sponse 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 concentration112 ranges. None of the reference t est 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 R RA 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 th e 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 Th ermo 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 bas is, 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 ap proach to EPA based on representative field tests of the final Hybrid PM CEMS design.

Response: Continuation of Document Control Number: EPA

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- 2997.1. See response to Comment Excerpt Number: 3.

Commenter Name: Ann W. McIver Commenter Affiliation: Citizens Energy Group Document Control Number: EPA

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- 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 o f 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 rul e.113 Commenter Name: Paul J. Allen Commenter Affiliation: Constellation Energy Document Control Number: EPA

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- 3164 Comment Excerpt Number: 9

Comment: Allow stack testing in lieu of continuous PM monitoring. In our opinion, PM testing is mo re 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

- e ffective. Annual source testing can meet the required need at a lower cost with reliable data

Response: EPA disagrees. See the response to EPA

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- 2913.1, Comment Excerpt Number 17.

Commenter Name: Michael L. Corvese Commenter Affiliat ion: Thermo Fisher Scientific, Inc Document Control Number: EPA

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- 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 i s 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 la nguage 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 duri ng 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 periodi c 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. I n 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 “ou t 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.1 14 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 f or 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 inc lude 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 utilit y 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 y ears 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 meas urement 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 limit ations 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 e nough 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 a t 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 activit ies (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 q uality 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 sy stem 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 America115 Document Control Number: EPA

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- 2913.1 Comment Excerpt Number: 17

Comment: The Boiler MACT proposal requires the installation and use of particulate matter continuous em issions 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 boiler s 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 electrif ication, 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 t he 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 CEM S 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 s uccessful 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 accept able 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. EP A 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 PS

11).116 Section 2.4 of PS

- 11 stresses the importance of planning for subsequent changes in effluent matrix and/or PM that mi ght 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 Affiliati on: Packaging Corp. of America Document Control Number: EPA

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- 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 four

hour 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 protoc ol 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 disagre e 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 mi crogram/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 measurem ent 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 agen cy 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: M ark W. Kowlzan Commenter Affiliation: Packaging Corp. of America Document Control Number: EPA

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- 2913.1 Comment Excerpt Number: 19

Comment: We believe that there are other valid indicators aside from PM CEMS, to determine if control equipmen t 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 Affiliati on: Michigan Biomass Document Control Number: EPA

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- 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 monitor ing (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

mo nitoring 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 facil ities 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.

Comme nter Name: Brad James118 Commenter Affiliation: Trinity Consultants Document Control Number: EPA

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- 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 ina ppropriate 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 i ncongruous 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 conditi ons. For the CEMS issue, see the response to EPA

- HQ

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- 0058

- 3179, Comment Excerpt Number 7.

Commenter Name: Brad James Commenter Affiliation: Trinity Consultants Document Control Number: EPA

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- 0058

- 2853.1 Comment Excerpt Number: 25

Co mment: 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 cur rently 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 s ources 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 sy stem (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 s pecifically 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 demonstrat ed 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 to119 these factors, U.S. Sugar requests further investigation by EPA prior to issui ng 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 dem onstrating 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 (em issions testing).

Response: See the response to EPA

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- 0058

- 2913.1, Comment Excerpt Number 17.

Commenter Name: Steven G. Hanson Commenter Affiliation: Graphic Packaging International Document Control Number: EPA

- HQ

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- 0058

- 2723.1 Co mment 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 es tablish MACT floors that account for variability and enable continuous compliance.

Response: See the response to EPA

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- 0058

- 3179, Comment Excerpt Number 7.

Commenter Name: Steven G. Hanson Commenter Affiliation: Graphic Packaging Interna tional Document Control Number: EPA

- HQ

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- 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 emissio ns 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 Mi ll is concerned about the viability of operating such a monitor on a multi

- fuel, load

- swinging boiler; particularly boilers combusting120 biomass and encourages further investigation by EPA prior to issuing a mandate for their use on such a wide

- scale.

Res ponse: See the response to EPA

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- 0058

- 2913.1, Comment Excerpt Number 17.

Commenter Name: Steven G. Hanson Commenter Affiliation: Graphic Packaging International Document Control Number: EPA

- HQ

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- 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 researc h 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 wo uld 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 manu facture 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

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- 2777.1 C omment 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) t o 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 grea ter 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 cont inuous 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. Rat her, 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 Specificat ion 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 industr y, 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 m any 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 a nd 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 $29,60 0 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 du ring 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, Ap pendix 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 shou ld 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.

R esponse: See the response to EPA

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- 2913.1, Comment Excerpt Number 17.

Commenter Name: Lee B. Zeugin122 Commenter Affiliation: Utility Air Regulatory Group Document Control Number: EPA

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- 2880.1 Comment Excerpt Number: 52

Commen t: 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 b e 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

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- 005 8

- 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 Q A 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 t he 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 de termine 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 Aff iliation: Utility Air Regulatory Group Document Control Number: EPA

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- 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 applica ble 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 UP L 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 on123 measurements conducted with the prescribed procedures includin g 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 fr om 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 concen trations 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 Affi liation: Utility Air Regulatory Group Document Control Number: EPA

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- 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 significantl y 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 ter m 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

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- 0246, at 3

- 10.] An additional point of concern is the lack of inf ormation 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 ga ses. 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 sel ect 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 affe cted 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 t hat their PM CEMS will meet the PS

- 11 criteria for multi

- fuel boilers. PS

- 11124 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 f or 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

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- 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

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- 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 complian ce determinations under this proposed rule. [See submittal for discussion of PM CEMS].

Response: See response to EPA

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- 2880.1, Comment Except Number: 52.

Commenter Name: Traylor Champion Commenter Affiliation: Georgia

- Pacific LLC Docu ment Control Number: EPA

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- 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 63125 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 mea sure 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 pro cedures 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 Affilia tion: Utility Air Regulatory Group Document Control Number: EPA

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- 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 eve n 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 coal

fired boilers in recent years, UARG is not aware of any instance in which a PM CEMS has been correlated at the leve l 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 signi ficant 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 pro vided 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 indistinguisha ble 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 t he response to EPA

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- 2913.1, Comment Excerpt Number 17.

Commenter Name: Traylor Champion Commenter Affiliation: Georgia

- Pacific LLC Document Control Number: EPA

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- 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 Su bpart 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, a pplying only PM CEMS to large units

.

Commenter Name: Lee B. Zeugin Commenter Affiliation: Utility Air Regulatory Group Document Control Number: EPA

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- 2880.1 Comment Excerpt Number: 61

Comment: For PM CEMS, EPA does not define such period s 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 ho urs 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 req uirement) and it limited the need for data collection to those instances when data were not collected for a minimum of “90 percent127 (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 tha t 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

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- 0260 at 13. In sho rt, 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 rulema king 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

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- 2997.1, Comment Excerpt Number 9.

Commenter Name: Lee B. Zeugin Commenter Affiliation: Utility Air Regulatory Group Document Control Number: EPA

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- 2880.1 Comment Excerpt Number: 101

Comment: EPA’s proposed IB MACT rule requires PM CEMS f or 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 realize s. 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 co nventional CEMS (SO2, NOx, CO 2 , 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 proc ess, 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 p ublished in the Federal Register Performance Specification 11 (PS

11), 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 P S

- 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 ra nge 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 consider ed 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 calib ration 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 statistica lly 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 conduct ed 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 Num ber: EPA

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- 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, bio mass 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 Portla nd 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, CO 2 , 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 corre ct 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 belo w, 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 (PS

11), Specification and Test Procedures for Par ticulate 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 respon se 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

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- 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

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- 2880.1 Comment Excerpt Number: 103

Comment: An import ant 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 resu lts 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’s130 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 concent ration," 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 CEM S to comply with PS

11 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 indistingui shable 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 l ow 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 a nd 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 e stablishing 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 emission s 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

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- 2880.1 Comment Excerpt Number: 104131 Comment: Proposed section 63.7525(b)(6) states, when PM emissions data are n ot 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 operatin g 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 a verage is referenceD in this section, which is inconsistent with proposed §63.7525(b)(3), as discussed above.

Response: See the response to EPA

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- 2997.1, Comment Excerpt Number 9.

Commenter Name: Jim Griffin Commenter Affiliation: Amer ican Chemistry Council Document Control Number: EPA

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- 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 complian ce 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 inpu t 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 d emonstrating 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 i nstallation 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 MM Btu/hr.132 Response: See the response to EPA

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- 2913.1, Comment Excerpt Number 17.

Commenter Name: Jim Griffin Commenter Affiliation: American Chemistry Council Document Control Number: EPA

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- 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 reg arding 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.

Ther e 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 scintillat ion, 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 f uel 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 o perating 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

r outinely capable of meeting the requirements of PS 11 and PS2 and measure PM emissions accurately.133 Response: Continuation of Document Control Number: EPA

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- 2792.1, Comment Excerpt Number: 169. See that response.

Commenter Name: Jim G riffin Commenter Affiliation: American Chemistry Council Document Control Number: EPA

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- 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 performe d 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
p eriods 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 fac ilities 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 accura te 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 inter val (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 p robability 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 demonstrating134 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 perturb ing 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 scatt er 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 mic rogram/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 measuremen t 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 l imits, 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: Richa rd L. Killion Commenter Affiliation: Babcock and Wilcox Power Generation Group Document Control Number: EPA

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- 2722.1 Comment Excerpt Number: 3

Comment: B&W, also a very large supplier of continuous emissions monitoring systems and software (CEMS), is concer ned that available C EMS 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

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- 2913.1, Comment Excerpt Number 17.135 Commenter Name: Robert Ellerhorst Commenter Affiliation: Michigan State University Document Control Number: EPA

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- 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 ele ctrostatic 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 addi tion 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 throug h 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 fo r 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
met hods. 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 t he 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 eac h 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 parti culate 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 of136 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 wi th PM limits.

Response: See the response to EPA

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- 2875.1, Comment Excerpt Number 8.

Commenter Name: Robin Mills Ridgway Commenter Affiliation: Purdue University Document Control Number: EPA

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- 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 part iculate 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 coal

fired 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 conditi ons 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 emiss ions 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 par ticulate 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 EP A 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 de tection system provides ongoing monitoring of the bag house component performance and provides for continuous compliance demonstration.

Response: See the response to EPA

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- 2875.1, Comment Excerpt Number 8.137 Commenter Name: Tim Keneally Commenter Affiliation: KapStone Paper and Packaging Corporation Document Control Number: EPA

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- 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 an d 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 EPA

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- 2913.1, Comment Excerpt Number 17.

Commenter Name: Michael Palazzolo Commenter Affiliation: Alcoa Inc Document Control Number: EPA

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- 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 min imum 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

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- 2997.1, Comment Excerpt Number 9. In the final rule, 63.7525(b)(6) and the reference to Method 19 has been remove d.

Commenter Name: Jack Carter Commenter Affiliation: Weyerhaeuser Company Document Control Number: EPA

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- 2797.1 Comment Excerpt Number: 24138 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 mo re. 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

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- 2913.1, Comment Excerpt Numb er 17.

Commenter Name: Timothy Hunt Commenter Affiliation: American Forest and Paper Association (AF&PA) Document Control Number: EPA

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- 3213.1 Comment Excerpt Number: 285

Comment: EPA’s requirement that PM CEMS should be used to demonst rate 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 dem onstrate 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 ba sed 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

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- 2913.1, Comment Excerpt Number 17.

Commenter Name: Timothy Hunt Commenter Affiliation: American Forest and Paper Asso ciation (AF&PA) Document Control Number: EPA

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- 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

e xpected 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 vari ety 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 avai lability. 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. * Similar ly, 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

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- 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

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- 3213.1 Comment Excerpt Number: 287140 Com ment: 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 t he 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 s olution 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 th an 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 emiss i on leve ls 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: Tim othy Hunt Commenter Affiliation: American Forest and Paper Association (AF&PA) Document Control Number: EPA

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- 3213.1 Comment Excerpt Number: 288

Comment: EPA has failed to document that PM CEMS are sufficiently precise and accurate to deter mine 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%) m id 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 caus e a response, even though PM emissions were141 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 complianc e, 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 emission s 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 accurac y 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 t o 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 ru le. 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 requ irements without further adjustment.

Commenter Name: Timothy Hunt Commenter Affiliation: American Forest and Paper Association (AF&PA) Document Control Number: EPA

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- 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 Refere nce 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 60.2 730 (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 a djustments), 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 force d to have duplicate PM CEMS systems so that142 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

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- 2997.1, Comment Excerpt Number 9.

Commenter Name: Timothy Hunt Commenter Affiliation: American Forest and Paper Association (AF&PA) Document Control Number: EPA

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- 2002

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- 3213.1 Comment Excerpt Number: 290

Comment: To measure and repo rt 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 the se 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 o f 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 cal culate 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 recogn ize 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) al lowing the use of a calculation constant rather than constant direct measurement. There are many examples of CEMS data management systems that apply site

specific constant moisture values (e.g., established during emissions testing) that continue to pass

r elative 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 m easurement.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

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- 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 inst alled 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 typ e of alternative.

Commenter Name: Mike D. Craig Commenter Affiliation: New Energy Corp. Document Control Number: EPA

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- 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, emis sion 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

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- 2997.1, Comment Excerpt Number 9.

Commenter Name: Mary Graham Commenter Affiliation: C harleston Metro Chamber of Commerce Document Control Number: EPA

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- 2732.1 Comment Excerpt Number: 10144 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 establis h 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 us ed in the forest products industry that need to be addressed before installation of such systems.

Response: See the response to EPA

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- 2913.1, Comment Excerpt Number 17.

Commenter Name: Melvin E. Keener Commenter Affiliation: Coalition for Responsible Waste Incineration (CRWI) Document Control Number: EPA

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- 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 thes e 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 complianc e 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

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- 3179, Comment Excerpt Number 7.

Commenter Name: Ashok K. Jain Commenter Affiliation: National Council for Air and Stream Improvement Document Control Number: EPA

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- 2804.1145 Comment Excerpt Number: 14

Comment: 3. Comment on EPA Determination that PM CEMSs Should Be Installed on Boilers with Heat Input Ca pacity 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 tim e 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 comp liance 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 performanc e 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 u pon 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

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- 2002

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- 2913.1, Comment Excerpt Number 17.

Comm enter Name: Ashok K. Jain Commenter Affiliation: National Council for Air and Stream Improvement Document Control Number: EPA

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- 2002

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- 2804.1 Comment Excerpt Number: 15

Comment: There are several significant issues with installing PM CEMSs on mult i

- 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 i nstruments. The responses of these146 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 res ults 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 in stallation 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

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- 2002

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- 2804.1, Comment Excerpt Number: 14.

Commenter Name: Ashok K. Jain Commenter Affiliation: National Council for Air and Stream Improvement Document Control Number: EPA

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- 2002

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- 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 th e 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 w ith 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 accomplish ed. 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, i t 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 n ecessary 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 cap ture that emission level for the correlation testing.

Achieving a range of emiss i on 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 dev ices 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

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- 2740.2 Comment Excerpt Number: 17

Comment: EPA In correctly 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 an d 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 t o 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 as suring 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 foun d 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

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- 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 betwee n 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 val ues 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 comp liance 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 c ommenter.

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/file s/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

measureme nts 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 Imp rovement Document Control Number: EPA

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- 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 ro lling average.” (Note: The149 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 unrea listic. 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 on e 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

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- 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

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- 2002

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- 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 g as 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

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- 3213.1, Comment Excerpt Number 290. See that response.

Co mmenter Name: William A. Moore Commenter Affiliation: Luminant Document Control Number: EPA

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- 2780.1 Comment Excerpt Number: 22150 Comment: Luminant does not support use of PM CEMS to demonstrate continuous compliance. EPA’s proposed rule requ ires 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
requ irement 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 uni t 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 monitori ng 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 concentr ations 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.

Respon se: See the response to EPA

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- 2913.1, Comment Excerpt Number 17.

Commenter Name: Randall D. Quintrell Commenter Affiliation: Georgia Paper and Forest Products Association, GPFPA Document Control Number: EPA

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- 2002

- 0058

- 2905 Commen t 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, biomas s 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 i s 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 d ependent upon particle characteristics. Moreover, light scattering cannot be employed for wet

- scrubber

- controlled sources. Our industry uses a wide variety of fuel151 types often burned at the same time with a wide range of proportions, and we have serious

re servations 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 four

hour stack tes t 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 ex ercise. 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 so urce 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 ma kes 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 a nd 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 mon itoring 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

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- 2913.1, Comment Exc erpt Number 17.

Commenter Name: David A. Buff Commenter Affiliation: Golder Associates Inc Document Control Number: EPA

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- 2801.1 Comment Excerpt Number: 50

Comment: A PM CEMS is not necessary since all boilers have a PM control device a nd 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 on152 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 ye ar, 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 a nd 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

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- 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 requir ed. 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

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- 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

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- 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 particu late 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 operation153 of bag leak detection systems i n 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 demonstra tion.

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 b e reasonable for the affected sources.

Commenter Name: Robert D. Bessette Commenter Affiliation: Council of Industrial Boiler Owners (CIBO) Document Control Number: EPA

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- 2702.1 Comment Excerpt Number: 117

Comment: EPA should consider th e 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 ins talling 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 syste ms 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 standar d 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 speci fic 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

n o 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 t hat 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 c apability 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 t he 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

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- 2002

- 0058

- 2913.1, Comment Excerpt Number 17. Also, o n the sensitivity is sue, 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 le vels (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 est ablishing 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 prescribe d 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

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- 2702.1 Comment Excerpt Number: 118155 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 suitabil ity 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

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- 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 fue ls, 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 "b iomass 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 result s 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 ind ustry 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 sim ultaneous 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 Do cument Control Number: EPA

- HQ

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- 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

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- 2702.1 Comment Excerpt N umber: 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 emissi ons 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 con tinue 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 de sirable 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 coeff icient 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 7 5% 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 E PA’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 breakd owns, 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 Secti on 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 d ata 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 th e 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 s ources 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

ne ar 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 sup port of the rule. Once those emissions limits are established, it is agency policy that determinations of compliance are to be based on158 measurements conducted with the prescribed procedures including meeting all of the control quality assurance and qualit y control requirements without further adjustment.

Also, See the response to EPA

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- 2997.1, Comment Excerpt Number 9 o n the data availability issue

.

Commenter Name: Robert D. Bessette Commenter Affiliation: Council of Industrial Boiler O wners (CIBO) Document Control Number: EPA

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- 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 publis hed 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 boiler s, 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 CEM S 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

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- 3213.1, Comment Excerpt Number 290. Also, the averaging period has been revised to a 30

- day ro lling average.

Commenter Name: Robert D. Bessette Commenter Affiliation: Council of Industrial Boiler Owners (CIBO) Document Control Number: EPA

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- 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 to159 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 pr oviding 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 Affilia tion: Council of Industrial Boiler Owners (CIBO) Document Control Number: EPA

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- 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 us e 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 a ssurance 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 t he 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

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- 2702.1 Comment Ex cerpt 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 a nd 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 annua l PM compliance test. In addition, because units that demonstrate compliance with the PM emission160 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 o r 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 Per formance 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 t o 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 Co ntrol Number: EPA

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- 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 d oes 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 mo isture 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 fiel d 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

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Commenter Name: David Bonistall Commenter Affiliation: NewPage Corp Document Control Number: EPA

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- 2920.1161 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 th rough 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 c ould 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. Fai nter, Jr. Commenter Affiliation: Association of Electric Companies of Texas Document Control Number: EPA

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- 2790.1 Comment Excerpt Number: 12

Comment: Oppose particulate matter (PM) Continuous Emissions Monitors (CEMS) to demonstrate continu ous 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 correlat ed. 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 t o 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

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- 3179, Comment Excerpt Number 7.

Also, o n the sensitivity issue, related to precision and accuracy, we disagree that measurement s 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 sa mpling).

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 develo ped 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

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- 2808.1 Comment Excerpt Number: 28

Comment: The Proposed Rule requires all boilers with a he at 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 whatsoe ver, 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 inaccur acy 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 monitorin g 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 sufficie nt to ensure proper control device operation. Adding a PM CEMS163 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). Cert ain 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 al ready 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

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- 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 re gulatory 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 a nd 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 limits164 could be streamlined because of the PM CEMS requirements in this rule, but d oes 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

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- 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 situ ations 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 be en 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 s cattering 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

em issions. 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 technol ogies 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.

C ommenter Name: Chris M. Hobson Commenter Affiliation: Southern Company Document Control Number: EPA

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Comment: RMB does not believe the use of a PM CEMS as a compliance monitor is appropriate due to technic al 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 indicatio n 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 proposed165 rule, includes relatively generous [Footnote: PS

- 11 statistical criteria: (1) the confidence interval (95%) half range at the median PM CEMS response va lue 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 performanc e 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 measureme nts 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 cond itions 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 appr oach 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 resp onse to EPA

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Commenter Name: Chris M. Hobson Commenter Affiliation: Southern Company Document Control Number: EPA

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Comment: The proposed rule specifie s 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. So urces 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 uni ts 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

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- 2741.1 Comment Excerpt Number: 73

Co mment: 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 Admi nistrator 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 unre alistic. 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 s hall 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 63.75 25(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 Ad ministrator 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

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Commenter Name: Chris M. Hobson Commenter Affiliation: Southern Company Document Control Number: EPA

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- 2741.1 Comment Excerpt Number: 75

Comment: Se ction 63.7540(a)(9)(ii) states: “During each PM correlation testing run ..., PM and O2 (or CO 2 ) 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 dry

basis 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 concentr ations 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, Performan ce 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 sectio n 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 ex amples of CEMS data management systems that apply site

specific 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
str ucture 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 D ocument Control Number: EPA

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- 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 complia nce 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 Per formance 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 t o 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

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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 contr olled by ESPs and168 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 requirem ents 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

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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
pr omulgated, 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 add ressed 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 ca nnot 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 crea ting 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,
espe cially 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 act ions 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 resul t 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 char acteristics 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 certif ication 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 c oal fired units and 0.02 lb/MMBtu for existing coal fired units.)

Response: See the response to EPA

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- 2913.1, Comment Excerpt Number 17.

Commenter Name: Michael L. Corvese Commenter Affiliation: Thermo Fisher Scientific, Inc Docume nt Control Number: EPA

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- 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 conf erence 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 el ement 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 Becau se 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 reca librate 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 P M 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 belo w.)

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 s elf

- 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, ve ry 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 ce rtification 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 determini ng 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

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- 2997.1 Comment Ex cerpt 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 lang uage 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 developm ent 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
approva l 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
pr ocedures. 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 recommend ations 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 standar d, 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 Committee172 Document Control Number: EPA

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- 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 t heir 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 bef ore installation of such systems.

Response: See the response to EPA

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- 2913.1, Comment Excerpt Number 17.

Commenter Name: Michael L. Corvese Commenter Affiliation: Thermo Fisher Scientific, Inc Document Control Number: EPA

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- 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 c oncentration 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 lig ht 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 te st 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, referenc e 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 comparis ons 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 poin t sampling, which would allow for reduction in the amount of time to perform the test, reduction in the173 amount of air pollution emitted while performing the necessary tests at elevated PM concentrations, and reducing the costs of the test. (See also commen t 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 includ ed 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 indi vidual state agency determinations.

Response: Continuation of Document Control Number: EPA

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- 2997.1. See response to Comment Excerpt Number: 3.

Commenter Name: Domtar Corp Commenter Affiliation: Guy R. Martin Document Control Number: EPA

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- 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 pr imary 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 i n 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 avoi d 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 sa mple 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) establish174 performance specifications for stack gas moisture monitors, and (2) determine the accuracy and precision of PM CEMS on biomass and multi

- fuel boilers and CIS WI sources.

Response: See response to EPA

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- 3213.1, Comment Excerpt Number 290.

Commenter Name: Michael L. Corvese Commenter Affiliation: Thermo Fisher Scientific, Inc Document Control Number: EPA

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- 2997.1 Comment Exc erpt 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 non

stratified to reduce correlation testing costs and improve the ac curacy 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 o rder 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 unif orm 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 perfo rmed 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 de vices 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 e ntire 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 the se 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 c oncurrent 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 coefficien t 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 approa ch 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 emissio n 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 concentra tions

Save industry substantial costs and trouble from failed correlation attempts.

Response: Continuation of Document Control Number: EPA

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- 2997.1. See response to Comment Excerpt Number: 3.

Commenter Name: James C. Jackson Commen ter Affiliation: Boise, Inc Document Control Number: EPA

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- 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. Whi le 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 in176 terms of steam load a nd 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

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- 2913.1, Comment Excerpt Number 17.

Commenter Name: Jim Griffin Commenter Affiliation: American Chemistry Council Document Control Number: EPA

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- 2792.1 Comment Excerpt Number: 172

Comm ent: 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 a pproved 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 specif ied 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 acti vities (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 requiremen ts 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

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- 2997.1, Comment Excerpt Number 9.

Commenter Name: Jim Griffin Commenter Affiliation: American Chemistry Council Document Control Number: EPA

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- 2792.1 Comment Excerpt Number: 173177 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 sh ould 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

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- 3213.1, Comment Excerpt Number 290.

Commenter Name: Jim Griffin Commenter Affiliation: American Chemistry Council Document Control Number: EPA

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- 2792.1 Comment Excerpt Number: 174

Comment: Absent the questions about the feasibili ty 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 boil ers, 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 s ize is a reasonable approach to ensuring continuous compliance with the standards.

Commenter Name: Jim Griffin Commenter Affiliation: American Chemistry Council Document Control Number: EPA

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- 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 instal led 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 E SP is redundant since they are indicators of emissions of the same pollutant, particulate matter, and it makes no sense to require178 both on the same unit. We recommend that this redundancy be eliminated by requiring only one continuous monitor.

In the pro posed 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 fabri c 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: Tabl e 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

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- 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 demonstratio n should be adopted in the final rule in lieu of a PM CEMS.

Response: See the response to EPA

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- 3179, Comment Excerpt Number 7.

Commenter Name: Lee B. Zeugin Commenter Affiliation: Utility Air Regulatory Group Document Control Number: EPA

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- 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 numer ical 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, the179 rulemaking record contains no analysis in which EPA purports to equate the snap shot 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 Docu ment Control Number: EPA

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- 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 mois ture 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 opaci ty 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 Comm enter Affiliation: Alcoa Inc Document Control Number: EPA

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- 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 f ollows 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

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- 2893.1 Comment Excerpt Number: 28

Comment: It is our understanding that the proposed rules require inst alling 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 br oken 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 fu el 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 associate d 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, p rovides 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

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- 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 d etermining 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 pl ume 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 support s 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 stand ards 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 equiv alent 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 p er Section 63.8(f).

Commenter Name: Chris Greissing Commenter Affiliation: Industrial Minerals Association Document Control Number: EPA

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- 2740.2 Comment Excerpt Number: 19

Comment: Existing COMS Systems. The requirement of CEMS will requ ire 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, testi ng 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 emissi ons.

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 perio dic 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 G rumman Document Control Number: EPA

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- 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 enforceable182 opacity limitations, and in many cases the opac ity 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, supplem ented 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 demo nstrate compliance without needing to collect COMS or control equipment parametric monitoring data.

Commenter Name: Pamela F. Faggert Commenter Affiliation: Dominion Document Control Number: EPA

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- 2908.1 Comment Excerpt Number: 26

Comm ent: 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: Limit ed

- 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

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- 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 residu al 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 gene ral 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

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- 3122 Comment Excerpt Number: 11

Comment: Op acity 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. C onflict 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 no t 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

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- 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 s crubber) 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 pl ates. 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 opaci ty 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 th at 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

e mission 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 characteristic s and control device performance, and are established as enforceable operating limits routinely in NESHAP184 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

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- 2880.1 Comment Excerpt Number: 36

Comment: It is well known that the relationship between opacity and mass PM (i.e., mas s concentration) is affected by the particle size distribution, particle shape, and the color (reflectivity) of the flyash. UARG Comments, EPA

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- 0413, Attachment C at 8. Numerous tests have confirmed that western subbituminous coal ash creat es 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 opa city operating limit that the PM limit is not being met.

Response: See response to EPA

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- 2880.1, Comment Excerpt Number 35.

Commenter Name: Lee B. Zeugin Commenter Affiliation: Utility Air Regulatory Group Document Control Number: EPA

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- 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 rel ated 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

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- 2880.1, Comment Excerpt Number 35.

Commenter Name: Lee B. Zeugin Commenter Affiliation: Utility Air Regulatory Group Document Control Number: EPA

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- 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, E PA 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 showing185 that compliance is achievable with 24 hours of data, including startup and s hutdown 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 wo uld 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 pe riod 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 c ontinuous 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

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- 190 7.1 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. Gener ally, if a CEMS is used, a 30

- day rolling average applies. Opacity uses a 24

- hour block average, while other operating parameters gen e rally use a 12

- hour block
average. We based the operating parameter 12

- hour block average on the estimated maximum sampl ing 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 D ocument Control Number: EPA

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- 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 the186 operation of any boiler, industrial or utility, and because u nplanned 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 C O 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

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- 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

- yea r 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 Wast e 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 Sub part 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 preser ve 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 parame ter 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 variabi lity, 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 th e 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 li mits 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

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- 1907.1, Comment Excerpt Number 19.

Commenter Name: Timothy Hunt Commenter Affiliation: American Forest and Paper Association (AF&PA) Document Control Number: EPA

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- 3213.1 Comment Excerpt Number: 291

Comment: If PM CEMS remain a rule requirement for larger boilers, the averaging period should be increas ed 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

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- 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 CE MS 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 b urdensome, 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

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- 1907.1, C omment Excerpt Number 19.

Commenter Name: David A. Buff Commenter Affiliation: Golder Associates Inc Document Control Number: EPA

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- 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 opera tes 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

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- 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 PM189 emissions, since few PM CEMS are employed at this time. Ultim ately, 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: America n Petroleum Institute (API) and National Petrochemical and Refiners Association (NPRA) Document Control Number: EPA

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- 2960.1 Comment Excerpt Number: 76

Comment: Furthermore, taking individual burners out

- ofservice for inspection generally w ill 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 com pliance averages.

Response: EPA disagrees. The final rule uses a CO compliance test at representative operating conditions, combined with an O 2 CEMS (on a 30

- day rolling average basis) to ensure good air pollution control practices to minimize CO emiss ions.

Commenter Name: Matthew Todd and David Friedman Commenter Affiliation: American Petroleum Institute (API) and National Petrochemical and Refiners Association (NPRA) Document Control Number: EPA

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- 2960.1 Comment Excerpt Number: 95

C omment: 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 sho rt 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

- o f

- 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 ch ronic 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 bec ause 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.

Com menter Name: Matthew Todd and David Friedman Commenter Affiliation: American Petroleum Institute (API) and National Petrochemical and Refiners Association (NPRA) Document Control Number: EPA

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- 2960.1 Comment Excerpt Number: 97

Comment: clar ification 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 out

ofservice 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 fr equent, 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 i n 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 calcul ating 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

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- 2960.1 Comment Excerpt Number: 98191 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 conti nuously. 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 sugge sted 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 Na me: Robert D. Bessette Commenter Affiliation: Council of Industrial Boiler Owners (CIBO) Document Control Number: EPA

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- 2702.1 Comment Excerpt Number: 123

Comment: 2. PM CEMS compliance basis.

Conflicting averaging times in the Proposed R ule 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 63.7 525(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

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- 2632.1 Comment Excerpt Number: 21192 Comment: Table 2 Should Specify the Same Averaging T ime 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, th e 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 arithm etic 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

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- 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 accou nt 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

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- 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 fu el 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
opera ted as efficiently as possible. Therefore, over the course of the day the operation of the193 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 operat es 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

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- 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 o n 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 f or a calendar month averaging period in this rule.

Commenter Name: Steven G. Hanson Commenter Affiliation: Graphic Packaging International Document Control Number: EPA

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- 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

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- 2723.1 Comment Excerpt Number: 30194 Comment: Should EPA move forward with the PM CEM mandate, EPA has conflicting information regarding the intende d 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 b lock 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 infreq uent (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 co uld 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

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- 2883.1 Comment Excerpt Number: 37

Comment: The Boiler MACT limits should be set considering intra

- unit variability and with averaging periods that will e nsure 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 burne d 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 st artups, 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 acknowled ged 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 c annot 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 nee ded 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. Longe r 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 comb ust 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 participa nts. 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

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- 1907.1, Comment Excerpt Number 19.

Comment er Name: David M. Kiser Commenter Affiliation: International Paper Company Document Control Number: EPA

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- 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
sect ion 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 Gr iffin Commenter Affiliation: American Chemistry Council Document Control Number: EPA

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- 2792.1 Comment Excerpt Number: 160196 Comment: EPA SHOULD CONSIDER LONGER AVERAGING PERIODS. The 2004 Boiler rule included emission limits for PM/metals, me rcury, 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 f rom 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 s tack 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 W aste 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 avera ging 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 limit s 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

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- 1907.1, Comment Excerpt Number 19. See the preamble for the approach to SSM periods in th e final rule.197 Commenter Name: Jim Griffin Commenter Affiliation: American Chemistry Council Document Control Number: EPA

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- 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 o ver 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 appli es 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

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- 1907.1 Comment Excerpt Number: 4

Comment: Co mpliance 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,
respec tively. 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 abo ve 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 optio n 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. Non

detect 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 Affilia tion: Consolidated Edison Company of New York Document Control Number: EPA

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- 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 fo r 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. SW

846

- 9250 is typically used for water and wastewa ter 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 a re 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 th e 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 meth ods 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 a pproval, 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: Mi chael L. Steele Commenter Affiliation: CraftMaster Manufacturing, Inc Document Control Number: EPA

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- 1907.1 Comment Excerpt Number: 2019 9 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 u nder 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 sit e specific fuel

- based Hg limit.

Response: See response to EPA

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- 1907.1, Comment Excerpt Number 4.

Commenter Name: Jim Griffin Commenter Affiliation: American Chemistry Council Document Control Number: EPA

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- 2792.1 Comme nt 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 hel pful 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 t he 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 a ppear.

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 th e 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

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- 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

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- 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.

Res ponse: See response to EPA

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- 2792.1 Comment Excerpt Number 184.

Commenter Name: Kerry Flick Commenter Affiliation: Metso Power Document Control Number: EPA

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- 2388.1 Comment Excerpt Number: 11

Comment: The EPA

- proposed Indu strial 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 consider ation, 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 En ergy & 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 of201 0.001 to 0.004 ppmw, while the bark ranged from 0.001 to 0.037 pp mw 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 low er 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

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- 1907.1, Comment Excerpt Number 4.

Commenter Name: Peter Zalzal Commenter Affiliation: Environmental Defense Fund Document Control Number: EPA

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- 2869.1 Comment Excerpt Number: 4

Comment: As describe d 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

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- 2388.1, Comment Excerpt Number 11.

Commen ter Name: Sharene Shealey Commenter Affiliation: RRI Energy Document Control Number: EPA

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- 2759.1 Comment Excerpt Number: 6

Comment: EPA allows for demonstration of compliance with HCl and mercury emission limits through fuel analysis in th e 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 an d 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 (se ctions 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 rulema king and there are a wide variety of liquid fuel types202 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 Aff iliation: RRI Energy Document Control Number: EPA

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- 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 t he 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 t o 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 c ompliance 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 affect ed 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

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- 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

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- 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 uni ts 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.

Comment er Name: Britt S. Fleming Commenter Affiliation: Auto Group Document Control Number: EPA

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- 2775.1 Comment Excerpt Number: 44

Comment: Proposed § 63.7521, which addresses fuel sampling but is completely focused on liquid and solid fuels. Giv en 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 exa mple, § 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 composit es 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 pr ocedures 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 gaseou s and liquid fuels from the composite sampling methods referenced in 63.7521(c) and (d). See response to comment DCN EPA

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- 2702.1 Excerpt 84 for fuel analysis methods for gaseous fuels. EPA may need to add further clarification on the applic ability 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

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- 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 propo sed 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 §6 3.7521 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 combusti on 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 th e 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 continuou sly 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 testi ng 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 purpose s, 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 § 63.751 0 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 Affiliatio n: American Forest and Paper Association (AF&PA) Document Control Number: EPA

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- 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

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- 3213.1 Comment Excerpt Number: 120

Comment: We would like EPA to confirm that for single fuel units, the exemption from f uel 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 determinin g 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 virtu ally no effect on the total amount of mercury and chlorine being input to the boiler206 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 tran sient flame stability
purposes.

Commenter Name: Timothy Hunt Commenter Affiliation: American Forest and Paper Association (AF&PA) Document Control Number: EPA

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- 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 col lection 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 sectio n 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

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- 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 helpf ul 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 Fe deral 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

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- 2792.1, Comment Excerpt Number 184.207 Commenter Name: Timothy Hunt Commenter Affiliation: American Forest and Paper Association (AF&PA) Document Control Number: EPA

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- 20 02

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- 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 hyd rogen chloride.

Response: See response for EPA

- HQ

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- 2792.1, Comment Excerpt Number 185.

Commenter Name: Timothy Hunt Commenter Affiliation: American Forest and Paper Association (AF&PA) Document Control Number: EPA

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- 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 wit h Subpart DDDDD.

Response: See response to EPA

- HQ

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- 2792.1 Comment Excerpt Number 184.

Commenter Name: Mike D. Craig Commenter Affiliation: New Energy Corp. Document Control Number: EPA

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- 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 a nd 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 c oal, so fuel analysis should be unnecessary.

Response: See response to EPA

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- 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

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- 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 f uels, 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 h ave 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 re duced 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

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- 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

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- 1907.1, Comment Excerpt Number 4.209 Commenter Name: Leonard W. Sandridge Commenter Affiliation: University of Virginia Document Control Number: EPA

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- 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 t his 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 sam pling 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: EPA

HQ

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- 3137.1, Excerpt 63. For liquid fuels, see response to DCN: EPA

- HQ

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- 1869.1 Excerpt 6.

Back

- up fuels are not necessarily exempted f rom 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

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- 2801.1 Comment Excerp t 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 mill s 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) provi des 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

canno t 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 to210 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

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- 2702.1 Comment Excer pt 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 bas is 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, l iquid, and solid fuels.

Response: For liquid fuels, see response to DCN: EPA

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- 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 (CI BO) Document Control Number: EPA

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- 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 cla rity, 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 maximu m 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: Coun cil of Industrial Boiler Owners (CIBO) Document Control Number: EPA

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- 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 tha t 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 sourc e requirements, see response to DCN: EPA

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- 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 Cont rol Number: EPA

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- 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

- fire d 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 langu age 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

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- 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.

R esponse: § 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 s ampling 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

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- 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)... 63.3 530(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 ad vance 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 ar e 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.

Resp onse: 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

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- 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.

Rec ommendations: Exempt gaseous and liquid fuels from the requirements of 63.7521(c) and (d).

Response: See response to comment DCN EPA

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- 2702.1 Excerpt 84 for composite sampling.

Commenter Name: John C. Hendricks Commenter Affiliation: A merican Electric Power Document Control Number: EPA

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- 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 t he best method for collecting such a sample.

Response: See the response to EPA

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- 2801.1, Comment Excerpt Number 55.

Commenter Name: Pamela F. Faggert Commenter Affiliation: Dominion Document Control Number: EPA

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- 2908.1 Comment Excerpt Number: 6214 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 analysi s 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: Deb ra J. Jezouit Commenter Affiliation: Class of '85 Regulatory Response Group Document Control Number: EPA

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- 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

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- 2759.1, Comment Excerpt Number 6.

Commenter Name: Douglas A. McWilliams Commenter Affiliation: American Municipal Power Document Control Number: EPA

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- 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 concent ration 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 sour ces, 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 mitigates5215 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 regul atory 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 e very source.

Commenter Name: Pamela F. Faggert Commenter Affiliation: Dominion Document Control Number: EPA

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- 2908.1 Comment Excerpt Number: 34

Comment: In the 2004 rule, EPA required repeat fuel analysis only when a new type of fuel i s 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 Chemica l Company Document Control Number: EPA

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- 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 pr oposed 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 preamb le 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 cont rolled 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 b asis.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 add ition, 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 N umber: EPA

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- 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 site

specific fu el 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 auth ority 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 define d 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 requir e 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 follo wing text:

You must maintain, and submit to the permitting authority for approval upon request, a site

specific fuel analysis plan that includes the information contained in paragraphs (b)(2)(i) through (vi) of this section. Only requests for an alternat ive 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 pla n 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 In ternational Inc Document Control Number: EPA

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- 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 compl iance 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

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- 3122 Comment Excerpt Number: 5

Comment: Fuel sampling. Fuel sampling requirements should be clarified. W hen 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 af fected 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

re quirements, 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

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- 2955.1 Comment Excerpt Number: 6

Comment: EPA has proposed the use of particulate matter (PM) for use as a surrogate for non

mercury metallic HAPs. These HAP constituents are fuel

- dependent, and are not affected by the combustion conditions in the boiler. As such, the E PA 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 fu el suppliers would greatly reduce the compliance costs for many companies without compromising public health or environmental protection.

Response: See response for EPA

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- 2759.1 Comment Excerpt Number 6

Commenter Name: Barry Christense n Commenter Affiliation: Occidental Chemical Corp Document Control Number: EPA

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- 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 a nd 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

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- 2702.1 Excerpt 84 for fuel analysis methods for gaseous fuels. EPA may need to add further clarification on the applicability of fuel analysis
req uirements in 63.7521 on certain gaseous fuels in a future reconsideration notice.

Commenter Name: Gary Melow Commenter Affiliation: Michigan Biomass Document Control Number: EPA

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- 2776.1219 Comment Excerpt Number: 16

Comment: A biomass fac ility 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 empl oy 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 c ontent of the fuel. We would propose using the detection level as the assumed level of mercury in the fuel.

Response: See response for EPA

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- 1907.1, Comment Excerpt Number 4

Commenter Name: Paul N. Cicio Commenter Affiliation: Industri al Energy Consumers of America Document Control Number: EPA

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- 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 exem pt 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 require ments 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 conducti ng 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 u ntil 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 temperat ure, minimum tube temperature, minimum flue gas temperature, minimum pulverizer temperature, elapsed time220 from light

- off, etc.), the start

- up fuel is shut down and the unit fires coal exclusively. Some pulverized coal units have additional equipment operat ing 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 t o 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 o r 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 o perates 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 d ays 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 perf ormance 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

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- 3137.1, Comment Excerpt Number 63.

Commente r Name: Richard Rosvold Commenter Affiliation: Xcel Energy Services, Inc Document Control Number: EPA

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- 2955.1 Comment Excerpt Number: 18

Comment: Monthly fuel sampling, as required in § 63.7515(t), is excessive for liquid fuels. These fuel s 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 b urning 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

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- 2801.1, Comment Excerpt Number 5 5.

Commenter Name: Gary Melow Commenter Affiliation: Michigan Biomass Document Control Number: EPA

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- 2776.1 Comment Excerpt Number: 18221 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, yo u 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 maxi mum 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 emi ssions and so these equations have not been adjusted.

Commenter Name: Bill Wemhoff Commenter Affiliation: National Rural Electric Cooperative Association Document Control Number: EPA

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- 2835.1 Comment Excerpt Number: 23

Comment: NRECA sup ports 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 approp riate for every source.

Commenter Name: Bill Wemhoff Commenter Affiliation: National Rural Electric Cooperative Association Document Control Number: EPA

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- 2835.1 Comment Excerpt Number: 29

Comment: Supports the option to use fuel analysi s 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 tha t have not changed fuel type, or the agency’s proposal regarding how that analysis is used.222 Response: See response to EPA

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- 2880.1, Comment Excerpt Number 30.

Commenter Name: Lee B. Zeugin Commenter Affiliation: Utility Air Regulatory Group Document Control Number: EPA

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- 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 § 6 3.7521 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 excee d 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 an alysis. 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 addres s 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. Similarl y, 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 add ress 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 pro vide 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

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- 2632.1, Comment Excerpt Number 46.223 Commenter Name: Lee B. Zeugin C ommenter Affiliation: Utility Air Regulatory Group Document Control Number: EPA

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- 2880.1 Comment Excerpt Number: 31

Comment: All fuel analysis under the rule must be conducted according to an approved site

specific plan and according to spe cific 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 p rescriptive. 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 combust ed 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 require d. 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 inclu des 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 o f 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 reexamin e 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

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- 2801.1, Comment Excerpt Number 55 for procedures used to collect and prepare the samples

. See the response to EPA

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- 2632.1, Comment Excerpt Number 48 for a clarification of the fuel analy sis plan submittals.

Commenter Name: Christopher S. Colman Commenter Affiliation: Hovensa LLC Document Control Number: EPA

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- 2863.1 Comment Excerpt Number: 46

Comment: If a facility’s fuel consistently tests below the limit, for 12 conse cutive 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

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- 2632.1 , Comment Excerpt Number 46

.

Commenter Name: Christopher S. Colman Commenter Affiliation: Hovensa LLC Document Control Number: EPA

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- 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 procedure s for collecting composite samples from tanks.

Response: See the response to EPA

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- 2801.1, Comment Excerpt Number 55.

Commenter Name: Lee B. Zeugin Commenter Affiliation: Utility Air Regulatory Group Document Control Number: EPA

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- 2880.1 Comment Excerpt Number: 72225 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 documen tation 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. Requi ring 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

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- 2880.1, Comment Excerpt Number 30.

Commenter Name: Jim Griffin Commenter Af filiation: American Chemistry Council Document Control Number: EPA

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- 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 opti on 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 fue led 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

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- 3213.1, Comment Excerpt Number 120.

Commenter Name: Jim Griffin Commenter Affiliation : American Chemistry Council Document Control Number: EPA

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- 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 fac ility 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

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- 2801.1, Comment Excerpt Number 55.

Commenter Name: Jim Griffin Commenter Affiliation: American Chemistry Council Document Control Number: EPA

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- 2792.1 Comment Excerpt Number: 183

Co mment: 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 anal ysis. 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 definiti on for an "equivalent pollutant determinative or analytical procedure" (section (6) under the definition) to explicitly include HCl.

Response: NEED RESPONSE See response for EPA

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- 3213.1, Comment Excerpt Number 122.

Commenter Name: Jim Eubank Commenter Affiliation: Kentucky Division of Air Quality Document Control Number: EPA

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- 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 i s 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 so urces 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 dele gated authority 60 days before the initial compliance demonstration.227 

### Detection Levels

Commenter Name: Dwayne Arino Commenter Affiliation: Jeld

- Wen, Inc Document Control Number: EPA

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- 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 approv ed 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 th at 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 emissi on 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

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- 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 Sec tion 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: Consum ers Energy Company Document Control Number: EPA

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- 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 N umber: EPA

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- 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 indust rial 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 M ACT 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 de fines 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 report ed. 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 dete ctable 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 detecti on 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, reliab ility, 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 sta ted: 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 necessar y, 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

se t 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 m ethod 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 mult iple 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 rep orted 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 l imit 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 lev el were less than the calculated floor or emissions limit230 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 e qual 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 t hree 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 Com menter Affiliation: Hampton Lumber Mills, Inc Document Control Number: EPA

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- 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 level s 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 t he 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 install ing 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 impreci sion 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 c apabilities 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 representa tive 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 s ensitive, 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 emission s limit. If three times the231 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 l imit 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 measurem ent 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

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- 2722.1 Comment Excerpt Number: 8

Comment: B&W is concerned that contin uous 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 complianc e demonstration methods.

Commenter Name: Nilaksh Kothari Commenter Affiliation: Manitowoc Public Utilities Document Control Number: EPA

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- 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

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- 2 817.1 Comment Excerpt Number: 9232 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 sourc e 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 stan dard 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 lim it 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 av erage 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 o f 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 ste p 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 emissi ons 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 de tection 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 l evel 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 conce ntration 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

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- 2970.1 Comment Excerpt Number: 11

Comment: It is extremely important to understand the quantification limit and apply it properly. The agency indicates this conc ept 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 quantification233 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 procedure s 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 li mit 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 a verage 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 st ep 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 emiss ions 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 d etection 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 U SA, Inc Document Control Number: EPA

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- 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 detectio n limit and instrument234 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. T hese 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
tes t 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% confi dence 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 spe cified 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 uncerta inty 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 me asure 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 r uler. 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 i nches. 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). Th e proposed Gas

- 2 emission limits are less than the A

- LOQ except for filterable235 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 ba sed 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 rat e 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 ins tall 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 A

LOQ. 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

v alues 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 represent s 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 t he 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 develo p 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 deter mining 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 represent ative 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 t he 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 substi tuted 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.

Comm enter Name: Douglas A. McWilliams Commenter Affiliation: ArcelorMittal USA, Inc Document Control Number: EPA

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- 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., Metho d 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 we re generated. The limit of quantitation based on field blank results (FB

LOQ) 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 matt er. 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 th at 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 proportional ly 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

reas onably 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 tr ue when the database237 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 databas e 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) c alculated 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 sam ple 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 dete ction 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 varia bility 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 calcula ted 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

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- 2875.1 Comment Excerpt Number: 1 2

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 test ing procedures.

Response: See the preamble for revisions to the CO limitations and compliance demonstration methods.

Commenter Name: Douglas A. McWilliams238 Commenter Affiliation: ArcelorMittal USA, Inc Document Control Number: EPA

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- 2 811.1 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 concen tration 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 perio d. 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 regu latory 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: Gordo n M. Smith Commenter Affiliation: Mitsubishi Polyester Film, Inc Document Control Number: EPA

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- 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. C alibrations 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 determ ine 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 inc ludes CO 2 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 lim its, 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

measureme nt. 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

meas ure 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% confiden ce 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 Fran cisco, 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 CO 2 than boilers and process heaters. Since CO 2 is a known interferent when using infrared a bsorption 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 limit ations and compliance demonstration methods.

Commenter Name: Gordon M. Smith Commenter Affiliation: Mitsubishi Polyester Film, Inc Document Control Number: EPA

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- 2912 Comment Excerpt Number: 17

Comment: These considerations clearly sug gest 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 by240 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 Di vision of Air Quality Document Control Number: EPA

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- 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 d ata 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 th e 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 r eport 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 Affiliatio n: Ameren Services Document Control Number: EPA

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- 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 stand ard 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 at241 s ources 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 conf idence 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 ass ured 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

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- 0789). In essence, US EPA has data i n 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 t o 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 d etection 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 m easurement 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 m ethod 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 st ep 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

- specif ic 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 in sufficiently 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 floo r 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 adequately242 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 fo r 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 addre ssed in the floor or the emissions limit.

Commenter Name: Jim Griffin Commenter Affiliation: American Chemistry Council Document Control Number: EPA

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- 2792.1 Comment Excerpt Number: 187

Comment: EPA Should Address Detection Limit and N on

- 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 analyti cal 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 nece ssary 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

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- 2792.1 Comment Excerpt Number: 188

Comment: EPA has f ailed 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 lim its 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 stat ed: "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 t he 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 develo ping 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 I I 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 d etection 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 m ethod 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 da tabase 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 include s 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 lev el 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 an d 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 ade quately 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 e missions limit does not account244 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

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- 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 M ethod 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 reiterate s 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 N umber: EPA

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- 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 Co rrected 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 result ing 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 detectio n 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

us ing 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 above245 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 de tection 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 P ower Document Control Number: EPA

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- 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 g iven 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 ba sis. 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 US

EPA established EERC as the Center of Excellence for Air Toxic Metals (CATM). Their input provi des 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 les s 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 metho d, 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

re sults 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 measureme nts 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 limi t 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 enou gh 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 u sed. 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 200 0/76/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, HC l, 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 analyze d]

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 val ues]

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 assoc iated 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 ppmv247 should be considered. At a mi nimum, 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 meth ods 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), compa red 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 e rrors 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 hig h

- 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 p resent 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 Meth ods 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 gase s 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 ammonia248 is over 10 ppm, the potent ial 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 addres s 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 1 0 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 H CI 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 beco me 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 (O H) 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 t hese 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 detecti on 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 me rcury 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 to249 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.

Co ntinuous 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 br eakthrough 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 ne ed 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 hav e 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 aro und 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 fur ans, 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 issu e 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 val ue (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 thei r 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 fr om 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 o f 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. Theref ore, 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 t o 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 mus t 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 tre ated 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 age ncy 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 calcu lating 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 signi ficantly 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 e ffect 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 l evel (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 to251 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 calcula ted 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 wer e 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

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- 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 da ta 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 sa mple 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 sub

samples 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. F or 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 incon sistencies 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 should252 reex amine 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 commente rs 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

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- 1907.1, Comment Excerpt Number:8.

Commenter Name: T imothy Hunt Commenter Affiliation: American Forest and Paper Association (AF&PA) Document Control Number: EPA

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- 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 tha t 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 detecti on 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 deter mination. 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 me asured below the test

- specific minimum detectable limit.

Commenter Name: Arthur N. Marin Commenter Affiliation: NESCAUM Document Control Number: EPA

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- 2893.1 Comment Excerpt Number: 3253 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 rev isions to the CO limitations and compliance demonstration methods.

Commenter Name: Michael Bradley Commenter Affiliation: The Clean Energy Group Document Control Number: EPA

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- 2466.1 Comment Excerpt Number: 4

Comment: To assess the fea sibility of meeting the CO standards for existing liquid

- and gas

fired 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 specifica tions 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 Protoco l 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 u sing 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 com pliance demonstration methods.

Commenter Name: Arthur N. Marin Commenter Affiliation: NESCAUM Document Control Number: EPA

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- 2002

- 0058

- 2893.1 Comment Excerpt Number: 8254 Comment: As with CO emission limits, the proposed mercury and hydrogen chlori de 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 Commente r Affiliation: Auto Group Document Control Number: EPA

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- 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 l imit 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 cali bration 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 mu st 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

- r ange 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 11 5 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

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- 2002

- 0058

- 3213.1255 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.

Regardi ng 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 t est

- specific minimum detectable limit.

Commenter Name: Timothy Hunt Commenter Affiliation: American Forest and Paper Association (AF&PA) Document Control Number: EPA

- HQ

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- 2002

- 0058

- 3213.1 Comment Excerpt Number: 104

Comment: The proposed dioxin/fura n 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 sho uld 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 als o 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 da ta 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 emissi on 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 impac t 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 eac h 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 dete ction 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 detectio n 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 p roposed 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

ou t 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 quant itation 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
p ercentile 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 assure257 compliance, should EPA even set numeric al 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 a gree 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 propo rtionally 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 a nd 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 l evel) 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 meth od 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 measuremen t 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 adjuste d 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 th e 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

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- 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 conc entration 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 As sociation (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 appropri ate 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

corr ection 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 wr ite 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 limi t; 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 determinatio n.

Commenter Name: Ashok K. Jain Commenter Affiliation: National Council for Air and Stream Improvement259 Document Control Number: EPA

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- 0058

- 2804.1 Comment Excerpt Number: 8

Comment: In its proposal and in its 2009 ICR, EPA has specified the u se 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 bet ween 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 s pecified. 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 sub

samples 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 b etween 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 requireme nt 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

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- 0058

- 1907.1, Comment Excerpt Number:8.

Commenter Name: Randall D. Qu intrell Commenter Affiliation: Georgia Paper and Forest Products Association, GPFPA Document Control Number: EPA

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- OAR

- 2002

- 0058

- 2905 Comment Excerpt Number: 6260 Comment: Many of the limits have been set at or below the practical quantitation limit (PQL) o f 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: Probabil ity 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 le ss 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 minimize s 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 f loor 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 representa tive 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 meth od 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: Uni versity of Virginia Document Control Number: EPA

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- 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 is261 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 p reamble 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

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- 2905 Comm ent 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 o f 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 t he 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: Addres s ed in response to EPA

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- 2905, Comment Excerpt Number: 6.

Commenter Name: Randall D. Quintrell Commenter Affiliation: Georgia Paper and Forest Products Association, GPFPA Document Control Number: EPA

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- 2 905 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 industri al 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 congeners262 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 pro cedure (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 resul ts are handled consistently and reported properly, and (ii) to ensure that no source with emissions below PQL levels can be considered non

compliant. Until that occurs, the dioxin/furan test method is unacceptable as a compliance measure and this testing r equirement 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 report ing 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/fur ans 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 detect able limit.

Commenter Name: Ashok K. Jain Commenter Affiliation: National Council for Air and Stream Improvement Document Control Number: EPA

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- 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 quantitati on 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 c ollected, 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

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- 2801.1 Comment Excerpt Number: 60

Comment: How to treat non

- detec ts when doing compliance test. Suggest if all 3 runs are non

detect, treat result as zero.

Response: Regarding EPA’s guidance on reporting of non

- detect values for compliance purposes, sources should use the guidance in cluded in each promulgated test me thod. 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 concent ration 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 (calcul ated 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 A ssociation (NPRA) Document Control Number: EPA

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- 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 reproducibili ty 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.

Commente r Name: Matthew Todd and David Friedman Commenter Affiliation: American Petroleum Institute (API) and National Petrochemical and Refiners Association (NPRA) Document Control Number: EPA

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- 2960.1 Comment Excerpt Number: 258264 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: No rth Carolina Chamber Document Control Number: EPA

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- 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 emissio ns 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 est ablishing 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 w as 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 t o 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 t han 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 thre e 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
t he representative method detection level to apply as the adjusted floor or emissions limit. This265 adjusted value would ensure measurement variability is adequately addressed in the floor or the emissions limit.

Commenter Name: Glenn C. England Commente r Affiliation: Environ Document Control Number: EPA

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- 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 n ot 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 f or 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 imp recision 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 l imit 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 detectio n 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

a ssociated 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 outl ier 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 probabi lity 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 detect ion 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 re presentative 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 conclud e 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 c onclude 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 li mit. 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

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- 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 pro blematic. 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 de tection 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: E PA

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- 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 a267 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 usi ng 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. Meas urement 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 meth od 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 im precision 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 me thod 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 t imes 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 wo uld 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 e missions 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 Association268 Document Control Number: EPA

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- 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 em issions 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 metho d 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 valu e. 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 dat a 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 sm all, 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 compa re 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 emission s 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 measure ment 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 in cluded in each promulgated test method.

Commenter Name: Pamela F. Faggert Commenter Affiliation: Dominion Document Control Number: EPA

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- 2908.1 Comment Excerpt Number: 29269 Comment: The proposed rule has several new and existing boiler types with CO limits proposed at 1 ppm and one new boiler typ e 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 requirement s, 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

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- 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 com ments 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 m easured 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

em ission 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 chal lenges 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 usin g 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 calibratio n 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

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- 2792.1 Comment Excerpt Number: 36

Comment: EPA has specified that ASTM Method D6784

- 02 (2008) may be used as an alternative to M ethod 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 o f 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 Met hod 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 Met hod 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 co nduct simultaneous emissions tests using both methods on sources to determine whether or not the two271 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 specifica tions are consistent between test methods and with the method capabilities. See the response to EPA

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- 1907.1, Comment Excerpt Number:8.



### Measurement Methodology Impractical

Commenter Name: G. Vinson Hellwig Commenter Affiliation: Michiga n Department of Natural Resources and Environment Document Control Number: EPA

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- 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 addit ion 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 su itable 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 n ot smaller.

Commenter Name: Robert G. Hedden272 Commenter Affiliation: Oilheat Manufacturers Association Document Control Number: EPA

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- 3188 Comment Excerpt Number: 7

Comment: It is our understanding that the proposed test procedure require s 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 decrea sed 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 di ameter 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

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- 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 supp ort 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 po pulation. 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 ca nnot 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 fo r the study was from boilers smaller than 10 MMBtu/hr. [EPA

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- 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 a nalyses” 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

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- 2960.1 Comment Excerpt Number: 138

Comment: Another measurement issue revolves around measuring and thus controlli ng 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 hav e 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 obj ective 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

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- 1598.1 Comment Excerpt Number: 5274 Comment: PCAPCD does not support the requi rement 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 resul ts 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

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- 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 Comment er Affiliation: The Vinyl Institute Document Control Number: EPA

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- 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 tes ting 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 continuou s 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 manufac ture) 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 eliminat ed 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

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- 2882.1 Comment Ex cerpt 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 diffi cult, 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

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- 2882.1 Comment Excerpt Number: 11

Comment: With ove r 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’srequirem ent 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 quest ionable 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 ru le, 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: Mor ton Salt Document Control Number: EPA

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- 2883.1 Comment Excerpt Number: 13276 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

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- 2882.1, Comment Excerpt Number 9.

Commenter Name: Richard Rosvold Commenter Affiliation: Xcel Energy Services, Inc Document Control Number: EPA

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- 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 testin g 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

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- 2527.1 Comment Excerpt Number: 1

Comment: We are concerned that allowing redu ced 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 alway s 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. B ased 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

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- 2527.1 Comment Excerpt Number: 2277 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 al ways 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 ensur e 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 Aff iliation: Eastman Chemical Company Document Control Number: EPA

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- 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 rest rictive 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 pe rformance 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 non

emissions 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 c omponent 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

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- 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 continue278 for those HAPs not meeting the relief criterion. EPA does not apply reduced testing to di oxin/furan or to compliance test under the emissions averaging provisions. There is no valid reason for this limitation.

Response: See the response to EPA

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- 2882.1, Comment Excerpt Number 9. Also, annual testing for dioxin/furan is not r equired under the final rule. For emissions averaging, see the response to EPA

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- 3137.1, Comment Excerpt Number 8.

Commenter Name: Arthur N. Marin Commenter Affiliation: NESCAUM Document Control Number: EPA

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- 2893.1 Com ment 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

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- 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, ver y few units are likely to qualify for this provision, so we are not sure of its value.

Response: See the response to EPA

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- 2882.1, Comment Excerpt Number 9.

Commenter Name: Britt S. Fleming Commenter Affiliation: Auto Group Document Co ntrol Number: EPA

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- 2775.1 Comment Excerpt Number: 60279 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 frequen t 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 perf ormance 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

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- 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

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- 2775.1 Comment Exce rpt 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 e missions 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 emiss ions 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 Fore st and Paper Association (AF&PA) Document Control Number: EPA

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- 3213.1 Comment Excerpt Number: 281280 Comment: The reduced testing frequency is not proposed for dioxin/furan or for facilities using emissions averaging, and emissions of the oth er 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 ru le 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 an nual 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 abov e the limits.

Response: See the response to EPA

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- 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

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- 3137.1, Co mment Excerpt Number 8.

Commenter Name: Randall D. Quintrell Commenter Affiliation: Georgia Paper and Forest Products Association, GPFPA Document Control Number: EPA

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- 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 th ose 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 sligh tly 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 perf ormers.

Response: See the response to EPA

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- 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 D ocument Control Number: EPA

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- 2764.1 Comment Excerpt Number: 21281 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 dist inctly 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 shoul d 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

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- 2882.1, Comment Excerpt Number 9. Also, annual testing for dioxin/furan is no t 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

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- 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

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- 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 §63.7 555(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 te sting 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 c hanging 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 thresho ld 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 perf ormance 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 t hat 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. Thi s 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 change s 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 ap ply 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 9 0 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 op erations 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 ru le 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

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- 2763.1 Comment Excerpt Number: 25

Comment: EPA should allo w 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 contr ol 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 Haza rdous 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 s ize). 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 di oxin/furan emissions is not required under the final rule.

Commenter Name: Leonard W. Sandridge Commenter Affiliation: University of Virginia Document Control Number: EPA

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- 2769.1 Comment Excerpt Number: 25

Comment: 40 CFR 63.7522(a) all ows 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 emiss ion 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

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- 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 ap ply 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

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- 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 i n 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

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- 2740.2 Comment Excerpt Number: 35

Comment: 63.7555. Wha t 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 app licable 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 emissio n 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: Golde r Associates Inc Document Control Number: EPA

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- 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 provis ion 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 polluta nt.

Commenter Name: Robert D. Bessette Commenter Affiliation: Council of Industrial Boiler Owners (CIBO) Document Control Number: EPA

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- 2702.1 Comment Excerpt Number: 133

Comment: We recognize EPA has included a provision to skip to a th ree 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 Respon se: 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 st andard 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

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- 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.

Reco mmendation: 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 te st be conducted within 37 months after the prior test.

Commenter Name: Patrick Strauch Commenter Affiliation: Maine Forest Products Council Document Control Number: EPA

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- 3120.1 Comment Excerpt Number: 6

Comment: Another suggestion we ha ve 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 o nce 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 appr opriate.

Commenter Name: J. Michael Geers287 Commenter Affiliation: Duke Energy Document Control Number: EPA

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- 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 be lieves 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 d ioxin/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 recommend s 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 t hat 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 me et 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

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- 2886.1 Co mment 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 provi sion 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 pollut ant. 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

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- 2632.1 Comment Excerpt Number: 41288 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 o f 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% bel ow 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 establi sh 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 test ing of dioxin/furan emissions.

Commenter Name: William O'Sullivan Commenter Affiliation: New Jersey Department of Environmental Protection Document Control Number: EPA

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- 2969.1 Comment Excerpt Number: 6

Comment: We recommend that stack t esting 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 com pliance 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 l imit 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

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- 2848.1 Comment Excerpt Number: 10289 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 Comme nter Affiliation: Morton Salt Document Control Number: EPA

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- 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 t he 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 aggress ive 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 perform ance 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

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- 2848.1, Comment Excerpt Number: 10.

Commenter Name: Lee B. Zeugin Commenter Affiliation: Utility Air Regulatory Group Document Control Number: EPA

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- 2880.1 Comment Excerpt Number: 22

Comment: UARG agrees performance testing should not be required any more f requently 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 extremely290 low levels of EPA’s proposed limits. UARG requests th at 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 wh ich 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 suf ficient 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

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- 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 operat ing 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 respect s. 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 addres s 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 Industr ial, Commercial, Institutional Boilers and Process Heaters National Emission Standards for Hazardous Air Pollutants

-- Major Source” (Apr. 2010), EPA

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- 0803, Appendix J

- 1. In the EGU ICR, EPA assumed a cost of $42,000, Supporting291 Statement f or Review of EPA ICR No. 2362.01 (Dec. 24, 2009), EPA

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- 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 alr eady 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 non

detects.

Response: Annual testing for dioxin/furan emissions is not required under the final rule.

Commenter Name: Bill Wemhoff Commenter Affiliation: National Rural Electric Coo perative Association Document Control Number: EPA

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- 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

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- 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

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- 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 co nditions 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 fuel292 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 p ractices 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 Numb er: EPA

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- 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) requ ires 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 emis sions 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 frequenc y. 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 i nitial 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 b e 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. Th erefore, 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 emissio ns 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 g ood 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 Lig ht and Power Document Control Number: EPA

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- 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 sho wed 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 pr ovides 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, a nd 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 capita l 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 environm ent 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

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- 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/fu el) at facility294 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 representativ e 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

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- 2702.1 Comm ent 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: Sour ces 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

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- 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 incl ude 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 complian ce 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 Administrat ion Document Control Number: EPA

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- 2916.1 Comment Excerpt Number: 4295 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 re duce 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

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- 3120.1 Comment Excerpt Number: 7

Comment: Create a best management practices procedure for these smaller facilities that will achieve an environmentally fr iendly standard, while not imposing the significant costs associated with the rule as it is currently proposed.

Response: See response to EPA

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- 2916.1, Comment Excerpt Number 4.

Commenter Name: J. Michael Geers Commenter Affiliation: Duke Energy Document Control Number: EPA

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- 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 DDDD D will be enormous. They are certainly “significant” within the meaning of the296 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

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- 2702.1, Comment Except Number 152.



### Operating Parameter Monitoring

Commenter Name: Michael L. Steele Commenter Affiliation: CraftMaster Manufacturing, Inc Document Control Number: EPA

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- 1907.1 Comment Excerpt Number: 10

Comment: Establi shing 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 b e 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 t he 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 Con trol Number: EPA

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- 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 calibratio n 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 calibratio n 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 limit s, 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 s ource will follow, and calls generall y for a daily performance evaluation of some form for most monitoring devices as a basic QC check . For example, t he method for checking for pre s sure obstructions is not prescribed in the rule. This is a basic quality c ontrol 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 continu ed 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 reg ulators 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 facili ty. EPA also298 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 sophisti cated 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 Co mmenter Affiliation: Illinois Manufacturers' Association Document Control Number: EPA

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- 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 t est 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

ma ximum 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 limi ts 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 operati ng 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 proc edure 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 devi ce 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 s ite

- 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 are299 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

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- 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 limit ations 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 Pl ants, 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 de monstrating 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 me rcury 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 app ropriate for assuring ongoing compliance. Using the alternative monitoring procedures of the general provisions, t he rule allows a source owner or operator to install and operate CEMS in lieu of some testing and parametric monitoring requirements. This p rocess 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

mon itoring systems.

Commenter Name: Robin Mills Ridgway Commenter Affiliation: Purdue University Document Control Number: EPA

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- 2782.1 Comment Excerpt Number: 8300 Comment: Inflexibility in operating limits will cause equipment operation p roblems 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

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- 2729.1 Comment Excerpt Number: 16

Comment: Operating limits

- Sorbent injection rate Establishing a set

- point minimum injection rate based on stack testing at 1 00

- 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 sele cted, 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 rate s 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 Company301 Document C ontrol Number: EPA

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- 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 equi pped 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 es timated 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 comment s, 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 monito ring approach pursuant to the Part 63 general provisions and establishment of an appropriate operating limit for the alternative parameter. Assuming an effective demonstration, t he situation described by the commenter may be an appropriate example of app lying that authority.

Commenter Name: Stephen R. Gossett Commenter Affiliation: Eastman Chemical Company Document Control Number: EPA

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- 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 flow

rate 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 performa nce 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 l oad 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 no302 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 t o 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 w ere 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 du e 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 rec ognize 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 thi s 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 submitte d 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

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- 2635.1, Comment Excerpt Number 5.

Comm enter Name: Stephen R. Gossett Commenter Affiliation: Eastman Chemical Company Document Control Number: EPA

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- 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 oper ating 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 occu rs 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. Furthermor e, 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

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- 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 arbitr ary 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 s tandards 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. O ther U.S. government agencies such as NASA also do not304 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 requi red 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 tha t 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 rel atively 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 c orrect 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 flex ible 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 mont hs (for example). If a system is consistently passing a six

month QA/QC check, that check may be pushed to annual.

Response: See the response to EPA

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- 1907.1, Comment Excerpt Number 37.

Commenter Name: Timothy Hunt Commenter Affiliat ion: American Forest and Paper Association (AF&PA) Document Control Number: EPA

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- 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 flo w 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 ens ure accuracy. For example, many facilities have flow305 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. Rosem ount recommends that these instruments be calibrated at least once every 5 years.

Response: See the response to EPA

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- 1907.1, Comment Excerpt Number 37.

Commenter Name: Timothy Hunt Commenter Affiliation: American Forest and Paper As sociation (AF&PA) Document Control Number: EPA

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- 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 ext remely 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) CPM S 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

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- 1907.1, Comment Excerpt Number 37.

Commenter Name: Timothy Hunt Commenter Affiliation: American Forest and Paper Association (AF&PA) Document Control Number: EPA

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- 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

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- 1907.1, Comment Excerpt Number 37.306 Commenter Name: Timothy Hunt Commenter Affiliation: American Forest and Paper Association (AF&PA) Document Control Number: EPA

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- 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 i f 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 f it 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

- spe cific 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

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- 1907.1, Comme nt Excerpt Number 37.

Commenter Name: Timothy Hunt Commenter Affiliation: American Forest and Paper Association (AF&PA) Document Control Number: EPA

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- 3213.1 Comment Excerpt Number: 299

Comment: Facilities need more flexibility in deve lopment 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 usin g 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 credib le 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 be cause such limits necessarily would require over

compliance with standards when affected sources operate under less rigorous conditions than those used for compliance testing.307 Response: See the response to EPA

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- 2635.1,Comment Excerpt Nu mber 5.

Commenter Name: Timothy Hunt Commenter Affiliation: American Forest and Paper Association (AF&PA) Document Control Number: EPA

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- 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. Othe r 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 t he 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 perfo rmance 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 l evels 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

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- 3213.1 Comment Excerpt Num ber: 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 use d 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

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- 3137.1, Comment Excerpt Number 59.

Com menter Name: Robert D. Bessette Commenter Affiliation: Council of Industrial Boiler Owners (CIBO) Document Control Number: EPA

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- 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 wi th 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 C ontrol Number: EPA

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- 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

con sistent 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.

Res ponse: N o thing 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 pa rameter data into longer block
averages.309 Commenter Name: Walter Tyler Commenter Affiliation: Invista Document Control Number: EPA

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- 2761.1 Comment Excerpt Number: 12

Comment: Boilers regulated under the Boiler MACT will be operated at ma ny 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 d uring 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 e nsure 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 curv e) 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 injectan t 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 op erating loads.

Commenter Name: Leonard W. Sandridge Commenter Affiliation: University of Virginia Document Control Number: EPA

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- 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 conduct ed 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 r anging 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

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- 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 al lowable substitute for a 12

- hour rolling average sorbent injection rate limit?

Response: See the response to EPA

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- 3137.1, Comment Excerpt Number 59.

Commenter Name: Leonard W. Sandridge Commenter Affiliation: University of Virginia D ocument Control Number: EPA

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- 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

- h our 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

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- 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 fr equency of calibration based on the historical experience with similar installations and instruments without EPA prescribing a one

size

- fits

- all frequency. A set frequency for all instruments regardless of the sophistication of the instrument and regardles s 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

- diagnostic s 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 sit e

- 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

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- 1907.1, Comment Excerpt Number 37.

Commenter Name: Melvin E. Keener Commenter Affiliation: Coalition for Responsible Waste Incineration (CRWI) Document Control Number: EPA

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- 2824.1 Comment Excerpt Number: 21

Comment: EPA should modify the language in 63.7540(a)(1) so that the facilities ha ve 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 re

established during performance tests. To avoi d obvious, ratcheting down of operating parameter312 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 a vailable. Until that time, the existing limit would remain in effect. On the concern about ratcheting down operating limits, see the response to EPA

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- 3213.1, Comment Excerpt Number 301.

Commenter Name: Chris Greissing Commenter Affili ation: Industrial Minerals Association Document Control Number: EPA

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- 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 averag e 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 alt ernative 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 un its. 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 D ocument Control Number: EPA

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- 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

- poin t calibration every 8 hours. Perhaps such unreliability in monitoring was typical 50 years313 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 s hould 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

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- 190 7.1, Comment Excerpt Number 37.

Commenter Name: Melvin E. Keener Commenter Affiliation: Coalition for Responsible Waste Incineration (CRWI) Document Control Number: EPA

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- 2824.1 Comment Excerpt Number: 27

Comment: EPA should resolve th e 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 avera ge. 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 i n 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.

Com menter Name: Chris Greissing Commenter Affiliation: Industrial Minerals Association Document Control Number: EPA

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- 2740.2314 Comment Excerpt Number: 27

Comment: OPERATING LIMITS. The Proposed Rule would require that sources establish and monit or 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 in itial 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 r equired 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 co nducted 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 wastef ully 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 boi ler 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

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- 2635.1,Comment Excerpt Number 5.

Commenter Name: Chris Greissing Commenter Affiliation: Industrial Minerals Association Document Control Number: EPA

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- 2740.2 Comment Excerpt Number: 33

Comment: 63.7540. H ow 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 oper ating 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 the315 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 operat ing 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 ran ge of the unit.

Response: See the response to EPA

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- 2635.1,Comment Excerpt Number 5.

Commenter Name: David A. Buff Commenter Affiliation: Golder Associates Inc Document Control Number: EPA

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- 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
p rovide for this exclusion.

Commenter Name: Robert D. Bessette Commenter Affiliation: Council of Industrial Boiler Owners (CIBO) Document Control Number: EPA

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- 2702.1 Comment Excerpt Number: 108

Comment: Operating Limits A. Operating Li mits 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 goi ng 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 and316 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) duri ng 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. EP A 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 estab lish 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 base loaded, 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 t ime 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 condi tions 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. O ne 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

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- 2635.1,Comment Excerpt Number 5.

Commenter Name: Robert D. Besset te Commenter Affiliation: Council of Industrial Boiler Owners (CIBO) Document Control Number: EPA

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- 2702.1 Comment Excerpt Number: 109

Comment: Variability of Sorbent Injection Over Loads. Sorbent injection limits should not be fixed at th e 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 to317 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 Aff iliation: Council of Industrial Boiler Owners (CIBO) Document Control Number: EPA

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- 2702.1 Comment Excerpt Number: 110

Comment: Values Obtained During Initial Performance Tests are Not Necessarily Representative. CIBO also has concerns wit h 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 th e 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. Suc h 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

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- 2635.1,Comment Excerpt Number 5.

Commenter Name: Robert D. Bessette Commenter Affiliation: Council of Industrial Boiler Owners (CIBO) Document Control Nu mber: EPA

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- 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 N ESHAP (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 operating318 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 supple mented 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 a ccommodate 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 moni toring 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

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- 2635.1,Comment Excerpt Number 5.

Commenter Name: Robert D. Bessette Commenter Affiliation: Council of Industrial Boiler Owners (CIBO) Document Control Number: EPA

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- 2702.1 Comment Ex cerpt 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 grea tly 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 wha t 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 N ame: Robert D. Bessette Commenter Affiliation: Council of Industrial Boiler Owners (CIBO) Document Control Number: EPA

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- 2702.1 Comment Excerpt Number: 139

Comment: Semiannual flow sensor calibration is too frequent and unjustified. The Pr oposed 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 s ensors 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

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- 1907.1 , Comment Excerpt Number 37.

Commenter Name: Robert D. Bessette Commenter Affiliation: Council of Industrial Boiler Owners (CIBO) Document Control Number: EPA

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- 2702.1 Comment Excerpt Number: 140

Comment: Daily check of pressure tap pl uggage 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 r equirement does not reflect common practice. CIBO recommends that EPA amend this requirement so that it is more flexible.

Response: See the response to EPA

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- 1907.1, Comment Excerpt Number 37.

Commenter Name: Robert D. Bessette Comme nter Affiliation: Council of Industrial Boiler Owners (CIBO) Document Control Number: EPA

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- 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. Autocalibration320 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

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- 1907.1, Comment Excerpt Number 37.

Commenter Name: Robe rt D. Bessette Commenter Affiliation: Council of Industrial Boiler Owners (CIBO) Document Control Number: EPA

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- 2702.1 Comment Excerpt Number: 142

Comment: The sorbent injection rate monitoring requirements are too unreasonable. Sources wi th 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 specificatio ns. 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 a nnually 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: S ee the response to EPA

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- 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 Co ntrol Number: EPA

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- 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 repeate d 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

- estab lished 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 qua lity. The National Institute of Standards and Technology, the U.S. government agency concerned with the quality and reliability of measurement data, does321 not require fixed calibration intervals. Other U.S. government agencies such as NASA also do not requi re 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 detail s 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.

A dditionally, 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) whi ch 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) an d the available metrology consensus standards.

Response: See the response to EPA

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- 1907.1, Comment Excerpt Number 37.

Commenter Name: Matthew Todd and David Friedman Commenter Affiliation: American Petroleum Institute (API) and Natio nal Petrochemical and Refiners Association (NPRA) Document Control Number: EPA

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- 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 a ny 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, 63.7 505(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 Recommend ation: 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 r ulemaking, 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 thei r 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 Petr oleum Institute (API) and National Petrochemical and Refiners Association (NPRA) Document Control Number: EPA

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- 2960.1 Comment Excerpt Number: 151

Comment: If proposed 63.7505(d) is maintained for CPMS and 63.8(a)(2) is made non

applicable, 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 param etric 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 non

applicable, revise 63.7505(d)(1)(ii) to remove the data collection and reduction systems and cla rify 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 b asic information and specifications for the collection system to ensure that it is capable of capturing and storing data at323 appropriate frequencies. There is no need for massive amounts of information to meet this requirement. This requirement has been inc luded 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 Asso ciation (NPRA) Document Control Number: EPA

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- 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 rat e.” 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 " no t 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) Docu ment Control Number: EPA

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- 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 C ommenter Affiliation: American Petroleum Institute (API) and National Petrochemical and Refiners Association (NPRA) Document Control Number: EPA

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- 2960.1324 Comment Excerpt Number: 157

Comment: Proposed 63.7525(e)(4) specifies that required fl ow 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, Rosem ont, 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 o perate 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 du ring 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

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- 1907.1, Comment Excerpt Number 37.

Commenter Na me: Matthew Todd and David Friedman Commenter Affiliation: American Petroleum Institute (API) and National Petrochemical and Refiners Association (NPRA) Document Control Number: EPA

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- 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

max imum 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 have325 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 a ny 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 t esting 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 reasonab le 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 add ing 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 o r 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 re ading 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 a nnual 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 pr essure reading is varying, change the calibration frequency in (f)(5) to annual and delete paragraph (f)(6).

Response: See the response to EPA

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- 1907.1, Comment Excerpt Number 37.

Commenter Name: Matthew Todd and David Friedman Comme nter Affiliation: American Petroleum Institute (API) and National Petrochemical and Refiners Association (NPRA) Document Control Number: EPA

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- 2960.1326 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 calibratio n, 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 Com ment 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

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- 1907.1, Comment Excerpt Number 37.

Commenter Name: Matthew Todd and David Friedman Commenter Affiliation: American P etroleum Institute (API) and National Petrochemical and Refiners Association (NPRA) Document Control Number: EPA

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- 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 perf ormance 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 sorb ent 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 t han 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 establis hing operating limits for control device operating parameters to reflect differences between performance test conditions and the real world.

Response: See the response to EPA

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- 2635.1,Comment Excerpt Number 5.327 Commenter Name: Robert D . Bessette Commenter Affiliation: Council of Industrial Boiler Owners (CIBO) Document Control Number: EPA

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- 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 b ased 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

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- 2702.1 Comment Excerpt Number: 203

Comment: Averaging Periods Emission l imits 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 cour se 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
t imes. 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 ho urs 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. T he facility must be able to operate the boiler in a manner that is328 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 i n 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 u se 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 wi ll 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 o perating limits being used.

Commenter Name: Randall D. Quintrell Commenter Affiliation: Georgia Paper and Forest Products Association, GPFPA Document Control Number: EPA

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- 2905 Comment Excerpt Number: 28

Comment: Flexibility should be in cluded in the compliance monitoring provisions, such as allowing the use of a CO 2 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 an d 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 CO 2 diluent comment is no longer applicable. The Agency believes the ot her 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 s ources.

Commenter Name: Marvis A. Lewallen329 Commenter Affiliation: Clearwater Paper Document Control Number: EPA

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- 2862 Comment Excerpt Number: 6

Comment: We encourage EPA to allow sources greater flexibility in how they establish
parame ter 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 estab lishing 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 di fficulty 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 so urces. 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 t he 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
prop osed 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

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- 2635.1,Comment Excerpt Number 5.

Commenter Name: Edward Bortz Commenter Aff iliation: SP Newsprint Co LLC Document Control Number: EPA

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- 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 th at 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 requires330 that such parameters be established for certain controls. Based on industry experience, we know
t he 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 su ch 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

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- 2635.1,Comment Excerpt Number 5.

Commenter Name: John Hopewell Comment er Affiliation: American Coatings Association Document Control Number: EPA

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- 2886.1 Comment Excerpt Number: 13

Comment: The CPMS QA/QC requirements are not appropriate.

Facilities need more flexibility in development of operating paramete r 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 paramete r 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 initiall y 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

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- 1907.1, Comment Excerpt Number 37.

Commenter Name: J. Michael Geers331 Commenter Affiliation: Duke Energy Document Control Number: EPA

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- 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 c ontrols 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 h ow 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 paramet ers. 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 a332 restriction such as a scrubber vessel is a directly related to velocity. As the velocity increases, the pressure drops. Recording pre ssure 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 du ring 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 va riability 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

sou rce 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: Se e the response to EPA

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- 2635.1,Comment Excerpt Number 5.

Commenter Name: J. Michael Geers Commenter Affiliation: Duke Energy Document Control Number: EPA

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- 2765.1 Comment Excerpt Number: 19

Comment: Operating Limits Propos ing 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 63.75 00(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 a s 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 o n 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 bitum inous 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 sufficie nt 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 t enuous 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, b ecause 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

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- 2635.1,Commen t Excerpt Number 5.

Commenter Name: John C. deRuyter Commenter Affiliation: DuPont Document Control Number: EPA

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- 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, scr ubbing 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 cost s. 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 causin g other system problems. Scrubber flow rates and other parameters need to vary with operating loads and other parameters for optimum system334 operation. Therefore, EPA must allow for variations in all operating parameters/limits as appropriate for the equipm ent and operations involved.

Response: See the response to EPA

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- 2635.1,Comment Excerpt Number 5.

Commenter Name: J. Michael Geers Commenter Affiliation: Duke Energy Document Control Number: EPA

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- 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 limi t 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 a bout 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 lev el 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

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- 0284, at 2.5.3.

Response: See the response to EPA

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- 2635.1,Comment Excerpt Number 5.

Commenter Name: J. Michael Geers Commenter Affiliation: Duke Energy Document Control Number: EPA

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- 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 req uirements 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 compli ance as required by the CAA). Source335 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 combina tion 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 t han 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” tes t 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 l ess 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 wo uld 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 establis hed 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: S ee the response to EPA

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- 2635.1,Comment Excerpt Number 5.

Commenter Name: David Foerter Commenter Affiliation: Institute of Clean Air Companies Document Control Number: EPA

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- 2937.1 Comment Excerpt Number: 27

Comment: Give n 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 para meters 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

an d 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 th e three test run averages336 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 spe cific 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 a nd 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

c onditions, 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 complia nce oversight and no change to the rule is necessary.

Commenter Name: David Foerter Commenter Affiliation: Institute of Clean Air Companies Document Control Number: EPA

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- 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 recommend s 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 operat ing 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 pr ovided for in the general provisions.337 Commenter Name: Russ A. Wozniak Commenter Affiliation: Dow Chemical Company Document Control Number: EPA

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- 2632.1 Comment Excerpt Number: 49

Comment: EPA Should Revise the Requirements in Proposed S ection 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 own er/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 r equirements 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 in338 acc ordance with industry practices as further defined in the monitoring plan required by section 63.7505(d).

Response: See the response to EPA

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- 1907.1, Comment Excerpt Number 37.

Commenter Name: Russ A. Wozniak Commenter Affiliation: D ow Chemical Company Document Control Number: EPA

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- 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 add

on controls. EPA must make allowances for these situations, and we discuss more specific concerns later in this comment.

Response: See the response to EPA

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- 2635.1,Comment Exce rpt Number 5.

Commenter Name: Russ A. Wozniak Commenter Affiliation: Dow Chemical Company Document Control Number: EPA

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- 2632.1 Comment Excerpt Number: 51

Comment: Establishing site specific operating limits based on an average of 3 stac k 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 us ed 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

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- 2 635.1,Comment Excerpt Number 5.

Commenter Name: Russ A. Wozniak Commenter Affiliation: Dow Chemical Company Document Control Number: EPA

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- 2632.1 Comment Excerpt Number: 52339 Comment: In order to set acceptable operating parameters, a sour ce 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 n o add

- on controls is a very risky approach for a boiler when striving to achieve operational flexibility.

Response: See response to comment EPA

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- 2632.1, excerpt 54.

Commenter Name: Russ A. Wozniak Commenter Affiliation: Dow Chemical C ompany Document Control Number: EPA

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- 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 arti ficial 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 ch lorine 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

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- 2632.1, excerpt 54.

Commenter Name: Russ A. Wozniak Commenter Affiliation: Dow Chemical Company Document Control Number: EPA

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- 2632.1 Comment Excerpt Number: 54

Comment: All sources shall be allowed to back calculate th e 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 to340 demon strate 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 multip lier 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 contro ls 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 nec essary 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 merc ury fuel input operating limit.

Commenter Name: Russ A. Wozniak Commenter Affiliation: Dow Chemical Company Document Control Number: EPA

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- 2632.1 Comment Excerpt Number: 55

Comment: For boilers and process heaters with wet scrubbers, fac ilities 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 site

specific pressure drop and liqui d 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 mus t 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, amo ng 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

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- 2635.1,Comment Excerpt Number 5.

Commenter Name: Russ A. Wozniak Commenter Affiliation: Dow Chemical Company Document Control Number: EPA

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- 2632.1 Comment Excerpt Number: 56341 Comment: For boilers and process heaters with sor bent 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 be comes 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

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- 2635.1,Comment Excerpt Number 5.

Commenter Name: Russ A. Wozniak Commenter Affiliation: Dow Chemical Company Document Control Number: EPA

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- 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 spec ific 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 p eriod 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

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- 2635.1,Comment Excerpt Number 5.

Commenter Name: Russ A. Wozniak Commenter Affiliation: Dow Chemical Company Document Control Number: EPA

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- 2632.1 Comment Excerpt Number: 58

Comment: For boilers and process heaters with electro static 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, a nd 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, settin g a parameter level during times of342 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

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- 2002

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- 2635.1,Comment Excerpt Number 5.

Commenter N ame: Russ A. Wozniak Commenter Affiliation: Dow Chemical Company Document Control Number: EPA

- HQ

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- 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 dependi ng 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

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- 20 02

- 0058

- 2632.1, excerpt 54.

Commenter Name: Chris M. Hobson Commenter Affiliation: Southern Company Document Control Number: EPA

- HQ

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- 2002

- 0058

- 2741.1 Comment Excerpt Number: 59

Comment: In 63.7525(j)(2), EPA proposes that sources installing bag lea k 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 Detecto rs, 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: AST M 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 those343 conditions may dictate variances from the approach and is allowe d 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

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- 2002

- 0058

- 2741.1 Comment Excerpt Number: 61

Comment: EPA has specified that all pa rametric 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 non

compliance 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 i s 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 r eporting 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 lowe r 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 cond itions, 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 oper ating 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

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- 2002

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- 2635.1,Comment Excerpt Number 5.

Commenter Name: Chris M. Hobson Commenter Affiliation: Southern Company Document Control Number: EPA

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- 2741. 1 Comment Excerpt Number: 63344 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, ina ppropriate, 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 als o 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 u se 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 minim um 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 Complian ce 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 alt ernatives 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

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- 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 re duced operations. Requiring that pressure drop to be maintained would require that the boiler/heater always be345 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 suggest s 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 c urrent 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 remov al performance that exceeds what was obtained during the performance test.

Response: See the response to EPA

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- 2002

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- 2635.1,Comment Excerpt Number 5.

Commenter Name: Chris M. Hobson Commenter Affiliation: Southern Company Document Control Nu mber: EPA

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- 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 inap propriately 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 l oads.

Response: See the response to EPA

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- 2635.1,Comment Excerpt Number 5.346 Commenter Name: Gregory A. Wilkins Commenter Affiliation: Marathon Petroleum Company Document Control Number: EPA

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- 2002

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- 3119.1 Comment Excerpt Numbe r: 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 a nd 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 N umber: EPA

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- 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 o f 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 Internationa l Inc Document Control Number: EPA

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- 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 ha s been changed.

Commenter Name: Roy W. Wood Commenter Affiliation: Eastman Kodak Company Document Control Number: EPA

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- 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 us e 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 equipme nt 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 establi sh 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 wide ly 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 oper ating 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, wit h 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 part iculate 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 HC l)]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 Pr ecipitation, 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 velocit y 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 equat ion, 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 d emonstrated 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 ef ficiency 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

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- 263 5.1,Comment Excerpt Number 5.

Commenter Name: Mick Baranko Commenter Affiliation: Douglas County Forest Products Document Control Number: EPA

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- 0058

- 2856.1 Comment Excerpt Number: 10

Comment: We encourage EPA to allow sources greater flexibil ity in how they establish parameter ranges for monitoring compliance with parameter operating limits. The proposed349 regulations require. that for biomass boilers with wet scrubbers, sorbent injection or ESPs with wet scrubbers, that the source establish ope rating 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 indu stry 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 base d 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 p oses 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

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- 2002

- 0058

- 2635.1,Comment Excerpt Number 5.

Commenter N ame: David O'Keefe Commenter Affiliation: USEC, Inc Document Control Number: EPA

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- 2002

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- 3122 Comment Excerpt Number: 10

Comment: Site

- specific operating limits, the proposed site

- specific operating limits should include variability and uncertain ty 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 wel l 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 mor e 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 calculated350 injecti on 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 i n 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

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- 2635.1,Comment Excerpt Number 5.

Commenter Name: Gary W. Kruger Commenter Affiliation: Morton Salt Document Control Number: EPA

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- 2002

- 0058

- 2883.1 Comment Excerpt Number: 10

Comment: EPA’s Opera ting 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 techni cally 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 operatin g 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

env ironment. 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

- consum ption 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 main tain 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 cont rol equipment to ensure351 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

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- 0058

- 2635.1,Comment Excerpt Number 5.

Commenter Name: Michael L. Corvese Comment er Affiliation: Thermo Fisher Scientific, Inc Document Control Number: EPA

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- 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 reliabi lity 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 requi red 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 fou nd 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

man ufacturer’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 assuran ce for CEMS that352 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 ap propriate 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 wi thin 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 guidan ce 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 guid ance.

Commenter Name: Gary W. Kruger Commenter Affiliation: Morton Salt Document Control Number: EPA

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- 2883.1 Comment Excerpt Number: 11

Comment: Opacity Values Obtained During Initial Performance Tests are Not Necessarily Representativ e. 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, densi ties, 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 bes ides 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 an alyses 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 elsew here 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 o ne 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, mer cury 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 prora ted 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 p erformance test.

Response: See generally the response to EPA

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- 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 Affil iation: Thermo Fisher Scientific, Inc Document Control Number: EPA

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- 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 manufact urer’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 D etection 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 whi ch 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 transf er 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.

Com menter Name: Michael L. Corvese Commenter Affiliation: Thermo Fisher Scientific, Inc Document Control Number: EPA

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- 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 c oncentrations 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. tak en 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 instrumen t 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 Qual ity Planning and Standards (OAQPS) Fabric Filter Bag Leak Detection Guidance" document needs updating or is355 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 procedur es, 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 manufacture r 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 m ay 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

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- 2752.1 Comment Excerpt Number: 15

Comment: Ope rating 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 const itute 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 facil ity 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 ra te 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 con ditions, 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 ful l 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 ga s temperatures, the flow

- rate of slurry will be relatively high. If this were established as a site

- specific minimum356 sorbent injection rate, the unit would inject more slurry than the flue gas could accommodate at low loads. One member company with solid

- f uel 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 consider able 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 lime stone 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

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- 2635.1,Comment Excerpt Number 5.

Commenter Name: American Crystal Sugar Co mpany and Michigan Sugar Company Commenter Affiliation: Patricia Hansen and Steven Smock Document Control Number: EPA

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- 2970.1 Comment Excerpt Number: 16

Comment: The frequency of calibration for some operational monitors is excessively hig h. 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

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- 1907.1, Comment Excerpt Number 37.

Commenter Name: Bill Wemhoff Commenter Affiliation: National Rural Electric Cooperative Association Document Control Number: EPA

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- 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 Monitor ing (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 propo sed 10 percent opacity standard, particularly in the absence of any exception for startup, shutdown, or357 malfunction. Objects to several provisions related to proposed bag leak detection systems and the lack of clarity in EPA’s proposed requirements for per iodic fuel analysis.

Response: See the response to EPA

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- 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

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- 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

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- 2635.1,Comment Excerpt Number 5.

Commenter Name: Lee B. Zeugin Commenter Affiliation: Uti lity Air Regulatory Group Document Control Number: EPA

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- 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. E stablishment 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 t he 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 wil l 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 there358 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 add ition 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 t he 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 emi ssions, 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

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- 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 performan ce 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 operati onal 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 restri ct 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

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- 2635.1,Comment Excerpt Number 5.359 Commenter Name: Le e B. Zeugin Commenter Affiliation: Utility Air Regulatory Group Document Control Number: EPA

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- 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

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- 0246 (Mar. 27, 2007) at 21

- 22, and Attachment 2 (incorporated by reference); UARG Comments EPA

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- 0413, Attachment C, Appendix 1. Moreover, none of the ESP parameters are likely to have any relationship to PM at units that al so 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

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- 0246 at 15

- 16 and Attachment 2.

Response: See the response to EPA

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- 2635.1,Comment Excerpt Number 5.

Commenter Name: Lee B. Zeugin Commenter Affiliation: Utility Air Regulatory Group Document Control Number: EPA

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- 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 de scribed 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 emissio ns 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

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- 0284, at § 2.5.3.

Response: See the resp onse to EPA

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- 2635.1,Comment Excerpt Number 5.360 Commenter Name: David M. Kiser Commenter Affiliation: International Paper Company Document Control Number: EPA

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- 2777.1 Comment Excerpt Number: 40

Comment: EPA should not pres cribe 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 bec ause 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 exp erience”. 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 m ore 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

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- 1907.1, Comment Excerpt Number 37.

Commenter Name: Lee B. Zeugin Commenter Affiliation: Utility Air Regulatory Group Document Control Number: EPA

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- 28 80.1 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 compl iance 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 indic ate 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, mult iple 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

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- 0413, Attachment C at 4. In addition, units with significant margins of compliance361 should be allowed to establish operating levels by extrapolating parameter data beyond that obtained during a performance test based on o ther 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 a re 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 protoco l 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 operati ng 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 a ction 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

recor d exceedances and report deviations) achieves EPA’s intended result without subjecting sources to potential unreasonable enforcement.

Response: See the response to EPA

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- 2635.1,Comment Excerpt Number 5.

Commenter Name: Lee B. Zeugin C ommenter Affiliation: Utility Air Regulatory Group Document Control Number: EPA

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- 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 demonstra te 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 o r 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 demonst rates 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

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- 0413 at 24, EPA simply referred back to its 19 97 guidance. See EPA Response to Public Comments, EPA

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- 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 recommendati ons 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 “recommendation s.” 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 on ly 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 Pl anning 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 proce dures, 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, an d 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 o f 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 manuf acturer 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 b ag 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 Affil iation: Utility Air Regulatory Group Document Control Number: EPA

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- 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 wi th 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 w et 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”); 63.7 540(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 mu st 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 doe s 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 th e 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 supp orts 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 re sult, 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, whic h clearly allows fabric filter equipped units with dry control systems the choice of using opacity instead of a BLDS. EPA also should revise proposed364 § 64.7530(b)(3)(ii) to make clear that units complying with an opacity standard do not have to establish E SP 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

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- 2745.1 Comment Excerpt Number: 52

Comment: The r e

- 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 proper ly 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 bo ilers 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 o f 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 o r 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

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- 1907.1, Comment Excerpt Number 37.

Commenter Name: Christopher S. Colm an Commenter Affiliation: Hovensa LLC365 Document Control Number: EPA

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- 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 provide d 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 fi nal rule.

Commenter Name: Traylor Champion Commenter Affiliation: Georgia

- Pacific LLC Document Control Number: EPA

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- 2745.1 Comment Excerpt Number: 53

Comment: The re

- calibration requirement for pressure gauges should be annually or at t he 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 basi s 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

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- 1907.1, Comment Excerpt Number 37.

Commenter Name: Traylor Champion Commenter Affiliation: Georgia

- Pacific LLC Document Control Number: EPA

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- 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, more366 practical, methods available for assuring that pressure taps are not plugged. If a pr essure 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 a ssure 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 Stand

Alone Semichemical Pulp Mills [see 40 CFR 63.866(a)(2)(ii)].

Response: See the response to EPA

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- 1907.1, Comment Excerpt Number 37.

Commenter Name: Traylor Champion Commen ter Affiliation: Georgia

- Pacific LLC Document Control Number: EPA

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- 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 me asured 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 Catego ries, 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

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- 1907.1, Comment Excerpt Number 37.

C ommenter Name: Lee B. Zeugin367 Commenter Affiliation: Utility Air Regulatory Group Document Control Number: EPA

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- 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, inc luding 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

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- 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 spec ifications 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
req uirements 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 mini mize 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

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- 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 “wo rk” the ESP is doing in terms of transfer of electrostatic charge to particles in the gas stream. However, these indicators368 provide relevant emissions information only to the extent that parameters such as particle loading to the ESP, particle size, partic le 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. Th is 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/am perage 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. Thi s 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 d ischarge 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 to tal 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 s eparation 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 constantl y 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, hi gh 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 t o 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 co ncentration, 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 volta ge 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

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- 2880.1 Comment Excerpt Number: 69

Comment: To reduce manpower requirements most sources will likely attempt to automate as much of the reportin g 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.

Re sponse: 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

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- 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 period3 70 acknowledges process variability, lessens the effect of short process upsets on c ompliance, 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 N ame: Jim Griffin Commenter Affiliation: American Chemistry Council Document Control Number: EPA

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- 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 e lectronic 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 inspec tions. 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 ran ge 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 s tandards 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. O ther 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 requi red 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 tha t time. Many of these early instruments suffered from drift, non

- linearity, and other performance issues that required371 frequent checks. Computerized control was virtually unknown. Today’s instruments are generations away from those early CEMS. They are sta ble, 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 immediate ly 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 dr ift, 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 cal ibration 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. I f a system is consistently passing a six

- month QA/QC check, that check may be increased to annual.

Response: See the response to EPA

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- 1907.1, Comment Excerpt Number 37.

Commenter Name: Jim Griffin Commenter Affiliation: American Che mistry Council Document Control Number: EPA

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- 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: Se e the response to EPA

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- 1907.1, Comment Excerpt Number 37.372 Commenter Name: Jim Griffin Commenter Affiliation: American Chemistry Council Document Control Number: EPA

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- 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 testi ng 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

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- 1907.1, Comment Excerpt Number 37.

Commenter Name: Jim Griffin Commenter Affiliation: American Chemistry Council Document Control Number: EPA

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- 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 req uirement is not justified. Calibration or replacement should only be required if the instrument’s reading is suspect.

Response: See the response to EPA

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- 1907.1, Comment Excerpt Number 37.

Commenter Name: Jim Griffin Commenter Affili ation: American Chemistry Council Document Control Number: EPA

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- 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 pH373 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 instrumen ts 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, whic h adds to the already significant control, testing, and monitoring costs for this rule if this requirement is retained.

Response: See the response to EPA

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- 1907.1, Comment Excerpt Number 37.

Commenter Name: Jim Griffin Commenter Affi liation: American Chemistry Council Document Control Number: EPA

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- 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 ac count and establish the appropriate inspection and calibration intervals for each type of monitoring device.

Response: See the response to EPA

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- 1907.1, Comment Excerpt Number 37.

Commenter Name: Jim Griffin Commenter Affiliation: Am erican Chemistry Council Document Control Number: EPA

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- 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 un der 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

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- 2635.1,Comment Excerpt Number 5.374 Commenter Name: Jim Gri ffin Commenter Affiliation: American Chemistry Council Document Control Number: EPA

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- 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 p roposed 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 operat ing 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 f acilities 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 monitor ing 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 captu res 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 use d for compliance, the final rule likewise does not require compliance with an opacity st a ndard under this subpart. Also, see the response to EPA

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- 3213.1, Comment Excerpt Number 301. For the HCl issue, see the response to EPA

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- 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

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- 1600.1 Comment Excerpt Number: 3375 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 oblig ations 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 a nticipated 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.

Re sponse: 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 sect ors 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: Ne w York City Department of Environmental Protection Document Control Number: EPA

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- 1600.1 Comment Excerpt Number: 6

Comment: The EPA should also consider incentivizing switches to cleaner fuels by waiving or modifying the stack testing requi rement for fuel oil mode if major source boilers are firing ultra

low 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 wil l 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, demonstrate d 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 deta iled list of commenters376 Document Control Number: EPA

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- 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

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- 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 requiremen ts are excessive. Th e 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

recurr ing 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 meas ured 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

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- 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 succes sful stack test therefore the risk of a significant change in emissions should be low. Testing shouJd be377 required no more frequency than every five (5) years, unless a change in method of operation that could potentially affect emissions is proposed.

Re sponse: See the response to EPA

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- 1879, Comment Excerpt Number 3.

Commenter Name: Richard Holland Commenter Affiliation: Packaging Corporation of America Document Control Number: EPA

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- 2385 Comment Excerpt Number: 4

Comm ent: 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 ad ditional 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 satisfi ed 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 pro bability 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 hydr ogen 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, MACT378 is a technology

- driven standard. Initial performance tests ha ve 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

- f ive

- 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 b y 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 thre e 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

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- 1879, Comment Excerpt Number 3.

Commenter Name: Ashle y Peterson Commenter Affiliation: American Meat Institute Document Control Number: EPA

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- 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 fr om the system will not appreciably change unless the system is modified.

Response: See the response to EPA

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- 1879, Comment Excerpt Number 3.

Commenter Name: Robin Mills Ridgway Commenter Affiliation: Purdue University Document Control Number: EPA

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- 2782.1 Comment Excerpt Number: 7

Comment: Annual testing frequency is unworkable for continuously operating and maintained plants like Purdue’s Wade Utility Plant379 §63.7515(a)’s timing requirement is too restrictive for plant s 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 con ducts 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 doe s 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 ini tial 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.

Additiona lly, 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 f or 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 t han 13 months after the prior test.

Commenter Name: Rich Raiders Commenter Affiliation: Arkema, Inc Document Control Number: EPA

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- 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 chlo rides. 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 cert ain 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 a llow380 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

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- 1879, Comment Excerpt Number 3.

Commenter Name : Steven M. Maruszewski Commenter Affiliation: The Pennsylvania State University Document Control Number: EPA

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- 2729.1 Comment Excerpt Number: 14

Comment: Test interval

- §63.7515 Testing Interval Proposed rule requires testing every ten t o 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 dur ing 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 specif ic cases. This would allow load following facilities to test during high demand months.

Response: See the response to EPA

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- 2782.1,Comment Excerpt Number 7.

Commenter Name: Stephen R. Gossett Commenter Affiliation: Eastman Chemical C ompany Document Control Number: EPA

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- 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 ever y 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 f or 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 of381 compliance, and this is just for this one regulation. We belie ve this is clearly an unreasonable requirement.

Response: See the response to EPA

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- 1879, Comment Excerpt Number 3.

Commenter Name: Stephen R. Gossett Commenter Affiliation: Eastman Chemical Company Document Control Number: EPA

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- 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 prop erly 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, we t 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

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- 1879, Comment Excerpt Number 3.

Commenter Name: Britt S. Fl eming Commenter Affiliation: Auto Group Document Control Number: EPA

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- 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 lat er 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 “ma ximum 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 p er permit cycle (once every 5 years). Thus, sources already are required to382 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

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- 1879, Comment Excerpt Number 3. Also, see the response to EPA

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- 2782.1,Comment Excerpt Number 7.

Commenter Name: Timothy Hunt Commenter Affiliation: American Forest and Paper Association (AF&PA) Document Control Number: EPA

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- 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 f uel 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 respons e to EPA

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- 2782.1,Comment Excerpt Number 7.

Commenter Name: Timothy Hunt Commenter Affiliation: American Forest and Paper Association (AF&PA) Document Control Number: EPA

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- 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

a ware 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 perf ormance 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 capa ble of meeting the emission limits. EPA has proposed extensive monitoring and recordkeeping that is meant to ensure383 continuous compliance with the emission standards. Therefore, the frequency of stack testing should be reduced to once every 5 years.

Res ponse: See the response to EPA

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- 1879, Comment Excerpt Number 3.

Commenter Name: Timothy Hunt Commenter Affiliation: American Forest and Paper Association (AF&PA) Document Control Number: EPA

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- 3213.1 Comment Excerpt Numbe r: 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 e ligible 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 Industria l Boiler Owners (CIBO) Document Control Number: EPA

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- 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 Leve l. 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

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- 1879, Comment Excerpt Number 3.384 Commenter Name: Randall D. Quintr ell Commenter Affiliation: Georgia Paper and Forest Products Association, GPFPA Document Control Number: EPA

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- 2905 Comment Excerpt Number: 2

Comment: One aspect of the unnecessary and unreasonable burden that the Rule would impose is the f requency 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, th e 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 o n

- 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 su ch 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 test ing under MACT.

Response: See the response to EPA

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- 1879, Comment Excerpt Number 3.

Commenter Name: Randall D. Quintrell Commenter Affiliation: Georgia Paper and Forest Products Association, GPFPA Document Control Number: EPA

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- 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 affec ted 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

a ny 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 interv als 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 test ing frequency in Title V permits.385 Response: See the response to EPA

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- 2782.1,Comment Excerpt Number 7.

Commenter Name: Randall D. Quintrell Commenter Affiliation: Georgia Paper and Forest Products Association, GPFPA Document Control N umber: EPA

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- 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 fir ms 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 i s not required under the final rule.

Commenter Name: Donald R. Schregardus Commenter Affiliation: Department of Defense Document Control Number: EPA

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- 2763.1 Comment Excerpt Number: 23

Comment: EPA should revise the requirement to conduc t 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 ear lier 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 perf ormance 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 perf ormance 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.

Res ponse: See the response to EPA

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- 2782.1,Comment Excerpt Number 7.

Commenter Name: Chris Greissing Commenter Affiliation: Industrial Minerals Association Document Control Number: EPA

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- 2740.2 Comment Excerpt Number: 28

Com ment: 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 great er 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 performanc e 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 performanc e tests once each calendar year but no sooner than six months after the previous test.

Response: See the response to EPA

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- 0058

- 2782.1, Comment Excerpt Number 7.

Commenter Name: David A. Buff Commenter Affiliation: Golder Associates Inc Do cument Control Number: EPA

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- 2801.1 Comment Excerpt Number: 58387 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 ever y 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

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- 2702.1 Comment Exce rpt 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 deterior ating." 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 scru bber 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

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- 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

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- 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 justif ied 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 t hat 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 b eing continuously monitored for compliance using continuous parameter monitors.

Response: See the response to EPA

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- 1879, Comment Excerpt Number 3.388 Commenter Name: Matthew Todd and David Friedman Commenter Affiliation: American Petrol eum Institute (API) and National Petrochemical and Refiners Association (NPRA) Document Control Number: EPA

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- 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 massiv e 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

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- 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

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- 2960.1 Comment Excerpt Number: 174

Comment: Despite the Agency‘s unsuppor ted 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. Dio xin/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 indi cate 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 requ irement for annual dioxin/furan performance tests. Instead require an initial dioxin/furan performance test and retesting if the unit is modified. This also389 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

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- 2960.1 Comment Excerpt Number: 177

Comment: Proposed 63.75 15 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 su ch 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 t he 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 perform ance 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.

R esponse: See the response to EPA

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- 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) Docu ment Control Number: EPA

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- 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 are390 limited and workload needs to be spread throughout the year to allow these resources to be efficiently utilized.

Recommendations: Allow for changi ng performance test timing to allow sources to spread out the effort throughout a year.

Response: See the response to EPA

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- 0058

- 2782.1, Comment Excerpt Number 7.

Commenter Name: Jeffrey R.Klieve Commenter Affiliation: Monsanta Company Doc ument Control Number: EPA

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- 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 th e response to EPA

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- 0058

- 1879, Comment Excerpt Number 3.

Commenter Name: Eric Trauner Commenter Affiliation: Citizen Document Control Number: EPA

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- 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 u nqualified, 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

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- 1879, Comment Excerpt Num ber 3.

Commenter Name: Dave Copeland Commenter Affiliation: Praxair Inc Document Control Number: EPA

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- 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 alternatives391 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 o n 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

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- 005 8

- 1879, Comment Excerpt Number 3.

Commenter Name: John Hopewell Commenter Affiliation: American Coatings Association Document Control Number: EPA

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- 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

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- 0058

- 1879, Comment Excerpt Number 3.

Commenter Name: Pamela F. Faggert Co mmenter Affiliation: Dominion Document Control Number: EPA

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- 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 f or 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 u nits 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 th e 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 no t 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 wit hin 720 unit operating hours after the test is normally required to be completed.392 Response: See the response to EPA

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- 2782.1, Comment Excerpt Number 7.

Commenter Name: Pamela F. Faggert Commenter Affiliation: Dominion Document Control Number: EPA

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- 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 ha ve 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
t ests. 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 fin al rule.

Commenter Name: Russ A. Wozniak Commenter Affiliation: Dow Chemical Company Document Control Number: EPA

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- 2632.1 Comment Excerpt Number: 40

Comment: EPA provides no insight or justification in the preamble or otherwise for requ iring 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 Waste393 Combustion MACT Section 63.1207(d)(1), requires initial retesting after 5 years. Dioxin/Furan retesting is only required for facil ities 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 orga nization 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 fina lize 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

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- 1879, Comment Excerpt Number 3.

Commenter Name: Russ A. Wozniak Commenter Affili ation: Dow Chemical Company Document Control Number: EPA

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- 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 perf ormance 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 w ithout 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 ru le, 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

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- 2876.1 Comment Excerpt Number: 2

Comment: The cost of annual testing is prohibitively high. The annual testing requirement is cost prohibitive for all therma l biomass systems, regardless of size. Annual testing may be feasible for boilers generating electricity, which receive substantial tax incentives, but it is not394 feasible for thermal

- only systems. Many of our customers are rural schools, municipal building s, 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 i n 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 aff ord 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

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- 0058

- 1879, Comment Excerpt Number 3.

Commenter Name: Gene Barr Commenter Affiliation: Pennsylvania Chamber of Business and Industry Document Control Number: EPA

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- 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 ca n. 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 Aff iliation: Boise Cascade, LLC Document Control Number: EPA

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- 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 an d 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 th e emission limits.

Response: See the response to EPA

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- 1879, Comment Excerpt Number 3.395 Commenter Name: James C. Jackson Commenter Affiliation: Boise, Inc Document Control Number: EPA

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- 2002

- 0058

- 2855.1 Comment Excerpt Number: 5

C omment: 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 rec ommends 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 com pliant manner in the interim between stack tests.

Response: See the response to EPA

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- 0058

- 1879, Comment Excerpt Number 3.

Commenter Name: Wayne J. Galler and Deborah A. Phillips Commenter Affiliation: Georgia Industry Environmental Coaliti on, Inc Document Control Number: EPA

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- 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 small er 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 te st 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

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- 2002

- 0058

- 1879, Comment Excerpt Number 3.

Commenter Name: John M. Irving Commenter Affiliation: Burlington Electric Department Document Control Numbe r: EPA

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- 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 operating396 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

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- 2002

- 0058

- 1879, Comment Excerpt Number 3.

Commenter Name: Rich ard Krock Commenter Affiliation: The Vinyl Institute Document Control Number: EPA

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- 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 depend ing 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 worst

case fuel mix during such tests.

Response: See the response to EPA

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- 0058

- 2782.1,Comment Excerpt Number 7.

Commenter Name : Paul J. Allen Commenter Affiliation: Constellation Energy Document Control Number: EPA

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- 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 surrogate s 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

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- 0058

- 187 9, Comment Excerpt Number 3.

Commenter Name: Tom Midyett Commenter Affiliation: Tennessee Paper Council Document Control Number: EPA

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- 0058

- 2691.1397 Comment Excerpt Number: 10

Comment: The Agency issued an Information Collection Request (ICR) i n 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 I CR 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, a lternative 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 require s 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 t he 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 a ffected 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 s ensitive 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 i s set for a high probability of questionable or inaccurate results.

Response: See the response to EPA

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- 1879, Comment Excerpt Number 3.

Commenter Name: Tom Midyett Commenter Affiliation: Tennessee Paper Council Document Control Number: EPA

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- 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 combuste d 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 anothe r 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 believe s is entirely unnecessary.

Response: See the response to EPA

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- 1879, Comment Excerpt Number 3.398 Commenter Name: Tom Midyett Commenter Affiliation: Tennessee Paper Council Document Control Number: EPA

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- 0058

- 2691.1 Comment Exc erpt 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 on

going testing falls under the purview of the respective States.

While the original Boiler MACT rule required annual PM te sting (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

- i n

- 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 tech nology.

Response: See the response to EPA

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- 0058

- 1879, Comment Excerpt Number 3.

Commenter Name: Gary W. Kruger Commenter Affiliation: Morton Salt Document Control Number: EPA

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- 0058

- 2883.1 Comment Excerpt Number: 14

Comment: EP A 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 performa nce is not deteriorating.

Response: See the response to EPA

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- 0058

- 1879, Comment Excerpt Number 3.

Commenter Name: Mark W. Kowlzan Commenter Affiliation: Packaging Corp. of America Document Control Number: EPA

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- 0058

- 2913.1 Comme nt Excerpt Number: 14399 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 technolo gy

- 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 State s 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 e xtremely 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 s ources 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

- yea rs 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

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- 2002

- 0058

- 1 879, 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

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- 0058

- 2970.1 Comment Excerpt Number: 15

Comment: Th e 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 dow n (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.

Re sponse: See the response to EPA

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- 0058

- 2782.1, Comment Excerpt Number 7.

Commenter Name: Jerry Osheka Commenter Affiliation: PPG Industries400 Document Control Number: EPA

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- 0058

- 2938.1 Comment Excerpt Number: 16

Comment: Annual Perfo rmance 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 an d 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 complianc e with the emission standards. Therefore, the frequency of stack testing should be reduced to once every 5 years.

Response: See the response to EPA

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- 2002

- 0058

- 1879, Comment Excerpt Number 3.

Commenter Name: Edward E. Quick Commenter Affiliatio n: Celanese International Corp Document Control Number: EPA

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- 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 ack nowledges 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 mo re 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, othe r 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 pe rmit 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

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- 1879, Comment Ex cerpt Number 3.401 Commenter Name: Steven G. Hanson Commenter Affiliation: Graphic Packaging International Document Control Number: EPA

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- 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 EP A

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- 2002

- 0058

- 1879, Comment Excerpt Number 3.

Commenter Name: Lee B. Zeugin Commenter Affiliation: Utility Air Regulatory Group Document Control Number: EPA

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- 2002

- 0058

- 2880.1 Comment Excerpt Number: 24

Comment: To address the possibility tha t 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 provide d 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 test ing. 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

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- 2002

- 0058

- 2782.1, Comment Excerpt Number 7.

Commenter Name: Barry Christensen Commenter Affiliation: Occidental Chemical Corp Document Control Number: EPA

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- 2002

- 0058

- 2848.1 Comment Excerpt Number: 25

Comment: Clarification is needed as to how tem porary tube blowing is factored into compliance tests for particulate matter. It is unclear to what extent these periods have been factored into the402 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 pe rforming units.

Commenter Name: Bill Wemhoff Commenter Affiliation: National Rural Electric Cooperative Association Document Control Number: EPA

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- 0058

- 2835.1 Comment Excerpt Number: 26

Comment: Generally supports EPA’s proposal to use period ic 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 c ontrol 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

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- 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.

Th at 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. EPA403 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 exte nsive 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

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- 0058

- 2782.1,Comment Excerpt Number 7. Also, see the response to EPA

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- 2002

- 0058

- 1879, Comment Excerpt Number 3.

Commenter Name: Jim Griffin Commenter Affiliation: American Chemistry Council Document Control Number: EPA

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- 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 s ection 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 emission s. 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.

Commen ter Name: Jim Griffin Commenter Affiliation: American Chemistry Council Document Control Number: EPA

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- 2792.1 Comment Excerpt Number: 198

Comment: Facilities Should Be Able To Test One Unit If It Is Representative Of Multiple Units At The F acility. 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 f acility 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 could404 "rotate" among the boilers in the grou p. This option would reduce the cost associated with emissions testing for facilities with many similar boilers.

Response: See response to EPA

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- 2002

- 0058

- 2632.1, Comment Excerpt Number 42.