AF&PA, AWC, BPA, CCUSA, CRA, ERC, NAM, NOPA, RMA, SOCMA, and TWC 

Petition for Administrative Reconsideration and for Amendment of the Boiler 

MACT, Boiler GACT, and CISWI Rules

Table of Contents

Executive Summary ........................................................................................................ 2

1. The Standards for Dioxin are Unlawful and Unachievable. .................................. 4

2. In the Final CISWI and Solid Waste Definition Rules, EPA Fundamentally and 

Improperly Revised the Definition of what Constitutes a “Contained Gaseous 

Material,” Resulting in the Potential for Many Boilers, Process Heaters, and Other 

Combustion Units, Including Combustion Devices Covered Under Other MACTs, 

to be Reclassified as CISWI Units Because of the Gases they Combust............. 7

3. We strongly support and want to retain the PM surrogate for Certain NonMercury Metal HAPs; We Believe the Final Industrial Boiler MACT Needs to Also 

Accommodate a Certain Class of Biomass Boilers............................................. 10

4. EPA improperly failed to Adopt a Total Select Metals (TSM) Alternative for 

Particulate Matter (PM) in Boiler MACT.............................................................. 13

5. The CO Emission Limits for Certain Biomass Boilers in Boiler MACT are 

Unachievable and Should be Reconsidered and Amended. .............................. 14

6. EPA’s New Source Limits for Boiler MACT are Unachievable for Many 

Subcategories..................................................................................................... 16

7. Revisions are Needed to the CISWI Floor Setting Process................................ 21

8. The CISWI Limits Do Not Consider Higher Emissions of CO and Other Pollutants 

During Periods Associated with Unit Start-Up and Shutdown When the Unit is 

Operating Under Non-Steady State Conditions.................................................. 26

9. The Limits in Boiler MACT for Oil Fired Units are Unachievable. ....................... 29

10. The Criteria for Qualifying as a Gas 1 Boiler/Process Heater in Boiler MACT 

Should Be Revised. ............................................................................................ 31

11. The Affirmative Defense for Malfunctions Is Unfounded And Is Not An 

Appropriate Substitute for An Alternative Standard Covering Periods Of 

Malfunction ......................................................................................................... 32

12. PM CEMS Should Not Be Required in Boiler MACT or CISWI........................... 33

13. We Agree that CO CEMS Should Not Be Required Under Boiler MACT or Boiler 

GACT, But Believe that the O2 Monitoring Requirements Should be ReEvaluated for Some Boilers. ............................................................................... 36

14. The Energy Assessment Should not be a Requirement in Boiler MACT or GACT 

and, at a Minimum, the Scope Should be Reconsidered.................................... 38

15. We Agree that Limited Use Units Should Have Their Own Subcategory and that 

Work Practices are Appropriate as MACT.......................................................... 38
Petition for Administrative Reconsideration

Page 2

16. We Agree that it is Appropriate to set GACT for Biomass-Fired and Oil-Fired 

Units at Area Sources......................................................................................... 39

17. We Agree that Synthetic Area Sources Subject to Boiler GACT Should not be 

Required to Obtain Title V Permits. .................................................................... 39

18. Fuel Switching Provisions for CISWI Units Should be Improved. ....................... 40

Appendix A. Errors in the Determination of RDLs to Set Boiler MACT and CISWI 

PCDD/F Limits...................................................................................................A-1

Appendix B. Additional CO Data Analyses .......................................................B-1

Executive Summary

The Petitioners submitted extensive and detailed comments on the proposed Boiler 

MACT, Boiler GACT, and CISWI rules. Our comments and our members’ comments 

represented a few of the thousands of comments EPA received on the proposed rules 

in August 2010. The volume of comments and the issues surrounding the development 

of the proposed rules necessitated several more months of careful consideration by 

EPA in development of the final rules. However, the court only allowed EPA a limited 

amount of time to consider all of the additional information and comments received 

following proposal. We understand EPA’s obligation to meet the schedule set out by 

the court for publication of the final rules and we acknowledge that there were several 

improvements between the proposed and final rules; however, we believe that there are 

still many improvements that need to be made to the final rules to make them 

achievable technically and economically. We would also like to note that although this 

petition covers only the Boiler MACT, Boiler GACT, and CISWI rules, we also have 

significant concerns with the final non-hazardous secondary materials definition rule

since it determines what units fall under CISWI as opposed to Boiler MACT, and many 

more fuel materials appear to be reclassified as solid wastes than originally expected. It 

is unclear if EPA fully considered the implications of these dramatic changes when it 

identified the best performing units for the MACT floor calculations for the various 

subcategories.

EPA has already indicated that it agrees a reconsideration is warranted for several 

issues related to the Boiler MACT, Boiler GACT, and CISWI rules, such as the 

additional subcategories established in Boiler MACT and CISWI rules, as well as the 

Gas 1 fuel specifications, carbon monoxide (CO) monitoring requirements, and 

dioxin/furan (D/F) requirements. We concur that these issues warrant reconsideration 

since the public was not given adequate notice-and-comment opportunity. We support 

the inclusion of new subcategories in the Boiler MACT and CISWI rules and have 

provided suggestions in this document for ways to improve the methods used to 

establish limits for these subcategories. We agree that a Gas 1 fuel specification is 

appropriate to allow gases other than natural gas and refinery gas to qualify for work 

practices, but the H2S specification needs to be adjusted. We also believe the Agency 

was justified in not requiring CO CEMS for all boilers over 100 MMBtu/hr but additional 

variability needs to be taken into account in setting CO limits, sources that already have 
Petition for Administrative Reconsideration

Page 3

CO CEMS must be considered when establishing compliance approaches, and the O2

monitoring requirements need reconsideration, as they were not included in the 

proposed rule.

We are most concerned about the establishment of dioxin/furan emission limits under 

the Boiler MACT and CISWI rules that relied on a small amount of data that are largely 

below detection limits. There is a great deal of measurement uncertainty associated 

with quantification of dioxin/furan emissions at the low levels seen from industrial 

boilers, process heaters, and energy recovery units. EPA has set these standards 

without being able to provide industry with an understanding of how to prevent or control 

dioxin/furan emissions from industrial boilers and process heaters and has not assigned 

any costs for meeting these standards. EPA should follow the approach taken in the 

recently proposed Utility Boiler MACT and set work practice standards instead of 

numerical emission limits for dioxin/furan. EPA has ample authority to prescribe a work 

practice standard instead of a numeric emissions limit. Section 112(h)(2)(B) authorizes 

EPA to establish work practice standards when “the application of measurement 

methodology to a particular class of sources is not practicable due to technological and 

economic limitations.” Such is the case for the proposed dioxin/furan standards – the 

proximity of the standard to the detection limit makes testing for compliance not 

technologically practicable, while the inability to accurately measure at the level of the 

proposed standard is economically impracticable because spending more money on the 

prescribed method will not resolve the inherent problem of setting the standard at the 

method detection limit. A reasonable work practice standard requiring good combustion 

practices is justified in this situation and would ensure that dioxin/furan emissions are 

minimized.

Also of high concern and great and perhaps unintended impact to the number of units 

affected by the CISWI rule is the removal of the definition of “contained gas” from the 

CISWI rule. This change was made between the proposed and final rules and was not 

justified or properly considered. The public had no opportunity to comment on the 

change, which has very broad implications, as described herein. Additionally, while we 

concur with EPA’s decision to subcategorize energy recovery units under the CISWI 

rule, we describe below the necessary revisions to the floor setting process and how 

startup and shutdown should be handled.

We continue to be concerned about the achievability of many of the new source limits, 

the solid fuel PM, CO, and dioxin/furan new source limits in particular. We believe that 

EPA needs to reconsider the methods and the amount of data used to set these limits to 

ensure energy flexibility and promote energy independence. The new source limits 

should not be so stringent as to discourage the use of renewable solid fuels. Biomass 

is a “clean” fuel in many of the same respects as the Gas 1 fuels. For example, a 

biomass-fired boiler typically will have far lower HCl and Hg emissions than a 

comparable, well-controlled coal-fired boiler. Perhaps more importantly, biomass-fired 

boilers produce no net CO2 emissions, which makes the combustion of biomass an 

important tool in managing and reducing the Nation’s carbon footprint. Similarly, 

biomass is an abundant, renewable domestically-produced fuel that can help reduce 

reliance on foreign sources of fossil fuel and, thus, improve the Nation’s energy security. 
Petition for Administrative Reconsideration

Page 4

Prescribing overly stringent HAP emissions limitations on biomass boilers will create a 

significant barrier to the continued expanded use of biomass fuels. 

We support the decision by EPA to retain the PM surrogate for certain metallic HAPs. 

The evidence is compelling that PM is an appropriate surrogate for non-volatile metal 

HAPs and a PM standard provides a practical known way of monitoring and controlling 

these emissions. However, concern remains that the emissions data on which the solid 

fuel subcategory PM limits are based are not representative of, and do not reasonably 

reflect the characteristics of, certain older and smaller biomass boilers. As a result, the 

PM standards severely disadvantage the facilities that operate these boilers and put 

them at risk of closure. We offer two options for reconsideration that could address 

these concerns while still maintaining the existing PM limit. First, Section 112(d)(4) 

authorizes EPA to set health-based emissions limitations (HBELs) when establishing 

standards for HAPs under § 112(d). Section 112(d)(4) is a powerful tool that enables 

EPA to match the stringency of a HAP emissions limitation to the level determined 

necessary to fully protect human health. As a result, the standard is no more stringent 

and no less stringent than needed to get the job done. Inclusion of a health-based 

emission limit in the Boiler MACT will ensure facilities are investing resources in 

emissions reductions where they have a public health impact. Second, EPA should 

consider creating a new subcategory that isolates these at-risk boilers factoring in their 

size, type and class in setting an alternative PM limit. Such an approach would not 

appreciably affect the existing standard. 

1. The Standards for Dioxin are Unlawful and Unachievable.

EPA Lacks the Legal Authority to Regulate D/F as a Category of Compounds

The final D/F standards are procedurally flawed. In the proposed rule, EPA explained 

that, for purposes of establishing the proposed emissions limitations, it “grouped the 

HAP into five categories” – including a category for dioxins/furans – on the grounds that 

“pollutants within each group have similar characteristics and can be controlled with the 

same techniques.” 75 Fed. Reg. 32018. EPA afforded no notice or opportunity for 

comment on its stated rationale for regulating D/F as a category of compounds, nor 

does the Clean Air Act provide for this approach. For both these reasons, the dioxin 

standards in the final rules are unlawful.

EPA explained that CO “has generally been used [in prior rules] as a surrogate for 

organic HAP,” but concluded for purposes of the Industrial Boiler MACT that D/F should 

be regulated separately “because, unlike other organic HAP, D/F can be formed outside 

the combustion unit.” Id. The proposed standards for D/F were expressed in terms of 

total “TEQ,” which is an approach that assigns a “toxicity equivalent” to D/F isomers 

using 2,3,7,8 TCDD as the toxicity baseline. See, e.g., id.at 32066 (Table 1, proposed

emissions limits for new or reconstructed boilers and process heaters). Compliance is 

determined by multiplying the measured amount of each isomer by its corresponding 

TEQ and then summing that value for all isomers.
Petition for Administrative Reconsideration

Page 5

Many commenters asserted that the proposal to regulate D/F as a category of 

compounds was beyond EPA’s authority because the § 112(b)(1) list of HAPs includes 

only two named D/F compounds – dibenzofuran and 2,3,7,8 tetrachlorodibenzo-pdioxin. In the final rule, EPA responded by asserting that, “While dibenzofuran and 

2,3,7,8 TCDD are two of the HAP listed in Section 112, all dioxin and furan compounds 

are considered to be POM and, as such, EPA has the authority to regulate these 

compounds under Section 112.” 76 Fed. Reg. 15640.

EPA provided no explanation in the proposed rule of its purported legal authority to 

regulate D/F as a class of compounds. The legal justification was provided for the first 

time in the preamble to the final rule. This justification is not a “logical outgrowth” of the 

proposed rule because commenters could not have reasonably predicted at the time of 

proposal that EPA might rely on its POM theory in justifying regulating D/F as a class of 

compounds in the final rule. Indeed, there are no comments on this point in the record 

because none of the commenters actually did anticipate that EPA would take this tack. 

This is an issue of central relevance to the outcome of the rule because, if EPA’s legal 

theory is ultimately determined (or proven) to be wrong, the categorical D/F standards 

will have to be rescinded and replaced with compound-specific limits or work practices.

Lack of notice and opportunity to comment aside, the substance of EPA’s stated 

rationale for regulating the entire category of D/F compounds is also contrary to law. As 

noted above, the fact that Congress specifically identified only two D/F compounds in 

the § 112(b)(1) list of HAPs provides an unambiguous signal that EPA may regulate 

only those two specific D/F compounds and not other isomers or closely related 

materials. Thus, upon reconsideration, EPA must propose to replace the D/F standards 

in the final Boiler MACT rule with work practice standards or establish emissions 

limitations only for dibenzofuran and 2,3,7,8 TCDD.

The Dioxin Standards Are Unachievable

In addition to the legal issues noted above, there are technical flaws in the final rule that 

render its D/F standards unachievable. EPA proposed emission limits for dioxin/furan 

for 9 subcategories of units based on fuel and design criteria. The limits were based on 

a very limited data set (1 to 2 units in each floor) and the majority of the data were 

detection level limited (i.e., very few dioxin/furan test results were above the method 

detection limit). Some of the data were of poor quality due to errors in transcription or 

calculation methodology. The proposed limits were so low as to be largely 

unachievable, none of the boilers setting the floors employed any dioxin/furan control 

measures, and there is no information to suggest there are control measures that can 

be reliably employed to further reduce these already low emissions. In the final rule, 

EPA has retained the dioxin/furan standards for 12 subcategories of units, recalculating 

the limits based on a procedure to adjust the data according to representative detection 

limits, or RDLs. Data corrections and floor calculation methodology adjustments have 

resulted in improvements in some dioxin/furan emission limits (e.g., existing oil unit limit 

of 4 ng/dscm), but the majority of the limits remain unachievable and are not justified. 

In the Boiler MACT regulatory impact analysis, EPA has not assigned any costs to 

compliance with the dioxin/furan limits:
Petition for Administrative Reconsideration

Page 6

The final rule requires all units that measure dioxin data below the method 

detection level to report that congener as zero. Based on the reported 

dioxin/furan data and associated detection levels available at the time of the final 

rule, most units will fall below the MACT floor levels if the non-detect congeners 

are treated as zero, For coal, 17 of the 27 tests would meet the existing limits, 17 

of the 22 tests for biomass would meet the existing limits, and all of the liquid and 

process gas tests would meet the existing limits. Given these results and the fact 

that some units are installing ACI for mercury control, which is expected to have 

a co-benefit of reducing dioxin/furan emissions, the cost analysis does not 

estimate any control costs for achieving the dioxin/furan emission limits.

4

 

Assuming compliance through reporting non-detect congeners as zero does not make 

sense and may not be consistent with existing reporting protocol. Assigning congeners 

as zero is only allowed by EPA procedures (Method 23, section 9.9) when determining 

total homologue groups, which uses a different analytical method than the isotope 

dilution method to identify 2,3,7,8 chlorine substituted isomers. In addition, some states 

do not allow reporting of non-detects as zero. EPA’s logic does not make sense 

because EPA’s baseline emission factors for many units without data are above the 

limits5, EPA projects only 11 units will install ACI, and EPA projects a dioxin/furan 

emission reduction of 23 g/yr across all fuels from implementation of the rule6. EPA 

cannot claim emissions reductions from a rule without associating some action on 

industry’s part to comply. EPA does not have sufficient data on dioxin/furan emissions 

from industrial boilers and process heaters to be able to delineate how compliance with 

the standards is to be achieved. If these concerns are not enough, boiler operators and 

equipment manufacturers have no clear understanding of the proper methods to reliably 

reduce D/F emissions to come into compliance with the standards EPA has set. 

In EPA’s recently proposed Utility MACT (76 Fed. Reg. 24976), no dioxin/furan 

standards are proposed for coal and oil-fired EGUs because the majority of the data are 

non-detect (ND). The levels of D/F reported by industrial boilers are very low, similar to 

utility boilers. Of the 333 test runs included in EPA’s emissions test database, 4.50% 

(15) are labeled as being below the detection limit (BDL) (i.e., all congeners reported as 

ND), 72.67% (242) are classified as detection level limited (DLL) (i.e., some of the 

congeners reported as ND), 21.92% (73) are labeled as above the detection limit (ADL)

 

4 ERG Memorandum, “Revised Methodology for Estimating Cost and Emissions 

Impacts for Industrial, Commercial, Institutional Boilers and Process Heaters National 

Emission Standards for Hazardous Air Pollutants – Major Source,” February 17, 2011.

5 ERG Memorandum, “Revised Development of Baseline Emission Factors for 

Boilers and Process Heaters at Commercial, Industrial, and Institutional Facilities,” 

January 2011.

6 US EPA, “Regulatory Impact Analysis: National Emission Standards for 

Hazardous Air Pollutants for Industrial, Commercial, and Institutional Boilers and 

Process Heaters,” February 2011.
Petition for Administrative Reconsideration

Page 7

(i.e., all congeners reported above detection levels). The D/F data submitted by 

sources in response to EPA’s Phase II Information Collection Request (ICR) reveals 

even further uncertainty in the data than meets the eye. D/F sampling and analytical 

methods offer unique challenges. Eastman’s data for Boiler 30 reveal a further 

understanding of this uncertainty (Eastman has submitted these data to EPA). Every 

congener in each test run was either reported as ND or reported as a value that was 

flagged with a “J” qualifier. The “J” qualifier indicates the analyte was quantified with a 

concentration below the reporting limit, defined as below the lowest point on the 

calibration curve. Some of the congeners were also labeled “EMPC” (estimated 

maximum possible concentration), indicating that a peak is detected but did not meet all 

of the method criteria. Both of these “flags” indicate that there is a high degree of 

uncertainty associated with D/F data at the low levels found in industrial boiler stack 

gas. This test report also reveals that some D/F congeners were detected in the field 

blank, indicating background levels of D/F which cast further doubt and uncertainty on

the reported analyte concentrations. An examination of one of the top performing coalfired units, the unit at Miller Coors in North Carolina, reveals a similar high level of 

uncertainty. In this test, of the total 51 reported congener values, 21 were reported as 

“not detected” but the other 30 values were all flagged with the “J” qualifier. Therefore, 

even the top performers in EPA’s dataset have results that have a high level of 

uncertainty. EPA is summing uncertainty upon uncertainty in each of the dioxin 

congeners to create an emission limit that cannot be technically justified. Test results 

with such uncertainty should not be used to set emission standards for entire source 

categories.

In setting the Boiler MACT and CISWI standards, EPA has stated that the emission limit 

should not be set below the capability of the applicable test method, which is defined as 

its limit of quantitation. Source testing professionals agree that this information is best 

obtained by conducting simultaneous emission tests with multiple sampling trains 

operated by different teams with analysis performed at different laboratories. However, 

in setting the PCDD/F standards, EPA has erroneously used the detection capabilities 

of best performing laboratories to determine method quantitation limits and has 

promulgated standards which are orders of magnitude below the quantitation limits of 

D/F in biomass boiler emissions. As demonstrated by the measurement issues noted; 

quantifying actual dioxin emission levels for the floor units is technologically 

impracticable and Clean Air Act Section 112(h)(1) supports establishing a work practice 

standard for D/F in the Boiler MACT, as was done in the recently proposed Utility 

MACT. At a minimum, EPA must reanalyze its data and set much higher D/F limits for 

both Boiler MACT and CISWI, since most of the measurements were well below the 

quantification limit of EPA Method 23 and there is significant uncertainty surrounding the 

measurements. Appendix A provides more detail on this topic.

2. In the Final CISWI and Solid Waste Definition Rules, EPA Fundamentally 

and Improperly Revised the Definition of what Constitutes a “Contained 

Gaseous Material,” Resulting in the Potential for Many Boilers, Process 

Heaters, and Other Combustion Units, Including Combustion Devices 
Petition for Administrative Reconsideration

Page 8

Covered Under Other MACTs, to be Reclassified as CISWI Units Because of 

the Gases they Combust.

On March 21, 2011, EPA published the final rule: Identification of Non-Hazardous 

Secondary Materials That Are Solid Wastes (76 Fed. Reg. 15456 (Mar. 21, 2011)) 

(NHSM Rule) and the final CISWI Rule. The NHSM Rule identifies non-hazardous 

secondary materials that are solid wastes when used as fuels or ingredients in 

combustion units. The final rules contain a significant change to EPA’s longstanding 

interpretation of the term “solid waste,” in that the Agency has announced that the term 

“contained gaseous material” should be construed for purposes of the NHSM and 

CISWI rules as including gases contained in pipes. In the past, EPA has not considered 

gases in pipelines to be “contained gaseous material.”7 However, in the response to 

comments for the NHSM Rule, EPA states: 

In the first place, we are unable to find any Agency reasoning supporting 

previous EPA interpretations that only gases in containers may be 

considered “contained.” Based on the facts of this case, EPA cannot see 

how gaseous secondary material that is generated in any particular 

system and is somehow sent to a gas-fired boiler, even through a pipeline, 

can be considered an “uncontained gas.” 

NHSM, Response to Comments, at 212. 

Similarly, in the CISWI Rule, EPA has deleted the definition of “contained gaseous 

material.” 40 CFR 60.2265; 76 Fed. Reg. 15761. That definition formerly read as 

follows: “Contained gaseous material means gases that are in a container when that 

container is combusted.” 

 

7

See, e.g., 47 Fed. Reg. 27520, 27530 (June 24, 1982) (“EPA agrees with 

commenters that fume incinerators are subject only to regulation under the Clean Air 

Act and does not intend that Parts 264 and 265 regulations apply to these facilities.”); 

RCRA/Superfund Hotline Monthly Summary, 9488.1986(03), available at RCRA Online 

(“[A] fume incinerator used only to destroy gaseous emissions from an industrial 

process is not subject to RCRA regulation since the fume input, being an uncontained 

gas, is not a solid waste....”); Memorandum from Matthew Straus, Chief, Waste 

Characterization Branch, to Clifford Ng, Engineer, EPA Region II (June 17, 1987) 

(“[M]ethanol-laden air from the drying and granulation step in a process, does not meet 

the definition of solid waste under RCRA because it is in vapor form and not confined in 

a container.”); 54 Fed. Reg. 50968, 50973 (1989) ([O]ur authority to identify or list a 

waste as hazardous under RCRA is limited to containerized or condensed gases.”); 56 

Fed. Reg. 7134, 7200 (Feb. 21, 1991) (Activated carbon air pollution control device is 

not RCRA regulated because the process gas “being treated is not a solid waste (it is 

an uncontained gas).”); 2000 CISWI Rule Response to Comments, at 15 (“Incinerators 

used as air pollution control devices and flares would not be covered by the CISWI 

standards and guidelines because they are not burning contained gases.”).
Petition for Administrative Reconsideration

Page 9

As a result of these two rules, gases in pipelines, ducts, and vents that are combusted 

must meet the standards promulgated under the CISWI Rule, unless the gases are 

combusted in air pollution control equipment associated with the CISWI unit itself. 

During the development of the 2000 CISWI rule, commenters asked that EPA expressly 

exempt from CISWI standards and guidelines any combustion device whose function is 

pollution control mandated by another federal or state requirement, including flares 

burning surplus, by-product, blast furnace gas. EPA responded by saying: 

Incinerators used as air pollution control devices and flares would not be 

covered by CISWI standards and guidelines because they are not burning 

contained gases. The definition of solid waste includes only “... solid, 

liquid, semisolid, or contained gaseous materials...” A definition of 

“contained gaseous material” has been added to the CISWI standards and 

guidelines to clarify that only gases that are in a container when that 

container is combusted are covered by CISWI standards and guidelines. 

Commercial and Industrial Solid Waste Incineration Units: Background Information 

Document for New Source Performance Standards and Guidelines, Public Comments 

and Responses (EPA-453/R-00-008) (Nov. 2000), at 15 (2000 CISWI Rule Response to 

Comments). 

As noted above, the definition of contained gaseous material has been deleted from the 

CISWI Rule and, in the Response to Comments on the NHSM Rule EPA has 

reinterpreted the definition of “contained gaseous material.” As a result, flares and other 

air pollution control equipment (such as regenerative thermal oxidizers (RTOs) and 

fume incinerators) not directly associated with a CISWI unit could now be considered 

solid waste incinerators subject to CISWI standards. In addition, industry boilers, 

furnaces, and kilns that are used to burn process gases could be considered CISWI 

units. This modification is so impactful that essentially any process emissions being 

controlled by a combustion device would now subject that combustion device to the 

CISWI standards.

EPA’s new interpretation of the term “contained gaseous material” has changed without 

notice or an opportunity for comment. At no stage of the NHSM rulemaking process did 

EPA provide any notice that it intended to change its interpretation of the term 

“contained gaseous material.” Neither the advanced notice of proposed rulemaking (74 

Fed. Reg. 41 (Jan. 2, 2009)) nor the notice of proposed rulemaking (75 Fed. Reg. 

31844 (June 4, 2010), nor the final NHSM Rule (76 Fed. Reg. 15456 (Mar. 21, 2011)) 

includes any discussion of this term. EPA did receive a comment on the proposed rule 

from the American Chemistry Council and a comment from the American Petroleum 

Institute, asking that EPA clarify that contained gaseous material includes only gas in a 

container. These comments assumed that is what EPA intended and merely sought 

clarifying language. 

Similarly, the proposed CISWI rule (75 Fed. Reg. 31938 (June 4, 2010)) provided no 

notice that EPA intended to change its interpretation of the term “contained gaseous 

material.” EPA did not even propose to delete the definition of that term from the 2000 
Petition for Administrative Reconsideration

Page 10

CISWI rule. 75 Fed. Reg. at 31983. However, this definition is deleted in the final

CISWI Rule with no discussion of this change in either the preamble or the response to 

comments document. 76 Fed. Reg. at 15761. 

The only place where EPA indicates that it has changed its interpretation of “contained 

gaseous material” is in the response to comments on the NHSM Rule, as noted above. 

This language belies EPA’s promises of transparency in rulemaking and does not 

provide adequate notice to the regulated community that a change in interpretation has 

taken place, much less an opportunity for comment.

Additionally, this issue is of central relevance to the CISWI Rule, as EPA’s new 

interpretation of the term “contained gaseous material” would substantially expand the 

universe of combustion devices that would be considered solid waste incinerators 

subject to the CISWI Rule. Thus, EPA must include this issue in the CISWI 

reconsideration proceeding. In our view, there is no basis or justification under the law 

for EPA to change its longstanding interpretation that the term “contained gaseous 

material” includes only gases in a container. We do not believe, based on our 

conversations with EPA since the promulgation of these rules, that the Agency intended 

to broadly expand the universe of affected facilities in this manner. EPA should reaffirm 

this longstanding position through reconsideration.

3. We strongly support and want to retain the PM surrogate for Certain NonMercury Metal HAPs; We Believe the Final Industrial Boiler MACT Needs to 

Also Accommodate a Certain Class of Biomass Boilers

We support the decision by EPA to retain the PM surrogate for certain metallic HAPs. 

The evidence is compelling that PM is an appropriate surrogate for non-volatile metal 

HAPs and a PM standard provides a practical known way of monitoring and controlling 

these emissions. We have member companies who strongly support the continued 

ability to use the PM surrogate. However, concern remains that the emissions data on 

which the solid fuel subcategory PM limits are based are not fully representative of, and 

do not reasonably reflect the characteristics of, certain older and smaller biomass 

boilers. As a result, the PM standards severely disadvantage the facilities that operate 

these boilers and put them at risk of closure.

We offer two options for reconsideration that could address these concerns while still 

maintaining the existing PM limit and the PM surrogate. The first is a health-based 

approach and the second requires the creation of a new subcategory. Both would retain 

the current PM limit while working to create flexibility for a class of boilers that are 

sufficiently distinct that an alternative approach is justified and required. A health-based 

approach for acid gases should be considered separately from one for manganese and 

the metallic HAPs.

Health-Based Approach 

In the preamble to the proposed Industrial Boiler MACT, EPA acknowledged its 

authority under CAA § 112(d)(4) to establish health-based emissions limitations 
Petition for Administrative Reconsideration

Page 11

(“HBELs”) for threshold pollutants in lieu of a MACT emissions limitations. However, the 

Agency proposed not to establish any health-based emissions limitations “[g]iven the 

limitations of the currently available information (i.e., the HAP mix where boilers are 

located, and the cumulative health impacts from co-located sources), the environmental 

effects of HCl, and the significant co-benefits of setting a conventional MACT standard 

for HCl.”8 Nevertheless, EPA asked for comment on a wide range of issues related to 

the justification for setting health-based emissions limitations and the method by which 

they should be set.

AF&PA and petitioners submitted comments explaining why EPA’s legal and factual 

concerns about setting HBELs are unfounded and presented data and information that 

would support HBELs for HAP acid gases and manganese. In particular, we pointed 

out that EPA had failed to provide an explanation as to why it adopted HBELs in the 

2004 Industrial Boiler MACT standard, but reversed course in the 2010 proposed rule. 

We further explained that EPA had failed to provide a rational basis for rejecting HBELs 

when, by definition, an HBEL must be set at a level that protects public health with an 

ample margin of safety. AF&PA also presented detailed information demonstrating that 

HAP acid gases and manganese are threshold pollutants and explaining how HBELs 

could be established in a prudent, protective, and practicable manner. Lastly, AF&PA 

explained how an HBEL for manganese could be implemented in conjunction with a 

total select metals standard for other non-volatile HAP metals such that the suite of HAP 

metals limits would be more closely tailored than an aggregate PM surrogate emissions 

limit alone.9

In the final rule, “EPA decided not to adopt an emissions standard based on its authority 

under section 112(d)(4).”10 The Agency asserted that the use of § 112(d)(4) is 

discretionary and “it is appropriate for EPA to consider relevant factors when deciding 

whether to exercise its discretion under section 112(d)(4).”11 In support of its decision 

not to adopt HBELs, EPA cited: (1) its ongoing concern about potential cumulative 

effects on health and the environment; (2) its belief that the CAA forbids EPA from using 

HBELs to exclude sources from regulation (which EPA said some commenters had 

suggested); (3) the “collateral benefits of reducing non-HAP air emissions; and (4) the 

fact that, for manganese in particular, it did not address or solicit comment on a possible 

manganese HBEL in the proposed rule.12

Reconsideration of EPA’s final decision not to set HBELs is needed and particularly 

justified given the Agency’s failure to acknowledge and respond to the detailed 

comments explaining why HBELs are needed and how they are justified under the facts 

and the law. This is an issue of central relevance to the Rule because the Agency’s 

 

8

75 Fed. Reg. at 32032.

9 See for example AF&PA Comments at 141-171.

10 76 Fed. Reg. at 15643.

11 Id.

12 Id. at 15643-15644.
Petition for Administrative Reconsideration

Page 12

failure to set HBELs has caused the acid gas and non-volatile metals standards in the 

final rule to be far more stringent than needed to protect health and the environment 

with an ample margin of safety, which will needlessly impose billions of dollars of 

excess costs on affected sources.

EPA failed, for example, to explain why HBELs could not be established in a manner 

that allows for consideration of site-specific characteristics – as petitions suggested in 

comments and as EPA adopted in the 2004 Industrial Boiler MACT. Similarly, EPA 

apparently ignored AF&PA and other commenters who agreed that HBELs must be 

emissions standards and that § 112(d)(4) should not be used as a mechanism to 

excuse certain affected sources from regulation. EPA also failed to explain why 

consideration of the co-benefits of non-HAP emissions reductions is a rational basis for 

not setting HBELs in the current rule when it clearly was not considered a barrier to 

setting HBELs in the 2004 rule. These and other similar flaws and gaps in the Agency’s

reasoning demand reconsideration of the decision not to set HBELs.

In conducting reconsideration on this issue, petitioners request that EPA consider a full 

range of possibilities, including establishment of specific subcategories where HBELs 

would apply, in order to give the most consideration to cost and regulatory flexibility 

issues. The reconsideration proposal should fully explore a possible HBEL for HAP 

acid gases – HAPs for which a particularly compelling case can be made that HBELs 

are appropriate and necessary. AF&PA submitted extensive scientific information in its 

prior comments demonstrating that HCl, HF, chlorine, and HCN are threshold pollutants. 

If EPA has any lingering concern on this point, it should identify the potential issues and 

ask for specific comments. In addition, the purported problems with “co-location” are 

easily resolved, in the first instance because EPA has ample authority to focus its risk 

assessment only on industrial boilers and, in the second instance, because a standard 

that allows for consideration of site-specific characteristics will prevent EPA from having 

to set a least-common-denominator standard keyed to hypothetical worst case 

conditions. The “co-benefits” issue also should be robustly assessed, particularly in 

light of the fact that a § 112 standard is wholly unsuited to effectively addressing criteria 

pollutant issues to which a substantial portion of the CAA is specifically dedicated to 

resolving.

The possibility of a manganese HBEL also should be fully explored. Perhaps the more 

important issue is how such an HBEL would be implemented in practice. It goes without 

saying that a manganese HBEL provides no meaningful relief if affected sources are 

also required to comply with a PM limit (which is an appropriate surrogate for all nonmercury HAP metals, including manganese). To solve this problem, AF&PA and others

argued in their comments that a manganese HBEL should be implemented in 

conjunction with an alternative “total select metals” (“TSM”) standard (see additional 

comments in Section 4 below) to ensure that the full range of non-volatile HAP metals is 

appropriately addressed. A manganese HBEL appropriately set and combined with a 

TSM alternative would provide economic relief for many rurally-located small wood-fired 

boilers where manganese is the primary HAP metal and there is no health impact to the 

surrounding location. Installation of sophisticated PM controls on these boilers will not 
Petition for Administrative Reconsideration

Page 13

be economically feasible for some companies, due to economic conditions and small 

operating margins, nor will they provide any additional environmental benefit where a 

HBEL is justified. Such approaches should be considered in the reconsideration 

proceeding.

New Subcategory for Certain Biomass Boilers 

As an alternative to the manganese HBEL and TSM limit, EPA should consider creating 

a new subcategory for smaller and older biomass boilers factoring in their size, type and 

class in setting an alternative PM limit. Subcategorizing these boilers would not 

appreciably affect the existing standard. Some biomass boilers especially those at wood 

product facilities operate multi-clones to control particulates. Multi-clones cannot meet 

the new PM limits and owners of boilers with multi-clones would face significant 

expenses for installing ESPs or fabric filters to meet the 0.039 lb/MM Btu limit.

Given the barely recovering economy and dim prospects for a housing recovery any 

time soon, industries that are dependent on the home building market can ill afford 

expenditures that harm their competitiveness. For mills with limited or no profits for the 

foreseeable future, investing $5 to $15 million in new particulate controls will put these 

facilities at risk of closure with a resulting loss of the jobs they support in their 

communities and up and down the value chain. These units are largely located in rural 

areas far away from PM non-attainment areas. Their emissions are small – on the order 

of 100 tons per year – so their emissions characteristics and potential impacts on health 

and the environment are markedly different from the biomass boiler population at large. 

Incremental PM reductions from moving from multi-clones to ESPs or fabric filters on 

these units will be minimal.

Therefore, there is ample evidence that the generally applicable PM standard is not 

appropriate or suitable for this class of boilers. In addition, this class of boilers is easily 

distinguishable from the general population of biomass boilers, which provides a rational 

basis for a subcategory to accommodate these boilers. Lastly, setting a separate PM 

standard for these boilers would not undermine the generally acceptable PM standard. 

For these reasons, EPA should create a subcategory for these boilers and establish a 

subcategory-specific PM limit.

4. EPA improperly failed to Adopt a Total Select Metals (TSM) Alternative for 

Particulate Matter (PM) in Boiler MACT.

In the proposed Boiler MACT, EPA proposed PM limits for all subcategories (except 

Gas 1) as a surrogate for non-mercury HAP metals. Although the original 2004 Boiler 

MACT had provided an alternative TSM standard, the proposed rule did not contain a 

TSM option and the final rule also does not contain a TSM compliance option. EPA 

recently signed the proposed Utility MACT rule, which provides a choice between 

complying with a PM or a TSM standard for coal-fired EGUs. The Utility MACT 

preamble does not explicitly state why TSM is provided as a compliance option for coal 

EGUs, but does state that PM is an appropriate surrogate when PM controls are used to

reduce emissions of metals. There are some industrial boilers (e.g., most liquid and 
Petition for Administrative Reconsideration

Page 14

gas-fired units) that do not have any PM controls and there are some industrial boilers 

(e.g., some biomass units) that do not have sophisticated PM controls, but have low 

metals emissions. 

We understand and agree with EPA’s approach to using particulate matter as a 

surrogate for non-mercury metallic HAP since metals are a component of particulate 

matter and testing for PM is simpler than testing for total metals. We do not wish to 

eliminate the use of PM as a compliance option. However, to enhance flexibility and 

cost-effectiveness in the proposed rule, we believe that EPA must also include a TSM 

emission limitation as an additional compliance option, allowing either fuel analysis or 

metals stack testing at the same frequency as the PM stack testing requirements for 

ongoing compliance. This approach will likely reduce the cost of the rule, allowing 

sources to comply using fuel analysis instead of annual or triennial stack testing and to 

design emissions reduction strategies around HAP metals instead of PM for certain 

categories of boilers where the addition of additional PM controls does not add to the 

health benefits of just controlling metal HAPs.

As noted above, EPA also should adopt, in conjunction with a manganese HBEL, an 

alternative TSM standard that does not include manganese. This option will be of 

particular importance to smaller biomass boilers to add flexibility and offer a lower cost 

compliance alternative that will still ensure protection of public health. 

5. The CO Emission Limits for Certain Biomass Boilers in Boiler MACT are 

Unachievable and Should be Reconsidered and Amended.

In the proposed Boiler MACT, EPA included CO emission limits based on boiler design 

for 9 subcategories of units. Boilers with a heat input of 100 MMBtu/hr and greater were 

required to install CO CEMS and comply with these emission limits on a 30-day rolling 

average basis. EPA used only 3-run stack test data to set the proposed limits, and did 

not properly consider variability. In using this procedure, EPA did not consider the 

variability of CO emissions with fuel and load. Facilities are typically required to conduct 

stack tests at 90 percent of full load or more and during normal operating conditions, so 

a CO stack test is going to represent the best operation of any boiler, not emissions 

over all operating conditions. EPA acknowledged this fact in the preamble at 75 Fed. 

Reg. 32021: “We believe that single short term stack test data (typically a few hours) 

are probably not indicative of long term emissions performance, and so are not the best 

indicators of performance over time.” AF&PA also provided graphical representations in 

its comments to demonstrate the variability of CO emissions for several boilers, and 

suggested that EPA analyze additional CO CEMS data to further investigate variability, 

rather than rely solely on stack test data.

In the final rule, EPA established CO emission limits based on boiler design for 11 

subcategories. EPA still used only 3-run stack tests to set the limits, but instead of 

requiring CO CEMS, the final rule requires an annual stack test and continuous O2

monitoring as an indicator of good combustion. EPA also adjusted the statistical 

method to calculate the MACT floor by using the 99.9 upper prediction limit (UPL) 

instead of the 99 UPL. In response to comments received on the measurement 
Petition for Administrative Reconsideration

Page 15

capability of EPA Method 10 for CO, EPA adjusted any measured CO data below a 

calculated method detection level, which resulted in some higher numbers being used in 

floor calculations, but also resulted in lower variability (especially for new source floors), 

since the same number was utilized in all 3 runs for calculation of the UPL. EPA also 

promulgated requirements for work practice standards during startup and shutdown 

(however, 63.7500 states that operating parameter limits apply at all times, so that 

would not excuse a source from meeting the established O2 parameter limit during 

startup and shutdown).

The CO emission limits must be reconsidered because the petitioners could not 

reasonably discern at the time of proposal the way in which EPA would formulate the 

final standards and, therefore, were deprived of the opportunity to submit meaningful 

comments on this key issue. For example, EPA created two new source categories, 

changed the statistical method used to analyze the emissions data, adopted a new 

approach to addressing test results below the method detection limit, created new work 

practices for startup and shutdown, and imposed completely new compliance methods. 

These issues are of central relevance to the final rule because they form a substantial 

part of the basis for the final CO emission limits, which are critically important parts of 

the rule.

Several commenters submitted continuous emissions monitoring data with their 

comments on the proposed rule that demonstrated CO emissions are highly variable –

which only stands to reason given that most industrial boilers are load-following units 

where the firing rate frequently changes based on changes in power or steam demand. 

We continue to believe that EPA has not gathered enough data on the variability of CO 

emissions from boilers in each subcategory and EPA did not sufficiently address our 

comments related to the variability of CO emissions. During the reconsideration 

proceeding, EPA will have the opportunity to solicit additional information from our 

members and other affected industry groups, which even more clearly will demonstrate 

the variable nature of CO emissions. 

Based on conversations with boiler and burner vendors, there are certain boiler and 

burner designs that cannot achieve the CO emission limits with a simple tune-up, 

especially in cases where a low NOx limit must simultaneously be achieved or where 

biomass is being burned with coal. AF&PA has heard from some of its members that 

biomass stoker boilers that already have recently modified over-fire air (OFA) systems 

cannot consistently achieve 490 ppm CO as a short-term standard, especially spreaderstoker boilers of older design. In addition, other companies have stated that in order to 

make combustion modifications to comply with the CO limits (and hopefully the 

dioxin/furan limits), they will have to install additional NOx control to prevent 

exceedances of their NOx limits as a result of compliance with the low CO limits. This 

of course will only come with a fuel/power efficiency cost, resulting in additional GHG 

emissions.

In addition, there remain situations where an evaluation of CO variability over all fuel 

and load conditions needs to be taken into account. In the final rule, EPA’s revised floor 
Petition for Administrative Reconsideration

Page 16

methodology did not take into account the fact that some units already have CO CEMS 

installed as required by their air permit (e.g., as BACT monitoring). Although it may 

have been EPA’s intent to establish a CO limit that a source would meet by performing 

an annual 3-hour stack test at full load, sources that already have CO CEMS will have 

to meet the limit on a continuous 3-hour average basis. Based on our analysis of CO 

CEMS data from some of the top performing units, there will be many periods where 

this is not feasible (see Appendix B). EPA should request additional CO data from the 

top performers, especially where CO CEMS data are available, and should determine 

an alternate form of the CO standard for each subcategory, based on use of CO CEMS 

and a 30- to 60-day averaging period. 

Finally, we continue to have concerns about data quality and representativeness of floor 

units. For example, the MNWeyerhaeuserIrontonEU 001 - 4 Cell Furnace, ranked 12 of 

12 in the Biomass Stoker CO floor, is actually a fuel cell, and not a stoker13. We also 

believe that the MNAndersonCorpBayport Boiler Nos. 11 and 12 are biomass 

suspension burners, not biomass stoker units. The INConsolidatedGrainandBarge

boilers may have been burning >10% TDF during the CO stack test, so should not be in 

the biomass floor. In addition, the MILPCSagola TOH-Wood unit is designated as the 

top performing biomass stoker for CO but is an old Geka burner design and is typically 

only operated at 60 percent load. This unit cannot be operated at full load because it 

exceeds State permitted CO limits. When this unit is operated at full load, it is 

supplemented with natural gas. This unit will not represent the design/operation of any 

future new biomass stokers. We have also heard from vendors that they cannot 

guarantee the new source coal and liquid CO limits. EPA should review the units in 

each floor to ensure that they are properly categorized, that units setting the new source 

floors are representative of future new boilers, and that there are adequate data to 

incorporate variability into the floor-setting process.

6. EPA’s New Source Limits for Boiler MACT are Unachievable for Many 

Subcategories.

In the proposed Boiler MACT, EPA included new source emission limits based on boiler 

design for 9 subcategories of units. Data were reviewed for boilers burning at least 

10 percent of the fuel represented by each subcategory, and the lowest stack test 

average was used to rank boilers by emission level. The new source emission limits 

are based on the 99 percent upper prediction limit (UPL) of the emission test data 

available for the unit with the lowest test average in each subcategory. In addition, the 

new source limits were set on a pollutant-by-pollutant basis, so they do not represent 

the actual overall performance of any one boiler or process heater. Capabilities of test 

methods and validity of submitted data were not considered, so some of the new source 

limits were below the practical limits of detection of EPA test methods. Fuel variability 

 

13 Weyerhaeuser Company on May 2, 2011, submitted information and a revised 

ICR Phase I survey to EPA to assist in correcting the misplacement of this unit in the 

stoker subcategory.
Petition for Administrative Reconsideration

Page 17

factors were not considered for all of the sources. Due to these factors, many of the 

proposed new source limits were so low that manufacturers were not willing to 

guarantee the emission levels for new boilers due to the limitations of technology and 

measurement techniques.

In the final rule, EPA established new source emission limits based on boiler design for 

11 subcategories. In response to comments received regarding representativeness of 

new source boilers with respect to the particular fuels burned, EPA attempted to pick 

the top source burning a representative fuel (e.g., clean biomass instead of deinking 

residuals, fuel oil instead of liquid process anhydrides waste) and burning 100 percent 

of the fuel represented by the subcategory. However, EPA continued to use a pollutantby-pollutant approach instead of a source-based approach, which results in only 2 

boilers in the entire database (one burning liquid and one burning 70% natural gas with 

30% biomass) being able to meet the new source limits. The new source limits are 

orders of magnitude below current NSPS and typical BACT requirements.

EPA also did not evaluate the stack test data used to set the new source limits to 

determine if emissions were above method detection levels (e.g., whether enough 

particulate was collected on the filter during a Method 5 stack test to ensure a reliable 

result, or whether the dioxin/furan test results actually detected any emissions of 

dioxin/furan). EPA should not set new source limits based on data that are below the 

measurement capabilities of the analytical and stack test methods. For example, 

examination of the data used to set the new source solid fuel PM limit 

(IAArchersDanielsMidlandDesMoines Asea Boiler #1) indicates that one stack test 

reported PM as below the detection limit and the second available test report indicated 

that only about 1.5 mg were caught on the filter. Published studies indicate that the 

practical quantitation limit of Method 5 is 3 to 6 mg, and a 1996 EPA-funded study 

indicated that the minimum PM catch for ±10 percent accuracy of Method 5 is 7.2 mg14. 

EPA should not use these data to set the new source standard, as the data are below 

the detection capabilities of the method. Instead, EPA simply replaced the three runs 

reported as below the detection limit with 0.0002 lb/MMBtu, which eliminates any 

variability and still represents a questionable result. Examination of the unit ranked 

number 2 in the solid fuel PM floor (IAMonsantoMuscatine Boiler #8) indicates the new 

source limit would be an order of magnitude higher if all data from this unit were used, 

as there are 18 test runs available from this unit that show emissions variability.

NCASI15 examined the ability of testing companies to measure PM emissions from 

sources to demonstrate compliance with the promulgated MACT standards for several 

 

14 “Minimum Detection Limit for Method 5,” R. Shigehara, Entropy Incorporated, 

EPA Contract No. 68-D2-0163, Work Assignment 3-06, September 30, 1996.

15 The National Council for Air and Stream Improvement (NCASI) is an 

independent, non-profit research institute that focuses on environmental topics of 

interest to the forest products industry.
Petition for Administrative Reconsideration

Page 18

source categories as shown in Table 1. The table shows the amount of PM that would 

be collected in a Method 5 train when tests are conducted on existing and new boilers 

operating at the promulgated PM emission standards and typical levels of oxygen 

observed during normal operation.

Table 1. PM Mass Expected To Be Collected During Performance Tests of Boilers

Source

Emission 

Standard, 

lb/MMBtu

Sample 

Volume, scf

Typical Stack 

Percent O2

Method 5 PM 

Mass, mg

Biomass, New 0.0011 90 10.0 2.5

Coal, New 0.0011 90 8.0 2.8

Oil, New 0.0013 90 6.0 4.1

Gas 2, New 0.0067 90 6.0 22.3

Biomass, Existing 0.039 30 10.0 29.4

Coal, Existing 0.039 30 8.0 33.4

Oil, Existing 0.0075 30 6.0 7.9

Gas 2, Existing 0.043 30 6.0 47.7

F factors used (dscf @ 0% O2/MMBtu) - biomass - 9400; Coal - 9820; Oil - 9220; gas – 8740 

As seen in Table 1, the mass of PM collected during performance test runs for boilers 

ranged from 2.5 to 47.7 mg. However, as pointed out in NCASI’s extensive comments 

on the boiler MACT proposal (U.S. EPA Docket EPA-HQ-OAR-2002-0058), the 

quantitation limit of EPA Method 5, based on analysis of simultaneous multi-lab 

Method 5 test data, is expected to be between 6-8 mg. Thus, the PM mass collected in 

three of the above eight cases (all new) would be well below the quantitation limit of the 

test method. Since sources typically design and operate their boilers at levels much 

lower than the emission standards to ensure compliance, this problem is further 

exacerbated. EPA should raise the emission standards to levels such that source 

operators can conduct tests and demonstrate compliance with the applicable standard.

EPA also did not provide enough consideration for variability of emissions, as many of 

the new source limits are set using one 3-run stack test. EPA could further consider 

variability by using the UL instead of the UPL statistical calculation and using a 99.9 

percent confidence level instead of a 99 percent confidence level, since sources will be 

required to meet the new source limits at all times. In addition, fuel variability data 

should be collected for all units setting new source floors and factored into the 

calculated emission limits. Industrial boilers operate over a variety of conditions and fire 

a variety of fuels, so adequate consideration of variability is important in setting 

achievable emission limits.

EPA must amend the rule limits so that equipment vendors are able to guarantee 

boilers and process heaters can achieve the new source limits. Table 2 summarizes 
Petition for Administrative Reconsideration

Page 19

the new source limits that we believe are the most problematic from the standpoint of 

achievability.

Table 2. Problematic New Source Limits

Subcategory and 

Pollutant

Proposed New 

Source Limit

Finalized New 

Source Limit

Notes

All D/F limits See overarching discussion on D/F limits in Item 1.

Solid Fuel PM 0.008 lb/MMBtu 

biomass

0.001 lb/MMBtu 

coal

0.0011 lb/MMBtu Stretching the measurement 

capability of Method 5; should 

not use stack tests that did not 

collect adequate PM on filter. 

Vendors are hesitant to 

guarantee this performance 

level. Will also be very difficult 

to calibrate/ certify PM CEMS 

– cannot vary emissions 

enough with a fabric filter and 

at these low levels to develop 

calibration curve. PM CEMS 

will not be able to meet current 

performance specification and 

requirement to collect 4 data 

points per hour at this low

level. 

Liquid CO 1 ppm@3% O2 3 ppm@3% O2 Vendors cannot provide 

guarantees for new units at 

this level. This is based on a 

gas-fired unit burning liquid 

periodically, and is a 3-run 

stack test, where EPA 

assigned all 3 runs a value of 

3 ppm (no variability) due to 

Method 10 accuracy. CO 

limits should not be any lower 

than 30 ppm based on 3x wet 

method accuracy criteria and 

CO vs. NOx issue (operating 

conditions that result in lower 

CO result in higher NOx). 
Petition for Administrative Reconsideration

Page 20

Subcategory and 

Pollutant

Proposed New 

Source Limit

Finalized New 

Source Limit

Notes

Biomass Stoker CO 560 ppm @3% O2 160 ppm @3% O2 Will not be able to burn many 

types of biomass (e.g., green 

wood) and achieve this level; 

vendors will only guarantee 

this level on dry biomass. Unit 

setting this limit is a wood 

products unit using outdated 

design that would not 

represent a new unit; unit also 

currently only operates at 60% 

of load. Additionally, the 

methodology used does not 

account for any CO variability. 

Coal PC/stoker/FB 

CO

90/7/30 ppm 

@3% O2

12/6/18 ppm @3% 

O2

Boiler vendors will not 

guarantee these levels. 

Additionally, the methodology 

used does not account for any 

CO variability. CO limits 

should not be any lower than 

30 ppm based on 3x wet 

method accuracy criteria and 

CO vs. NOx issue. 

Gas 2 CO 1 ppm @3% O2 3 ppm @3% O2 Vendors cannot provide 

guarantees for new units at 

this level. Additionally, the 

methodology used does not 

account for any CO variability. 

CO limits should not be any 

lower than 30 ppm based on 

3x wet method accuracy 

criteria and CO vs. NOx issue. 

Although EPA states that forcing fuel switching is not an appropriate control technology 

for this rule, these new source limits will in many cases force facilities to install new 

natural gas boilers instead of new biomass boilers. These new source limits will 

discourage facilities from replacing older solid fuel boilers with newer more efficient solid 

fuel boilers because they cannot build a new solid fuel boiler that meets the new source 

limits. 

EPA should reconsider the new source limits because the promulgated limits are based 

on flawed and unreasonably limited data and analyses, resulting in standards that are 

unrealistic and unattainable in most cases. EPA currently lacks the available data to 

truly account for variability and should review the underlying data to ensure that the 

suite of limits actually represents what a new boiler will be able to reliably achieve and 

does not provide a disincentive to new construction of solid and liquid fuel boilers in the 

future. EPA is encouraged to take the time it needs during the reconsideration period to 
Petition for Administrative Reconsideration

Page 21

request additional data from top performers and to review test data to ensure results 

below the limits of detection are not being used to set standards.

7. Revisions are Needed to the CISWI Floor Setting Process.

Section 129 of the Clean Air Act requires new and existing unit MACT standards to be 

based on “maximum degree of reduction in emissions” considering cost, and non-air 

health and environment impacts and energy requirements. It also requires minimum 

standards that are at least as stringent as the emissions limitations achieved by best 

performing unit(s) in a category, commonly referred to as “MACT floor limits.” In its 

CISWI rule proposal, EPA used a step-by-step statistically-based methodology to 

establish MACT floor limits for both new and existing units in each of four CISWI 

categories. Methodology steps included ranking units based on average performance 

as determined from EPA’s emissions database, selecting best performing unit(s), 

pooling test run data for the selected unit(s), characterizing the data as normally or lognormally distributed, and calculating an upper limit, all on a pollutant-by-pollutant basis. 

Commenters stated that the proposed methodology was flawed, especially in light of 

EPA’s very limited database developed through its Information Collection Request, and 

that it resulted in overly stringent standards. This stringency was evidenced by the fact 

that in each and every case, over 100 in all, EPA’s floor limit (the minimum standard) 

ultimately became the final standard despite EPA’s detailed assessment of beyond-thefloor options. Of central relevance was whether the methodology properly accounted for 

the full range of emissions variability. Commenters offered many changes and 

corrections to the methodology and its implementation and encouraged EPA to ensure 

its floor limits reflect previously achieved standards. 

In the final rule EPA used the same basic approach and steps in setting the MACT 

floors as in the proposal, but made two changes – 1) pooled data were judged lognormally distributed unless conclusively demonstrated otherwise, and 2) units with more 

data were adjusted to weight their influence on the pooled data calculations. EPA also 

employed its proposed alternate case upper predictive limit (UPL) instead of the base 

case upper limit (UL) to calculate the floors. 

We believe that EPA’s revised methodology is still flawed. When coupled with its very 

limited database, typically a single 3-run test per pollutant for each CISWI unit, EPA’s 

rigid statistical approach has resulted in inconsistent, sometimes irrational, and 

economically challenging if not unachievable emission standards. EPA has a 

responsibility to obtain emissions data that represent the actual range and variability of 

operating conditions. These standards also encourage practices counter to EPA’s own 

solid waste management and energy policies. For example:

Existing biomass power plants combusting clean forest-derived biomass and 

subject to Boiler MACT rules must meet a hydrogen chloride emission limit of 

0.035 lb/MMBTU, equivalent to about 27 ppmdv716. Add even small amounts of 

 

16 Parts per million dry volume corrected to 7 percent oxygen.
Petition for Administrative Reconsideration

Page 22

biomass of a type that EPA has now deemed “solid waste”, say construction or 

demolition wood or orchard stumps, to the fuel mix and the boiler becomes 

subject to CISWI Energy Recovery Unit (ERU) rules where the limit drops to 0.45 

ppmdv7, 60 times more stringent. Similarly, the CISWI mercury limit is sixteen 

times more stringent. On the other hand, the CISWI PM limit is 250 mg/dcsm717, 

more than 5 times less stringent than the Boiler MACT PM limit (0.039 lb/MMBTU 

= 45 mg/dscm7). While we understand why there is not likely to be perfect 

harmony between Boiler MACT and CISWI standards, the sheer magnitude of 

differences casts serious doubt on the viability of EPA’s floor-setting 

methodology. MACT is after all a technology-driven standard and there is no 

fundamental difference between the equipment or combustion properties of 

biomass-to-energy boilers subject to Boiler MACT and those subject to CISWI

that would justify the radically diverse standards. 

In the above example, the exceedingly low CISWI hydrogen chloride and 

mercury limits, among others, will drive biomass power plants to abandon 

burning biomass “solid wastes” that would subject them to the CISWI standard 

or, due to economic constraints, cease operating altogether. This would result in 

landfilling of urban wood and landfilling or open burning of agricultural residues, 

in contradiction to EPA’s own Solid Waste Management Hierarchy, federal and 

state air pollution control programs, renewable energy policies, solid waste 

landfill “diversion” programs, and mandated permit requirements to generate 

emissions offsets from combusted biomass.

EPA’s CO standard for the new CISWI biomass category is based on a single 3-

hour test of the one unit identified as the best performer. The test consisted of 

three runs having identical results at 153 ppmdv7. In this case and for other CO 

floor limits EPA had adjusted any measured CO data below a calculated method 

detection level, which resulted in some higher values being used in floor 

calculations, but also resulted in lower variability (especially for new source 

floors), since the same value was utilized in all 3 runs for calculation of the UPL. 

EPA conducted its statistical analysis and set the limit at 160 ppmdv7, less than 

5% above the average test result. It’s hard to understand how this limit reflects 

emission variability, especially since EPA itself recognizes that CO in particular is 

a variable pollutant stating “CEM data show that CO levels have a higher degree 

of variability than other pollutants” (76 Fed. Reg. 15646). Here and elsewhere 

EPA has applied its methodology to very limited data with seemingly no check on 

whether the resulting floor limit is rational. 

Section 129 requires new units to meet standards which are equivalent to or 

more stringent than existing units, but EPA’s methodology resulted in CISWI 

MACT floors limits for new solid/biomass ERUs that were much less stringent for 

six of ten pollutants. EPA “fixed” this problem by lowering the new unit limits 

down to the level calculated for the existing units for these six pollutants 

 

17 Milligrams per dry standard cubic meter corrected to 7 percent oxygen.
Petition for Administrative Reconsideration

Page 23

explaining in table footnotes: “The NSPS limit exceeds [i.e., is less stringent than] 

the EG limit. The EG limit was selected as the NSPS limit.” (76 Fed. Reg. 

15710, 15726, 15727). This is a further example of application of statistics to a 

small database yielding irrational results.

Given these types of unusual outcomes and the apparent limitations of EPA’s database 

and methodology EPA should reconsider its CISWI MACT floor-setting methodology. 

EPA should examine the reasonableness of derived MACT floor limits, erring on the 

side of achievability; otherwise it risks setting standards that have not been achieved in 

practice, in contradiction to the law. Specifically EPA should include reconsideration of 

the following methodological steps and issues raised by commenters: 

1) The effect of waste composition. In the final rule, the selected best performing 

CISWI units frequently combusted “solid wastes” in small proportion to total 

inputs, or burned wastes that did not contain significant amounts of the 

constituents that would cause emissions (e.g., chlorine in biomass generating 

hydrogen chloride emissions). As a result, stringent emission limits for hydrogen 

chloride, cadmium, lead, mercury and dioxin/furan were driven more by waste 

characteristics and composition than the control technology employed at the best 

performing units. Stand-alone biomass power plants (as opposed to ERUs 

located at manufacturing facilities) are economically driven to burn large 

proportions of “solid wastes” such as urban wood and are particularly 

disadvantaged by these limits where incremental emission reductions exceeding 

99% would be required. EPA should consider waste content variability 

adjustments, percent reduction alternative standards (see #4 below), geographic 

factors (e.g., biomass chloride content related to location) and other approaches 

that set achievable standards and otherwise level the playing field for units trying 

to responsibly utilize the nation’s biomass residuals.

2) Selection of upper limit value. In the final rule EPA selected the 99th percentile 

upper predictive limit of the pooled best performer data as the MACT floor for 

each pollutant. To the lay person 99% may sound like a very high compliance 

probability. To the CISWI operator however it means a 1% probability of failure, 

per pollutant, per performance test and represents an unacceptable compliance 

risk with numerous attendant consequences. For a two unit facility and nine 

pollutant limits non-compliance risk of a single performance test is 1-(0.99)18= 

17%, or approximately one failure every six years. In addition, setting the 

standard right at the selected upper limit does not allow for any compliance 

margin that every operator needs. For floors set using statistical metrics EPA 

should reconsider using a 99.9% upper limit as the MACT floor, as it did with the 

CO limit in the Boiler MACT rule.

3) Upper Predictive Limit (UPL) versus Upper Limit (UL). In the final rule EPA 

determined the MACT floor limit for each pollutant using individual test runs and 

a UPL calculation. The UPL as a statistical tool is misapplied in this case and 

should not have been used. The UPL’s fundamental premise is that run-to-run 

performance test results are randomly distributed over the entire population 
Petition for Administrative Reconsideration

Page 24

distribution. EPA acknowledges this random premise (76 Fed. Reg. 15724) yet it 

provides no evidence supporting it. In fact, run-to-run results within performance 

tests at many CISWIs are not likely to be distributed randomly across the entire 

distribution. Rather, each of the three runs conducted during a performance test 

reflects conditions affecting a unit’s emissions at the time of the test. Many of 

these conditions (e.g., waste characteristics, condition of combustor and air 

pollution control equipment, season of the year) are likely to remain the same or 

at least similar over the short duration (up to a few days) of a performance testing 

program. Individual run results in a short term performance test will therefore not 

vary randomly across the entire distribution of emissions that would be observed 

over longer (monthly or annual) time periods. Accordingly, when using the 

statistical approach to establish MACT floor limits EPA should reconsider use of 

the UL, as originally proposed in the CISWI rule, instead of the UPL.

4) EPA’s upper limit (UL) and upper predictive limit (UPL) calculations do not 

properly account for both intra-unit and inter-unit variability. In its UL and UPL 

calculations EPA has used the square root of sample variance instead of the total 

variance. By substituting sample variance for total variance EPA has not properly 

accounted for total variability. Total variability is the sum of both within (intra) and 

between (inter) unit variability. Inter-unit variability is an additive value because 

the variance in emissions from each of the top performing sources is 

independent of one another and dependent on each individual unit’s waste 

composition, combustor type, air pollution control type, test conditions and 

sample matrix. Intra-unit variability is the variability observed in test results from 

the same unit due to differences in waste composition, and process and air 

pollution control operation conditions during each test run. As such, if total 

variability is not addressed MACT floors will not represent limitations that can be 

achieved. Whether EPA uses the UPL or UL approach to determine MACT floors 

it should use the modified UPL or UL that accounts for total variance as used in 

the proposed Portland Cement Rule18 and the HWC MACT Rule19. EPA 

provided no rationale for why it did not use total variance instead of sample 

variance in the UPL or UL calculation MACT limit calculations. Its response only 

addressed use of UPL. The HWC MACT Rule estimated MACT floors that were

achievable by the average of the best performing sources by using total sample 

variance.

The equation for the Modified UPL or UL that addresses total variance is:

 

18 Development of the MACT Floor for the Proposed NESHAP for Portland 

Cement, April 2009. EPA-HQ-OAR-2002-0051-2011.

19 Technical Support Document for HWC MACT Standards, Volume III: Selection of 

MACT Standards. U.S. Environmental Protection Agency, Office of Solid Waste and 

Emergency Response. September 2005, Pages 7-5 to 7-7. EPA-HQ-OAR-2004-0022-

0453.
Petition for Administrative Reconsideration

Page 25

UPL or UL = Mean + t √ VT

Where Mean is the average of the best performing MACT unit averages and VT is 

the total variance determined as the sum of the within (intra) source variance and 

the between (inter) source variance.

Total Variance of VT = VB + Vw, 

Where VB is the variance of the average of the best performing unit averages. As 

described above VB is additive because the variance of each unit is independent 

of one another and dependent on individual units waste composition, combustor 

type, air pollution control type and sample matrix affects when sampling. VW is 

the within or intra source variance and is calculated as the sum of the variances 

of individual runs within each of the best performing sources since individual unit 

test results will vary with waste composition, and process and air pollution control 

operation conditions during each test run.

5) Alternative percent reduction standard for hydrogen chloride, sulfur dioxide, and 

mercury. EPA’s final emission standards are set as stack discharge 

concentrations. In the final CISWI rule preamble EPA did not address comments 

requesting an alternative percent reduction standard, but EPA did reject a similar 

comment in the Boiler MACT rule on the basis that it has no best performing unit 

data with which to determine appropriate values. We believe EPA is looking at 

this alternative too narrowly. If data specific to these units is unavailable, EPA 

should look beyond CISWI units to determine demonstrated emission reduction 

performance capabilities of air pollution control devices on combustion sources. 

EPA could rely on engineering calculations and vendor representations of 

achieved-in-practice results to define numerical best control efficiency 

performance of air pollution control equipment under Section 129(a)(3) provisions 

which allow standards to be based on “methods and technologies for removal or 

destruction of pollutants before, during, and after combustion.” EPA should 

establish emission reduction (percent removal efficiency) standards for sulfur 

dioxide, hydrogen chloride and mercury as compliance alternatives to the 

concentration-based standards. 

6) Common stack data. In the final rule EPA includes average test results obtained 

from a common stack serving multiple CISWI units as indicative of all units 

serving the stack. EPA offered no explanation to comments questioning the 

practice in the proposed CISWI rule, but EPA did respond to the same comment 

in the final Boiler MACT rule preamble. We strongly disagree with EPA’s 

unsupported assertion made there that common stack data represents the 

performance of individual units. In the particular instance where EPA included 

common stack data from the NY Black River Generation facility to represent all 

three units, the identical emission values in three of the top five performers 

dampens the variability that would otherwise be observed had the units 

themselves been tested. EPA should reconsider its interpretation that data from 
Petition for Administrative Reconsideration

Page 26

common stacks serving multiple units is representative of each of those units. 

These data should either be considered as one unit or, more appropriately, 

discarded from the database for purposes of determining variability.

7) Pollutant-by-pollutant approach. This issue has been vetted in other forums and 

is currently in litigation, but it bears repeating the request here on the basis of 

legal arguments presented by multiple commenters. The issue is central to any 

reconsideration request because of the impact that EPA’s pollutant-by-pollutant 

approach has on the CISWI standards. EPA should reconsider its pollutant-bypollutant approach, instead using unit-by-unit composite performance to rank and 

select best performing unit(s), especially considering the fact that EPA’s 

database demonstrates that no CISWI unit has “achieved in practice” all of the 

final emission standards.

These reconsideration requests apply to EPA’s methodology for setting MACT floor 

limits. In considering these petitions EPA should keep in mind that the floor limits are 

only the first step in setting the standards and represent the minimum stringency 

requirements. As such, given its database and methodology EPA should expect that in 

perhaps many cases it will need to go beyond the floor to set final standards, always 

evaluating the achievability of the final standards.

8. The CISWI Limits Do Not Consider Higher Emissions of CO and Other 

Pollutants During Periods Associated with Unit Start-Up and Shutdown 

When the Unit is Operating Under Non-Steady State Conditions.

In the proposed CISWI NSPS and Emission Guidelines, EPA did not provide separate 

treatment of startup and shutdown periods. The proposed CISWI Rule stated that the 

emission limits apply at all times, including startup, shutdown, and malfunction (SSM) 

periods.20 EPA stated in the preamble that the Agency was not proposing separate 

emission standards during startup or shutdown for the following reasons:

“We determined that CISWI units will be able to meet the emission limits during 

periods of startup because most units use natural gas or clean distillate oil to 

start the unit and add waste once the unit has reached combustion temperatures. 

Emissions from burning natural gas or distillate fuel oil would generally be 

significantly lower than from burning solid wastes. Emissions during periods of 

shutdown are also generally significantly lower than emissions during normal 

operations because the materials in the incinerator will be almost fully combusted 

before shutdown occurs.” [75 Fed. Reg. 31964] 21

 

20 75 Fed. Reg. 31949

21 EPA also relied in part on the Sierra Club decision invalidating the Part 63 

SSM general provisions, asserting that while the ruling “directly affects only [a particular] 

subset of CAA section 112(d) rules ..., the legality of source category-specific SSM 

provisions such as those adopted in the 2000 CISWI rule is questionable.” 76 Fed. 

Reg. at 15737. This is flawed reasoning for three reasons. First, it does not necessarily 

follow that the court’s holding extends beyond the bounds of § 112 – particularly in this 
Petition for Administrative Reconsideration

Page 27

While this may be generally true for incinerators, this does not adequately characterize 

many energy recovery units (not all boilers startup on natural gas or distillate oil as 

evidenced by examining EPA’s CISWI database, which includes startup fuel for each 

unit that submitted an ICR response). In addition, it also does not account for the fact 

that oxygen levels at startup can be very high and result in very high pollutant 

concentrations when correction to 7 percent oxygen is required. EPA recognized this 

fact in setting different emission standards for startup and shutdown under the recent 

revisions to the Portland Cement MACT standards and NSPS.22 

Many commenters objected to EPA’s position and offered various alternatives, including 

establishing separate standards for these periods. In the final rule, however, EPA 

maintained its position that the same emission standards applicable during other 

operating periods will also apply during startup and shutdown. The preamble states:

In establishing the standards in this final rule, EPA has taken into account startup 

and shutdown periods and have not established different standards for those 

periods. The standards that we are finalizing are based on short term stack tests 

for pollutants that generally are not expected to vary significantly at startup and 

shutdown. The possible exception here is CO, which in some subcategories 

such as ERUs, could vary at startup and shutdown. However, the percent 

oxygen operating limits will ensure that combustion conditions are optimized and 

the CO is minimized. Solid waste and fuel-fired ERUs do not normally startup 

and shutdown more the once per day. Thus, we are not establishing a separate 

emission standard for these periods because startup and shutdown are part of 

their routine operations and, therefore, are already addressed by the standards. 

Periods of startup, normal operations, and shutdown are all predictable and 

routine aspects of a source's operation. We have evaluated whether it is 

appropriate to have the same standards apply during startup and shutdown as 

applied to normal operations, and as the rule is structured, well operated and 

controlled units should be able to meet the standards at all times. 76 Fed. Reg. 

15738

In presenting this petition it is important that we distinguish between EPA’s definitions of 

“startup period” and “shutdown” contained in the CISWI rule23 which exclude all periods 

 

case, where § 129 specifies that standards must be established pursuant to § 111, 

under which SSM provisions have been implemented since the early 1970’s. Second, 

the 2000 CISWI SSM provisions are work practices, which qualify as “emissions 

standards” under the Act. Lastly, as explained above, the available data indicate that 

emissions during periods of SSM are significantly different from emissions during 

normal operations – even for the best performing sources. Therefore, some 

accommodation for SSM periods must be provided.

22 Rulemaking dockets EPA-HQ-OAR-2007-0877 and EPA-HQ-OAR-2002-0051

23 40 CFR 60.2265 and 40 CFR 60.2875 definitions: Startup period means the 

period of time between the activation of the system and the first charge to the unit. 
Petition for Administrative Reconsideration

Page 28

when waste is burning, and the broader scope of startup and shutdown which includes 

those periods of transition when firing auxiliary fuel and/or solid waste when the unit is 

operating under non-steady state load conditions. For example, for an ERU this 

includes the period when bringing the unit on line after solid waste has been charged 

and started burning but before reaching steady state steam load as well as periods after 

waste has ceased being charged and waste combustion is completed. It is these 

transition periods in which the greater concern exists regarding variability of emissions 

and for which EPA has no emission data. 

We disagree with EPA’s unsupported assertions that the standards address startup and 

shutdown periods. Corrected emission concentrations can be significantly higher during 

startup and shutdown due to the unavoidable less-than-optimal emissions control 

performance during transitional (non-steady state) conditions. For example, at biomass 

ERUs combustion-related emissions such as CO, particulate (smoke) and opacity 

increase during the startup period when load and temperature are coming up to full load 

steady-state conditions. The Maine Department of Environmental Protection has stated 

“Wood and multi-fueled boilers produce large CO variations during startups as the boiler 

heats up. Start-ups can take up to 14 hours for some units. Shutdowns can also result 

in significant CO variability.”24 EPA itself recognized in the Boiler MACT that “CEM data 

show that CO levels have a higher degree of variability than other pollutants” (76 Fed. 

Reg. 15646). It doesn’t matter whether these units are being fired with biomass fuel or 

biomass solid waste – the equipment involved is virtually identical and fuel combustion 

characteristic differences are minimal. Startup burners reduce emissions by preheating 

the combustion chamber and downstream equipment but are not sized to achieve full 

load temperatures and even if they were, could not completely avoid temporary suboptimal combustion conditions as heat load shifts from auxiliary fuel to waste during 

startup and from waste to auxiliary fuel during shutdown. Air pollution control equipment 

goes through similar transient temperature and flow conditions, e.g. changing furnace 

temperature and velocity profiles make SNCR systems less effective during startup than 

during full load steady state conditions. These conditions are distinct from the less 

variable conditions that occur during typical steady-state operations. EPA’s emission 

database excludes these periods and therefore does not capture this component of 

variability, leading to MACT floors that have not been achieved in practice. 

EPA should open reconsideration of CISWI emission standards applicable during 

startup and shutdown periods. Reconsideration should include review of CEMS and 

other data and an engineering assessment of combustor and air pollution control 

equipment practices to establish performance capabilities. If EPA cannot use best 

 

Shutdown means the period of time after all waste has been combusted in the primary 

chamber.

24 Letter James P. Brooks, Bureau Director, State of Maine Bureau of Air Quality 

to James Eddinger, USEPA, February 4, 2010.
Petition for Administrative Reconsideration

Page 29

operating practices under Section 129 as it has under Section 112, then it should 

consider several options for separate and distinct startup and shutdown standards 

including:

Uncorrected concentrations standards that reflect actual performance;

Corrected concentration standards, accounting for concentration “blow up” when 

dilute conditions are corrected to 7 percent oxygen;

Longer averaging times to accommodate short term swings; and

For existing units requiring State Implementation Plans (SIP) to include a process 

which sets case-by-case numerical mass-based emission standards. 

In the Boiler MACT rule, EPA had also proposed that standards apply at all times. 

However, in the final Boiler MACT rule EPA responded differently to commenters’ 

objections. In the final rule EPA incorporated a work practice standard in lieu of 

numerical limits for periods of startup and shutdown. The work practice standard 

requires sources to minimize periods of startup and shutdown following manufacturers’ 

recommended procedures.

If EPA recognized the need to modify startup and shutdown provisions in the Boiler 

MACT then it must also recognize the issue in the CISWI rule. The very same 

equipment and combustion conditions (boiler, air pollution control equipment, fuel/waste 

characteristics) that prompted EPA to change startup and shutdown provisions in the 

Boiler MACT also exist with the units regulated under the CISWI rule. EPA even 

acknowledges in both rules that sources can alternate between being boilers and 

incinerators based on whether they burn “fuels” or “solid wastes”. Yet EPA gave no 

explanation why the change made in the Boiler MACT wasn’t considered an issue in the 

CISWI rule. Accordingly, EPA should make accommodations for startup and shutdown 

in the CISWI rule just as it has under the Boiler MACT. 

EPA should expand definitions of “startup period” and “shutdown” in 40 CFR 60.2265 

and 40 CFR 60.2875 to include time periods of non-steady state operation after initial 

waste charging during startup and before auxiliary fuel firing during shutdown. Current 

definitions include only those periods when solid waste is not burning. These more 

limited definitions may have been appropriate for some categories which move 

seamlessly from auxiliary fuel to waste, but need to be changed to accommodate all 

units now included in the CISWI rule.

9. The Limits in Boiler MACT for Oil Fired Units are Unachievable.

EPA has grouped all boilers and process heaters firing any liquid fuel into one 

subcategory. Comments on the proposed rule suggested further subcategorization into 

heavy and light liquids. This further subcategorization was not incorporated into the 

final rule. In the response to comments, EPA states that although there are design 

differences between heavy and light liquid fired units, the approach taken in the final 

rule is consistent with that for solid fuels, as all solid fuels are grouped together for the 

fuel based HAP. EPA goes on to say that although solid fuel units are split for CO and 
Petition for Administrative Reconsideration

Page 30

dioxin/furan, they are not splitting light and heavy liquid units and the floors are made up 

of a mix of light and heavy units.25 The CO limits that EPA has finalized are made up of 

data that EPA has largely adjusted due to measurement capabilities of EPA Method 10, 

with little variability as a result. The floor units represent only 2 facilities, both burning 

distillate fuel oil. Additional issues with the data and methodology EPA used to set CO 

limits were discussed in Item 5. Also, an analysis of the CO data for heavy and light 

liquid units indicates that a very different CO limit would result for heavy liquid units 

when these units are treated as separate subcategories. This would indicate that EPA 

should be consistent with the Agency’s treatment of fuel and design based 

subcategories by establishing separate CO emission limits for heavy and light liquid 

units. As indicated in Item 1, we believe that work practice standards and not emission 

limits are warranted for dioxin/furan under Boiler MACT.

The liquid PM limits are set using a very small amount of data, and are not 

representative of fabric filter control technology (which EPA states is the technology 

assumed to be MACT for PM), as none of the floor units have controls. There are only 

18 data points used to set the PM floor, one of which is labeled as detection level limited 

(DLL). Therefore, the “top performers” are determined based on a very limited data set 

and reflect only combustion of distillate fuel oil or “anhydrides waste”. In fact, no unit 

burning No. 6 fuel oil (even the one listed as having a fabric filter with sorbent injection) 

meets the liquid fuel PM limit based on the PM stack test and fuel firing information in 

the EPA database. 

There are 79 units for which EPA has gathered Hg data, but only 8 stack tests. 71 units 

are assigned fuel analysis data, but represent only 14 facilities. There are 11 floor units, 

with 50 data points, of which only 10 (2 stack tests and 2 fuel analyses) are labeled as 

above the detection limit. This is a very limited amount of data and a very biased data 

set (primarily based on non-detect data) to be used to set Hg limits for units firing any 

type of liquid fuel. The Hg limits are again based on units with no Hg controls, but on 

the fuels with the lowest amounts of mercury. 

The HCl floors are similarly developed with a small amount of data and are based in 

large part on non-detect data (only 5 of 35 data points used to set the floor are above 

the detection limit – 1 stack test and 1 set of fuel analysis data). However, for 

PABoeingRidleyPark, EPA should assign the Unit 033 stack test result to all of the 

facility’s units, and not the fuel analysis data, as all of the facility’s units are uncontrolled

(the fuel analysis data are listed as non-detect and are lower than the stack test result). 

EPA should reconsider the HCl limit for liquid boilers because the selected top 

performing unit (TNInvistaChattanooga EU003 Vaporizer #2) emission test data show 

higher emissions than the limit set for existing liquid fired units (0.00062 lb/MMBtu for 

this unit versus the existing unit limit of 0.00033 lb/MMBtu). This seems to indicate a 

problem with EPA’s floor setting methodology; the selected top performer should be 

able to meet the established limit.

 

25 Response to commenter EPA-HQ-OAR-2002-0058-1869.1, Comment Excerpt Number 4.
Petition for Administrative Reconsideration

Page 31

We do agree with EPA’s approach of assigning a fuel variability factor to the HCl and 

Hg data to improve the consideration of variability in setting the floor, but EPA should 

gather additional data to improve the representativeness of the floor units. EPA should 

reconsider its decision regarding further subcategorization of liquid units and should 

gather additional emissions information to ensure the final limits are achievable by 

boilers and process heaters burning liquids other than distillate oil or process liquids.

10. The Criteria for Qualifying as a Gas 1 Boiler/Process Heater in Boiler MACT

Should Be Revised.

In the proposed rule, EPA established numerical emission limits for units burning gases 

other than natural gas or refinery gas (Gas 2 units) and established only work practice 

requirements for units burning at least 90 percent natural gas and/or refinery gas (Gas 1 

units). EPA’s justification for establishing work practices for Gas 1 units was technical 

infeasibility of measuring and controlling low levels of HAP emissions from these units. 

Industry submitted comments and other supplemental information demonstrating that 

emissions from many types of Gas 2 units were also very low and suffered from the 

same measurement and control difficulties.

In the final rule, EPA has established criteria for units burning gases other than refinery 

gas and/or natural gas to qualify as Gas 1 units. We agree that there should be criteria 

for gas-fired units to qualify for the Gas 1 subcategory, because the justification for 

requiring work practices for natural gas and refinery gas units are the same for many 

units firing other types of gases. The 4 ppmv H2S and 40 ug/m3 mercury content criteria

are based on the typical content of sweet natural gas. EPA assumed in its impacts 

analysis and Gas 2 MACT floor calculations that all gas-fired units burning gases other 

than coke oven gas and blast furnace gas would meet the Gas 1 criteria based on an 

evaluation of mercury content. 

EPA stated in the preamble, “EPA has determined that to the extent that process gases 

are comparable to natural gas and refinery gas, combustion of those gases in boilers 

and process heaters should be subject to the same standards as combustion of natural 

gas and refinery gas.” 76 Fed. Reg. 15639. However, the H2S levels selected as part 

of the Gas 1 criteria do not represent the typical content of refinery gas (Refinery NSPS 

40 CFR 60, Subpart Ja limits H2S composition of fuel gas prior to combustion to 162 

ppmv H2S on a 3-hour average basis and 60 ppmv on a 365-day average basis) and 

some other types of gases that have low mercury content will also have H2S content 

greater than 4 ppmv (e.g., landfill gas, biogas, and certain process gases). For 

example, literature indicates that the typical range of anaerobic digester gas is 200 to 

3000 ppm of H2S. Typically, digester gas meeting a pre-combustion concentration of 

200 ppm is BACT. Therefore, if H2S is retained as part of the criteria to be eligible for 

inclusion in the Gas 1 subcategory, the limit should be revised to reflect the higher H2S

contents of other clean gases.
Petition for Administrative Reconsideration

Page 32

11. The Affirmative Defense for Malfunctions Is Unfounded And Is Not An 

Appropriate Substitute for An Alternative Standard Covering Periods Of 

Malfunction

In the proposed rule, EPA asserted that “malfunctions should not be viewed as a distinct 

operating mode and, therefore, any emissions that occur at such times do not need to 

be factored into development of CAA section 112(d) standards, which, once 

promulgated, apply at all times.”26 Rather than setting standards to cover periods of 

malfunction, EPA explained that it would instead rely on enforcement discretion – i.e., if 

a true malfunction caused an affected source to exceed MACT emissions standards, 

“EPA would determine an appropriate response based on, among other things, the 

good faith efforts of the source to minimize emissions during malfunction periods, 

including preventative and corrective actions, as well as root cause analyses to 

ascertain and rectify excess emissions.”27

In our comments on the proposed rule, we argued that EPA inappropriately assumed 

that malfunctions are not a distinct operating mode that even the best performers 

sometimes experience. We further pointed out that EPA has ample authority to 

establish work practice standards in situations where numeric emissions limitations are 

not practicable. Therefore, EPA should establish a work practice standard that would 

apply during malfunction periods.28

In the final rule, EPA reiterated its belief that “it is reasonable to interpret section 112(d) 

as not requiring EPA to account for malfunctions in setting emissions standards.”29 But, 

instead of dealing with malfunctions through enforcement discretion, EPA decided to 

establish an affirmative defense that affected sources could raise if EPA or a third party 

were to seek enforcement action against an exceedance that occurs during a period of 

malfunction.30

EPA’s decision to establish an affirmative defense for periods of malfunction was not 

expressly raised in the proposed rule and cannot reasonably be considered a logical 

outgrowth of the proposal to deal with malfunctions using enforcement discretion. 

Needless to say, an affirmative defense (including detailed criteria, such as who has the 

burden of proof and what must be demonstrated to successfully mount such a defense) 

is a far cry from the wholly different proposal to rely on enforcement discretion. 

Commenters had no reason to believe that EPA would establish an affirmative defense 

in the final rule and had no opportunity to prepare and submit comments on the legal 

justification (or lack thereof) for establishing such a defense or on the specific criteria 

used to implement the defense.

 

26 75 Fed. Reg. at 32013.

27 Id.

28 See AF&PA Comments at 250-253.

29 76 Fed. Reg. at 15613.

30 Id.
Petition for Administrative Reconsideration

Page 33

In addition, EPA’s decision to establish an affirmative defense is of central relevance to 

the outcome of the rule. Affected sources under the final rule are “guilty until proven 

innocent.” This is fundamentally incompatible with EPA’s obligation to set emissions 

standards or work practices governing all periods of operation, including periods of 

malfunction. As a result, EPA must reconsider its decision to establish an affirmative 

defense for periods of malfunction.

12. PM CEMS Should Not Be Required in Boiler MACT or CISWI.

In the Boiler MACT rule (both proposed and final), EPA is requiring PM CEMS as the 

monitoring method for solid fuel and residual fuel oil fired boilers 250 MMBtu/hr or 

greater in size. In the CISWI rule (both proposed and final), EPA is requiring PM CEMS 

as the monitoring method for solid fuel and residual fuel oil fired energy recovery units 

250 MMBtu/hr or greater in size. The installed PM CEMS will be required to meet 

Performance Specification 11 and also comply with Procedure 2 in Appendix F of 

40CFR60. Comments were submitted on both rules describing how PM CEMS are 

inappropriate for combination fuel fired units and the limitations in their measurement 

capabilities. Further, Section 129 (c)(3) requires that any monitoring, test methods and 

procedures be validated on solid waste incineration units. PM CEMS have not been 

validated on any solid waste incineration unit. We believe that for the reasons 

described below, EPA should not require the installation of PM CEMS on boilers/energy 

recovery units burning solid fuel or residual oil. 

In order for a CEM to be suitable for demonstrating compliance, it must be accurate and 

precise under all operating conditions and must have demonstrated the capability of 

operating for long periods of time without breaking down. However, as discussed 

below, these requirements are not met when considering installation of PM CEMS on 

industrial boilers/energy recovery units.

(a) EPA has failed to provide any technical information regarding the 

suitability of PM CEMS as compliance monitors. In the MACT proposal 

EPA 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 statements neither establish the performance capabilities of 

PM CEMS nor do they justify their use as compliance monitors. Prior to 

promulgating this requirement, EPA must provide data that support its 

findings that justify the use of PM CEMS as compliance monitors and 

show that such monitors have been validated on multi-fuel boilers and 

solid waste incineration units.

(b) Among the instruments commercially available for measuring PM in stack 

emissions are those that use the principles of light scattering, optical 

scintillation, electrostatic induction and beta attenuation. The responses 

of several of these instruments are expected to be affected by the size 

and nature of the particles being emitted. Thus the calibration curve for 

such instruments would be expected to change as the fuel mix and 

operating load change. EPA has not published results of any study 
Petition for Administrative Reconsideration

Page 34

examining these issues. EPA must provide data that confirm that one or 

more types of monitors are capable of holding their calibration given the 

changing nature of PM emissions from multi-fuel boilers/energy recovery 

units. 

(c) PS-11 specifies in Section 8.6 (4) (i) that simultaneous PM CEMS and 

reference method tests must be performed to obtain three levels of PM 

mass concentrations. Section 8.6 (4) (ii) specifies that the three PM 

concentrations must be distributed over the complete operating range 

experienced by the source. Thus, if a source experiences high PM 

emissions for short periods of time due to process upsets, the facility 

would have to conduct the correlation tests at emission levels that could 

be above the emission standards. This raises the following issues:

(i) How can a source operate above its PM limits in order to conduct 

stack tests to meet PS-11 requirements if it must be in compliance 

with its PM limits at all times?

(ii) EPA has assumed that PM emissions from a source can be 

controlled predictably within a narrow range through operating 

changes. If that is the case, what process did EPA go through to 

exclude the monitoring of process parameters as a less expensive 

alternative to continuous PM emissions monitoring?

(iii) EPA has not documented the process by which sources that are 

equipped with a fabric filter will achieve the targeted PM emission 

rates to satisfy the requirements of PS-11. 

(d) EPA has failed to document that currently available PM CEMS are 

capable of meeting the requirements of PS-11 when they are installed on 

multi-fuel boilers/energy recovery units. 

In order to demonstrate that a PM CEMS is meeting the requirements of 

PS-11, a multi-fuel boiler will face some additional challenges not faced by 

say utility boilers burning coal. For example, a multi-fuel boiler/energy 

recovery unit burning a variety of fuels will need instruments available to 

continuously monitor the mass flow rate and moisture contents of all the 

fuels. This will greatly impact the ability of a PM CEMS to meet PS-11. 

(e) 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 obtaining a correlation coefficient of ≥0.85 between

measured and predicted stack gas PM concentrations, a 95% confidence 
Petition for Administrative Reconsideration

Page 35

interval mid range at the mean PM CEMS response value within ±10% of 

the emission limit, and a tolerance interval mid range at the mean PM 

CEMS response value with a 95% confidence that 75% of all possible 

values are within 25% of the PM emission limit. This suggests there is a 

very high probability that many CEMS PM measurements that show up as 

exceeding the standard may actually be below the emission standard.

(f) To measure and report PM emissions in lb/MMBtu, boilers/energy 

recovery units 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 biomass 

boilers, residual oil boilers, multi-fuel boilers and CISWI energy recovery 

units, 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 boilers, residual oil, 

multi-fuel boilers and CISWI energy recovery units, especially when load 

and fuel mix ratios are constantly changing. 

(g) PS-11 requires sources to conduct a minimum of 15 manual reference 

method tests. 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.” This section is 

in direct conflict with EPA’s stated use of PM CEMS as compliance tools 

of the Boiler MACT standards. Additionally, EPA has failed to recognize 

that the promulgated PM standards for new sources would require many 

hours of sampling with the Method 5 train for a single run in order to 

collect a PM mass above the quantitation limit of Method 5. Thus 

calibration of PM CEMS would require many hours of testing at stable 

rates, which may not be feasible for many swing boilers.

(h) There are 2 main types of PM CEMS: light scattering devices and beta 

gauges. For many types of units, such as multi fuel boilers/energy 

recovery units, the beta gauge will be the only option for PM CEMS. 

However, at the level of the new source PM limit for solid fuel boilers 

under Boiler MACT, the beta gauge will not be able to collect sufficient 

mass on its filter tape to be able to make 4 measurements per hour and 

satisfy the §63.7525(b)(4) requirement for continuous monitoring systems. 

Based on the questions and concerns raised above, we recommend that EPA eliminate 

the requirement to install PM CEMS on boilers/energy recovery units.
Petition for Administrative Reconsideration

Page 36

13. We Agree that CO CEMS Should Not Be Required Under Boiler MACT or 

Boiler GACT, But Believe that the O2 Monitoring Requirements Should be 

Re-Evaluated for Some Boilers.

In the proposed rule, EPA required CO CEMS for units sized 100 MMBtu/hr and 

greater. Although CO CEMS were set as the required monitoring devices, the CO limits 

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

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

extensive information regarding the variability of CO emissions and the 

inappropriateness of setting a limit using full load stack test data and requiring units to 

install CO CEMS to demonstrate compliance over all operating conditions. 

In the final rule, EPA removed the CO CEMS requirement and instead requires a 

minimum flue gas oxygen concentration operating limit and continuous O2 monitoring. 

While we agree that CO CEMS are not an appropriate monitoring requirement for a CO 

limit based on stack test data obtained at full load conditions, we do not believe that 

EPA has fully considered the potential concerns with these alternative oxygen-related 

requirements in certain circumstances. In section 5 of these comments, we suggest an 

alternative CO limit with a longer averaging time for those boilers who chose to use 

CEMS. 

The minimum oxygen and O2 monitoring requirement are not a logical outgrowth and 

represent new requirements in the final Boiler MACT rule; thus petitioners were not 

given an opportunity to comment on their use, EPA should reconsider these new 

requirements as a matter of central relevance to the rule because it goes to the heart of 

how affected sources must demonstrate compliance with the rule. 

Minimum Flue Gas Concentration Operating Limit

EPA should investigate whether the minimum oxygen requirement is effective and 

necessary to assure emissions are controlled to regulated levels in all instances. O2 is 

an attractive measure because it is used at many boilers to track combustion efficiency 

which is correlated to fuel use and thus emissions. However, EPA provides no 

discussion of the relevance of a 12 hour averaging period in comparison to establishing 

the standard from one hour test data. In that regard EPA’s selection of the operating 

limit as the lowest 1-hour average observed during CO testing is arbitrary. (Note that 

EPA’s operating limit itself is unclear. The final rule preamble states in two places that 

the minimum oxygen limit is 90% of the observed performance test result (76 FR 15618, 

15640) whereas the tables in Part 63 Subpart DDDDD specify the limitation as 100% of 

the observed minimum.)

EPA should also assess the impacts of the minimum oxygen requirement on boiler 

operating flexibility and efficiency and specific to boiler designs. The limit derived from a 

performance test period that does not include the complete mix of fuels and range of 

characteristics encountered over the course of an operating year would limit the 

operator’s flexibility to deal with fuel variations. This is particularly at issue for biomass 

boilers which need to combust fuels of varying heating value and moisture content. 

First, any additional combustion air could reduce overall boiler thermal efficiency and 
Petition for Administrative Reconsideration

Page 37

energy output. Higher oxygen levels result in additional flue gas which may affect 

performance of air pollution control equipment like ESPs that are particularly sensitive to 

volumetric flow rates. 

O2 Measurement Device Location

The location of the measurement device is problematic. Section 63.7525(a) of the final 

Boiler MACT states, "The oxygen level shall be monitored at the outlet of the boiler or 

process heater," preventing sources from being able to use existing O2 trim analyzers,

which imposes needless additional costs. 76 Fed. Reg. 15671. EPA should allow the 

use of existing O2 analyzers, which are mounted in optimum locations. 

Many existing boilers and process heaters already utilize flue gas oxygen analyzers for 

indication, alarm, and O2 trim control, where the fuel/air ratio is automatically controlled 

for optimum combustion conditions. The sensing location for existing O2 monitors is 

typically in the optimum location to sense flue gas composition as reliably as possible, 

because sensing of oxygen in these cases maintains proper excess air levels and helps 

prevent unsafe operating conditions. For many types of combustion units, that location 

is near the boiler or process heater furnace outlet in a position upstream of any potential 

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

in an erroneous direction. This location is also upstream of air preheaters where 

utilized, thus avoiding the erroneous (high O2) indications due to inherent leakage 

across regenerative air preheater seals or potential tube leakage in recuperative air 

preheaters. For those units equipped with existing O2 sensors and O2 trim control 

systems, flue gas composition at those locations would already be used for combustion 

tuning and control characterization. Therefore, if O2 monitoring was desired for 

continuous compliance under the Boiler MACT rule, sensing O2 at that current location 

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

utilized for these existing purposes are not compliance CEMS meeting PS-3 

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

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

operation.

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

downstream of potential air inleakage points and air preheater leakage points, thus 

leading to variations in readings that can impact operation and long term compliance. It 

must be recognized that where CO or NOx CEMS are utilized in the stack with O2 or 

CO2 correction, that O2 or CO2 reading corrects for variations in excess air from the 

furnace as well as any air inleakage or internal air heater leakage, so the impact is not 

of consequence from a combustion safety or direct compliance perspective. However, if 

it is required to actually monitor and maintain O2 level, then the most appropriate 

location for sensing that O2 level is upstream of any potential leakage points. 

The most cost effective approach for utilization of O2 CEMS would be to allow continued 

use of existing O2 analyzers and use of new O2 analyzers of appropriate design for the 

application to be located in optimum positions for the particular unit involved. Requiring 

periodic sensor calibration would be a way to ensure accurate O2 monitoring. If new O2

sensors are required in all cases in the breeching or stack to meet PS-3 requirements, it 
Petition for Administrative Reconsideration

Page 38

would be an unjustified additional capital and ongoing O&M expense that will not 

provide any constructive compliance information. We request that EPA reconsider the 

specifics of the O2 monitoring requirement and also provide instructions on the use of 

this monitoring method and for CO stack testing in common stack situations. Stack 

testing for CO in the common stack should be allowed without having to isolate one unit 

per test and causing unnecessary startups and shutdowns.

14. The Energy Assessment Should not be a Requirement in Boiler MACT or 

GACT and, at a Minimum, the Scope Should be Reconsidered.

EPA proposed a beyond the floor requirement of an energy assessment in the Boiler 

MACT and GACT rules. The energy assessment requirement remains in the final rules 

with some changes. We support the removal of the mandatory use of the ENERGY 

STAR program as a requirement in the final rule. 76 Fed. Reg. 15618. We also agree 

that facilities and companies that have already conducted detailed energy assessments 

should be exempt from the requirement of conducting an energy assessment if one has 

been conducted within 3 years prior to promulgation. 76 Fed. Reg. 15632. Removing

the certified assessor requirement is also supported. However, we continue to believe, 

as stated in our comments, that EPA is not justified in extending the scope of the 

assessment beyond the affected source. The "affected source" regulated by this 

NESHAP is the specified emission unit – boilers and process heaters – not the major 

source location of the emission unit. The energy assessment requires investigation into 

equipment not covered by the Boiler MACT or any other Section 112 standard. 

EPA comment responses indicate that it was EPA’s intention to only include within the 

scope of the energy assessment the equipment and facilities that are associated with 

energy output from the regulated combustion units. However, the energy use system 

definition included at 63.7575 and 63.11237 in the final MACT and GACT rules extends 

beyond that intended scope for facilities which purchase electricity for operation of

compressed air systems, machine drive (motors, pumps, fans), process cooling, facility 

HVAC, building envelop(e), and lighting.

Although we continue to believe that EPA is not justified in its inclusion of this 

requirement in the Boiler MACT and GACT rules, if the energy assessment is retained 

as a beyond the floor requirement, the scope should be reduced to the boiler and its 

auxiliaries. This element of the rule should be reconsidered because changes were 

made to the energy assessment requirements that were not included in the proposed 

rule and change the scope of the assessment.

15. We Agree that Limited Use Units Should Have Their Own Subcategory and 

that Work Practices are Appropriate as MACT.

In the proposed rule, EPA included 9 subcategories. Limited use boilers and process 

heaters were not given separate treatment than units that operate continuously. 

Commenters argued that limited use units should not be subject to the same 

compliance and testing requirements for many reasons, including the extra emissions 

that would happen if facilities were required to startup idle units to meet the annual 
Petition for Administrative Reconsideration

Page 39

testing requirements and the fact that these units spend a good percentage of their 

operating time starting up and shutting down, resulting in different emission profiles than 

full-time use units. 

In the final rule, EPA has subcategorized limited use units, so this is an appropriate 

reconsideration item because this subcategory (and the corresponding requirements for 

affected units in this subcategory) were not proposed and are not a logical outgrowth of 

the proposal. In addition, this issue is of central relevance to the rule because a 

workable approach to limited use units is needed to appropriately balance the burdens 

of the rule with the unique emissions characteristics of limited use boilers. Having said 

that, we support the creation of this subcategory due to the many reasons listed in our 

comments. We also support work practices as the appropriate compliance approach for 

this subcategory. However, we believe that units operating at less than 10 percent of 

their annual capacity factor, rather than 10 percent of the annual operating hours, 

should qualify as limited use units. A capacity utilization factor of 10 percent was 

chosen for the previous boiler MACT final rule as the best means of defining a limited 

use unit. See National Emission Standards for Hazardous Air Pollutants for Industrial, 

Commercial, and Institutional Boilers and Process Heaters; Final Rule, 69 Fed. Reg. at 

55223. This definition is equally appropriate for the current rule.

16. We Agree that it is Appropriate to set GACT for Biomass-Fired and OilFired Units at Area Sources.

In the proposed Boiler GACT rule, EPA proposed to set numerical emission limits for 

CO for existing biomass-fired and oil-fired area source boilers and for CO and PM for 

new biomass-fired and oil-fired area source boilers. The final Boiler GACT rule 

appropriately includes work practices for existing biomass-fired and oil-fired area source 

boilers and includes PM limits only for new biomass-fired and oil-fired area source 

boilers. As we indicated in our comments on the proposed rule, we believe it is 

appropriate to set standards for biomass- and oil-fired boilers as GACT and not MACT. 

CAA § 112(d)(5) authorizes EPA in most cases to set standards for area sources using 

“generally available control technologies or management practices” (i.e., “GACT”) rather 

than “MACT.” In situations where the use of GACT is authorized (as it is here), § 

112(d)(5) on its face authorizes EPA to establish “standards or requirements .... which 

provide for the use of generally available control technologies or management 

practices.” (Emphasis added). In other words, when setting standards based on GACT, 

EPA is expressly authorized to establish work practices instead of emissions limitations. 

Reconsideration of this issue is appropriate in order to ensure that an adequate 

opportunity for public comment is provided on EPA’s decision to prescribe work 

practices. 

17. We Agree that Synthetic Area Sources Subject to Boiler GACT Should not 

be Required to Obtain Title V Permits.

In the proposed rule, EPA stated that synthetic area sources (those that installed 

controls after 1990 that resulted in facility-wide emissions below the major source HAP 
Petition for Administrative Reconsideration

Page 40

thresholds) would be required to obtain a Title V permit. We submitted comments that 

stated these facilities should not be required to obtain a Title V permit. In the final rule, 

EPA has removed the requirement, but included this issue among the items to be 

reconsidered. For all of the reasons already included in our comments on the proposed 

rule, we support the removal of the requirement for area sources to obtain a Title V 

permit.

18. Fuel Switching Provisions for CISWI Units Should be Improved.

Petitioners provided comments on the proposed Boiler MACT and CISWI rules on the 

lack of a provision to allow units to switch back and forth between Boiler MACT and 

CISWI based on whether they are burning fuel and waste. In the final rule, EPA 

included a mechanism for sources to move between the two rules, but sources must 

wait 6 months after cessation of solid waste burning to move back under Boiler MACT. 

As this is a new requirement in the final rule, it is appropriate for EPA to reconsider it. 

EPA arbitrarily chose 6 months. With the extensive monitoring and testing required 

under both rules, facilities should be able to adequately ensure compliance under either 

rule without being restricted on the frequency of fuel switching. Sources should be 

allowed to make the switch between waste and fuel as often as operational concerns 

require as long as they keep adequate records.
A-1

Appendix A. Errors in the Determination of RDLs to Set Boiler MACT and CISWI

PCDD/F Limits

by Arun V. Someshwar and Ashok K. Jain

National Council for Air and Stream Improvement (NCASI)

Executive Summary

 

In setting the boiler MACT standards, EPA has stated that the emission limit should not 

be set below the capability of the applicable test method which is defined as its limit of 

quantitation. Source testing professionals agree that this information is best obtained 

by conducting simultaneous emission tests with multiple sampling trains operated by 

different teams with analysis performed at different laboratories. However, in setting the 

PCDD/F standards, EPA has erroneously used the detection capabilities of best 

performing laboratories to determine method quantitation limits and has promulgated 

standards which are orders of magnitude below the quantitation limits of PCDD/F in 

biomass boiler emissions. We recommend that for Boiler MACT, EPA should set work 

practice standards for PCDD/F since most of the measurements were well below the 

quantitation limit of EPA Method 23. Alternatively, EPA must reanalyze its Boiler MACT 

data and set much higher PCDD/F limits. Under the CISWI rule, if work practice 

standards are not allowed under Section 129, EPA must reanalyze its ERU PCDD/F 

data and set much higher PCDD/F limits.

EPA Procedure for Setting the PCDD/F Standards

In order to establish the PCDD/F emission limit for biomass stoker boilers, EPA chose 

from its database only those stokers that burned at least 90% biomass. This resulted in 

only nine boilers with PCDD/F emissions data. Assuming all NDs at their DLs, EPA 

then determined the top 12% with the lowest TEQs to be represented by 2 boilers, 

namely the Georgia Pacific, Madison, GA and Boralex Stratton Energy, Stratton, ME

boilers, each with 3 runs. Table 1 shows the detailed isomer-specific data and the 

WHO-TEF/2005 TEQs for the six runs on these two boilers. The mean and 99% UPL 

value for the six runs was 1.64E-03 and 3.82E-03 ng/dscm @ 7% O2, respectively.

Table 1. PCDD/F Emissions For 2 Biomass Stokers in Top 12%

PCDD/PCDFs in ng/dscm @ 7% O2

Georgia Pacific, Madison, GA Boralex Stratton Energy, ME

Pollutant Name Run 1 Run 2 Run 3 Run 1 Run 2 Run 3

1,2,3,4,6,7,8 HpCDD 1.55E-03 8.99E-04 6.82E-04 4.31E-03 5.39E-03 1.83E-03

1,2,3,4,6,7,8 HpCDF 2.79E-03 1.88E-03 1.69E-03 3.66E-03 8.10E-03 1.64E-04

1,2,3,4,7,8 HxCDD 6.32E-04 5.72E-04 5.03E-04 4.21E-05

1,2,3,4,7,8 HxCDF 1.10E-03 5.62E-04 2.98E-04 4.63E-04 1.76E-03

1,2,3,4,7,8,9 HpCDF 5.01E-04 4.10E-04 6.18E-04 8.14E-05 1.28E-03 1.99E-04

1,2,3,6,7,8 HxCDD 6.11E-04 5.50E-04 5.13E-04 4.35E-04

1,2,3,6,7,8 HxCDF 7.49E-04 2.10E-04 2.79E-04 5.76E-04 1.81E-03

1,2,3,7,8 PeCDD 6.55E-04 3.12E-04 5.62E-04 4.24E-04 1.31E-04

1,2,3,7,8 PeCDF 8.14E-04 7.07E-04 5.99E-04 4.89E-04 1.41E-03

1,2,3,7,8,9 HxCDD 6.65E-04 6.21E-04 5.45E-04
A-2

1,2,3,7,8,9 HxCDF 5.17E-04 2.70E-04 3.52E-04 1.43E-04

2,3,4,6,7,8 HxCDF 5.87E-04 2.19E-04 2.96E-04 3.76E-04 2.15E-03

2,3,4,7,8 PeCDF 6.97E-04 6.70E-04 5.91E-04 6.25E-04 1.82E-03 3.97E-05

2,3,7,8-TCDD 1.69E-03 4.57E-04 3.30E-04 1.10E-04 6.32E-04

2,3,7,8-TCDF 8.85E-04 5.18E-04 4.32E-04 3.17E-03 2.12E-03 7.52E-04

Total OCDD 4.96E-03 3.95E-03 3.13E-03 1.83E-02 1.71E-02 7.44E-03

Total OCDF 3.39E-03 2.37E-03 1.71E-03 4.66E-03 8.31E-03 7.94E-04

TEQs using ND=DL 3.21E-03 1.38E-03 1.44E-03 7.48E-04 2.12E-03 8.74E-04

 shaded entries are non-detects shown at the detection limit

On pages 14 and 15 of the ERG memo1, under “Measurement Detection Level 

Variability”, a procedure is laid out whereby the calculated UPL is compared to a 

computed value that was developed to account for the effect of measurement 

imprecision associated with a database that includes method detection level data. For 

each test run, a detection level (DL) is estimated (in TEQ units) by replacing each 

congener value by the average of all the “flagged” values (BDL or DLL) for that run and 

then recalculating the run TEQ. Table 2 shows the result of these calculations for the 

six runs shown in Table 1. The maximum DL value is estimated to be 1.92E-03 

ng/dscm @ 7% O2. The EPA procedure then stipulates that the maximum DL cannot 

be greater than the mean of the pollutant emissions values from the best performers

and this largest value becomes the RDL for each pollutant emissions dataset. The 

larger of the 3 x RDL value and the computed floor value or emissions limit (e.g., the 99 

percent confidence UPL) becomes the limit. Thus, since the mean (1.64E-03) is less

than the maximum DL (1.92E-03), the 3 x RDL value for biomass stokers becomes 3 x 

1.64E-03 or 4.92E-03 ng/dscm @ 7% O2. Since this value is higher than the calculated 

floor derived from the UPL calculations (3.82E-03), it becomes the basis for the floor 

(Note this value compares favorably with the EPA derived limit of 5.00E-03 ng/dscm @ 

7% O2).

Table 2. Estimation of Detection Levels For Each Run - 2 Biomass Stokers in Top 12%

PCDD/PCDFs in ng/dscm @ 7% O2

Georgia Pacific, Madison, GA Boralex Stratton Energy, ME1

Pollutant Name Run 1 Run 2 Run 3 Run 1 Run 2 Run 3

1,2,3,4,6,7,8 HpCDD 6.08E-04 4.60E-04 5.45E-04

1,2,3,4,6,7,8 HpCDF 6.08E-04 4.60E-04 5.45E-04

1,2,3,4,7,8 HxCDD 6.08E-04 4.60E-04 5.45E-04

1,2,3,4,7,8 HxCDF 6.08E-04 4.60E-04 5.45E-04

1,2,3,4,7,8,9 HpCDF 6.08E-04 4.60E-04 5.45E-04

1,2,3,6,7,8 HxCDD 6.08E-04 4.60E-04 5.45E-04

1,2,3,6,7,8 HxCDF 6.08E-04 4.60E-04 5.45E-04

1,2,3,7,8 PeCDD 6.08E-04 4.60E-04 5.45E-04

1,2,3,7,8 PeCDF 6.08E-04 4.60E-04 5.45E-04

1,2,3,7,8,9 HxCDD 6.08E-04 4.60E-04 5.45E-04

1,2,3,7,8,9 HxCDF 6.08E-04 4.60E-04 5.45E-04

2,3,4,6,7,8 HxCDF 6.08E-04 4.60E-04 5.45E-04

2,3,4,7,8 PeCDF 6.08E-04 4.60E-04 5.45E-04

2,3,7,8-TCDD 6.08E-04 4.60E-04 5.45E-04

2,3,7,8-TCDF 6.08E-04 4.60E-04 5.45E-04

Total OCDD 6.08E-04 4.60E-04 5.45E-04

Total OCDF 6.08E-04 4.60E-04 5.45E-04

DL (in TEQs) 1.92E-03 1.45E-03 1.72E-03 0.00E+00 0.00E+00 0.00E+00
A-3

 

1

no entries for the Boralex unit since the DLs for all NDs were unavailable in the original report;

Differences in EPA’s Procedures for Establishing Biomass Stoker PCDD/F Limits

There are a number of major deficiencies in EPA’s methodology for establishing 

biomass stoker PCDD/F emission limits:

(1) As seen in Tables 1 and 2, no analytical detection limit data were available for 

the Boralex Stratton Energy boiler. Thus EPA treated those values as zero in 

selecting that boiler as a best performer. This error biased the results low.

(2) EPA’s methodology for determining method quantitation limits is not valid, as 

described below.

In its September 18, 2009 guidance to sources obligated to perform dioxin/furan testing 

in response to the 2009 ICR, EPA directed sources to “calculate the in-stack emissions 

rate for any analytical measurement below detection level using the relevant detection 

level as the “real value,” in direct conflict with the Method 23 requirement. When this 

approach was used to establish PCDD/F emissions, because most of the congeners 

were present below the method detection limit, the sources with the lowest analytical 

method detection limit became the best performers. Thus, by default, the lowest 

reported analytical detection limits became the reference method detection limit (RDL) 

in EPA’s calculations, which then became the basis for determining the quantitation limit 

(determined to be three times the RDL).

In using the above approach, EPA seems to have assigned as method detection limits 

the lowest analytical detection limit values obtained at one or two laboratories for one or 

two sets of data. As NCASI stated in its comments on the boiler MACT proposal (U.S. 

EPA Docket EPA-HQ-OAR-2002-0058), EPA Method 23 consists of extracting a known 

volume of the sample from the stack to capture the target pollutant on a filter, in a 

capture solution, or combination of both, processing the collected samples, and 

analyzing the samples. Each of these three steps can introduce random errors to the 

final measurement. For example, when a stack sample is collected, due to stratification 

in the stack, the sample may not represent the true average concentration of the 

pollutant. Similarly, some contamination may be introduced in a sample during its 

processing. For example, some particulate matter may be left when samples are 

transferred from one container to another. Or, some PM may fall into the sample 

container during its handling. Finally, during analysis, the instrument calibration may 

not have an r2value equal to 1.0 or there may be matrix interference, either of which 

affects the analyst’s ability to accurately identify and quantify an instrument reading. 

The above examples of potential sources of random errors associated with EPA test 

Method 23 are not unique to this method. All measurements have errors associated 

with them. These errors consist of systematic errors, if the method is biased, and 

random errors. Even in the absence of any systematic errors, random errors cause 

replicate measurements to vary from run to run, although the average of such random 
A-4

errors is zero when the number of replicates is high. In general, the magnitude of the 

random error decreases as a fraction of the measured value as the value of the 

measured parameter increases. In practice, when the measured value of a parameter 

is much higher than the potential for random error, there is a high degree of confidence 

in the measured value obtained from a single or a few runs. However, as the measured

value decreases, the potential contribution of the random error to the measured value 

increases, thus decreasing the confidence level in the measured value from a single or 

a few runs until the point where the measured value cannot be distinguished from the 

random error.

Analytical chemists have for a long time been concerned about their ability to determine 

whether or not an analyte is present in a sample and, if it is present, its true level. This 

has given rise to two important concepts: limit of detection and limit of quantitation. In 

general terms the detection limit of an analytical method is defined as the lowest 

concentration that can be distinguished from the blank at a defined level of statistical 

significance. The quantitation limit for a method is defined as the smallest concentration 

of the analyte which can be measured where the accuracy achieves the objectives of 

the measurement.

A number of methods have been proposed for determining analytical method detection 

and quantitation limits (Coleman et al. 1997, Corley 2003, Currie 1999, Voigtman 2008). 

In 2004, EPA conducted a detailed review of analytical method detection and 

quantitation approaches (EPA 2004). In its simplest form, the detection limit of an 

analytical method is determined by conducting 7 replicate analyses of a very low level 

sample and multiplying the resulting standard deviation by 3.14. The quantitation limit, 

which is also defined as the minimum level of the test method, is then calculated by 

multiplying the detection limit by 3.18 (EPA 2004, pp. 5-35). 

While the above methods for determining the detection and quantitation limits are 

adequate for the analysis component of test methods, as described earlier, source 

emission test methods have two other components, namely sampling and sample 

processing, prior to sample analysis. Thus, any procedure for determining the detection 

and quantitation limits of source emission test methods needs to include procedures 

that would account for the random errors associated with sampling and sample 

processing in addition to evaluating random errors associated with sample analysis. 

EPA has been well aware of the issues related to method detection and quantitation 

limits for many years, as reflected in EPA’s appointment in 2005 of a federal advisory 

committee on detection and quantitation approaches and their uses in the Clean Water 

Act Program (Federal Register 2005) and issuing a 2005 memorandum regarding 

effluent limits which states: “The NPDES permit should state that any sample analyzed 

in accordance with a method having appropriate method detection limit (MDL) and 

minimum level (ML) and found to be below the ML will be considered in compliance with 

the permit limits unless other monitoring information indicates a violation.” (EPA 2005)

To establish the analytical method quantitation limits, a majority of EPA’s National 

Advisory Committee recommended that a minimum of 6 to 7 laboratories be used to set 
A-5

National Quantitation limits and after applying an appropriate outlier test, the 

quantitation limit should be set at the upper 95% confidence limit for normally distributed 

data or 95th percentile of the laboratory quantitation limit data, if data are non-normally 

distributed. To accomplish this, NCASI reassembled and reanalyzed all the PCDD/F 

emissions data in the industrial boiler MACT database and attempted to establish the 

95

th percentile values of detection limits for each of the 17 PCDD/F isomers. The detail 

boiler-specific data are provided as an attachment to this document in excel format. 

Before these percentile values were determined, the entire body of data comprising the 

detection limits for each non-detect isomer was checked for suspected “outliers” using 

the Rosner’s test. This test can be used to detect up to 10 outliers for sample sizes of 

25 or more. However, the suspected outliers at the 99% confidence interval were 

discarded from the dataset only after the data were plotted graphically and the outliers 

confirmed by “visual observation”. Table 3 provides the 95

th percentile values of the 

detection limits for each of the 17 PCDD/F isomers corresponding to all the PCDD/F 

emissions data in EPA’s industrial boiler emissions database. Data for a total of 110 

boilers were included in this analysis, of which 57 were biomass units (>10% biomass 

fired), 9 were CISWI units, 14 were Gas 1 units, 4 were Gas 2 units, 25 were coal units 

(>90% coal), and 1 was an oil unit.

Results of the Current NCASI Analysis

Table 4 summarizes the quantitation limits for the 17 isomers using the 95

th percentile 

values of detection limits shown in Table 1 where each QL is taken at 3 x the DL. Also 

shown is the QL in WHO-TEF/2005 TEQ units. The data show that using the 95

th

percentile values for the QLs, the floors for PCDD/F emissions from industrial boilers 

cannot be less than 0.106 ng/dscm at 7% O2 in WHO-TEF/2005 TEQs. For each of the 

17 isomers, Table 5 shows the fractions of all results or observations in the entire Boiler 

MACT PCDD/F database that was below the 95th percentile quantitation limits as shown 

in Table 4. It is seen that on average 94.6% of all data were below the method 

quantitation levels when using the 95

th percentile values for the QLs. Thus, a very large 

fraction of all the data was always below the respective QL for the isomer.
A-6

Table 3. Summary of Detection Limit Statistics for All Non-Detects

in the Boiler MACT PCDD/F Database, ng/dscm at 7% O2

Congener N

1

N

1

Min. Max. 95th %ile2

1,2,3,4,6,7,8 

HpCDD

53 1.68E-04 1.60E-02 1.60E-02

1,2,3,4,6,7,8 HpCDF 108 1.80E-04 2.50E-02 1.60E-02

1,2,3,4,7,8 HxCDD 162 5.65E-05 1.65E-02 1.22E-02

1,2,3,4,7,8 HxCDF 87 4.66E-05 1.60E-02 1.35E-02

1,2,3,4,7,8,9 HpCDF 189 4.63E-06 1.60E-02 1.11E-02

1,2,3,6,7,8 HxCDD 134 4.99E-05 1.61E-02 1.28E-02

1,2,3,6,7,8 HxCDF 100 4.29E-05 1.60E-02 1.28E-02

1,2,3,7,8 PeCDD 168 1.75E-04 1.60E-02 1.19E-02

1,2,3,7,8 PeCDF 113 2.56E-05 1.60E-02 1.28E-02

1,2,3,7,8,9 HxCDD 153 8.04E-04 1.80E-02 1.28E-02

1,2,3,7,8,9 HxCDF 181 0.00E+00 1.60E-02 1.14E-02

2,3,4,6,7,8 HxCDF 126 4.85E-05 1.60E-02 1.22E-02

2,3,4,7,8 PeCDF 110 2.00E-04 1.62E-02 1.35E-02

2,3,7,8-TCDD 210 0.00E+00 1.60E-02 8.72E-03

2,3,7,8-TCDF 81 2.95E-06 1.17E-02 1.00E-02

Total OCDD 41 5.50E-04 3.20E-02 3.20E-02

Total OCDF 84 2.02E-04 2.02E-02 1.61E-02

In WHO-TEF/2005 TEQs 3.53E-02

1No. of Observations; 2Detection Limit

Table 4. Summary of Quantitation Limits For Each PCDD/F Isomer Based on the 

95th Percentile Detection Limits Determined in Table 3, ng/dscm at 7% O2

Congener N

1

95th %ile2

1,2,3,4,6,7,8 HpCDD 53 4.80E-02

1,2,3,4,6,7,8 HpCDF 108 4.80E-02

1,2,3,4,7,8 HxCDD 162 3.66E-02

1,2,3,4,7,8 HxCDF 87 4.05E-02

1,2,3,4,7,8,9 HpCDF 189 3.33E-02

1,2,3,6,7,8 HxCDD 134 3.84E-02

1,2,3,6,7,8 HxCDF 100 3.84E-02

1,2,3,7,8 PeCDD 168 3.57E-02

1,2,3,7,8 PeCDF 113 3.84E-02

1,2,3,7,8,9 HxCDD 153 3.84E-02

1,2,3,7,8,9 HxCDF 181 3.42E-02

2,3,4,6,7,8 HxCDF 126 3.66E-02

2,3,4,7,8 PeCDF 110 4.05E-02

2,3,7,8-TCDD 210 2.62E-02

2,3,7,8-TCDF 81 3.00E-02

Total OCDD 41 9.60E-02

Total OCDF 84 4.84E-02

In WHO-TEF/2005 TEQs 1.06E-01

1No. of Observations; 2Quantitation Limit = 3 X Detection Limit
A-7

Table 5. Fraction of Observations in the Entire Boiler MACT PCDD/F Database 

Below the 95th Percentile Quantitation Limits As Shown in Table 4

Congener N

1

95th %ile295th %ile3

1,2,3,4,6,7,8 HpCDD 327 303 92.7%

1,2,3,4,6,7,8 HpCDF 324 303 93.5%

1,2,3,4,7,8 HxCDD 327 313 95.7%

1,2,3,4,7,8 HxCDF 327 312 95.4%

1,2,3,4,7,8,9 HpCDF 327 318 97.2%

1,2,3,6,7,8 HxCDD 327 308 94.2%

1,2,3,6,7,8 HxCDF 327 313 95.7%

1,2,3,7,8 PeCDD 327 316 96.6%

1,2,3,7,8 PeCDF 327 311 95.1%

1,2,3,7,8,9 HxCDD 327 315 96.3%

1,2,3,7,8,9 HxCDF 327 315 96.3%

2,3,4,6,7,8 HxCDF 327 310 94.8%

2,3,4,7,8 PeCDF 327 303 92.7%

2,3,7,8-TCDD 327 317 96.9%

2,3,7,8-TCDF 327 292 89.3%

Total OCDD 322 295 91.6%

Total OCDF 320 309 96.6%

94.6%

1

Total number of valid observations excluding outliers; 2number below QL in Table 4; 3% of data < QL

It should be noted here that the above analysis is only based on the analytical method 

quantitation limit and does not include random errors associated with sample collection 

and recovery of the samples. These activities are expected to increase the quantitation 

limit of Method 23.
B-1

Appendix B. Additional CO Data Analyses

1. Analysis of CO CEMS Data for Two Biomass Boiler Top Performers

The lone boiler in the top 12% biomass FBC performer list with a CO CEMS already 

installed, which was also the best performer in its category and thus the basis for setting 

limits for new boilers (both based on a short term 3 run data set), is the biomass 

fluidized bed combustor (FBC) at Temple-Inland in Rome, GA. In addition to the data 

for the 3-run test, Temple-Inland had also submitted to EPA 30 days of CO CEMS data 

for the period between 7/1/08 and 7/30/08 (Docket ID No. EPA–HQ–OAR–2002-0058). 

It appears that EPA has not used these data in setting the floor for biomass FBCs 

(existing and new). Temple-Inland also submitted to EPA a plot of the 30-day rolling 

average (CO CEM data) for this boiler that covered a 12-month period (7/7/09 to

7/7/10). NCASI obtained the detailed hourly average data for this 12-month duration 

and analyzed them as described in this document. NCASI also recently obtained 4 

months of CO CEMS data from an engineering study on a biomass stoker unit (Georgia 

Pacific in New Augusta, MS) that was also considered to be among the top 12% 

performers for the existing biomass stoker category. This document analyses these two 

sets of data and shows how alternate 24-hour average CO limits will need to be 

developed for existing and new industrial boilers that are already equipped with CO 

CEMS.

Boiler in Top 12% Biomass Stoker Category With CO CEMS

The Boiler MACT CO limit for existing biomass stokers is 490 ppm @ 3% O2. The 

Georgia Pacific, New Augusta, MS mill biomass stoker was among the twelve boilers 

considered to be among the best performers for CO emissions for the biomass stoker 

category. A value of 130 ppm @ 3% O2, the average of three one hour duration CO 

runs (90, 90 and 210.2 ppm), was used to represent this boiler. This mill recently 

conducted a 4 month-long CO emissions study on this same boiler using a rented CO 

CEMS (Oct. 1, 2010 to Jan. 31, 2011). Detail one-minute average data were available 

for analysis. Twenty-four hour average blocks (daily) were developed from these detail 

data (122 days) after eliminating a small amount of data that clearly corresponded to 

startup and shutdown conditions (0.4%). 

Table 1 provides a summary of the statistics obtained to derive the 99.9% UPL value of 

the 24-hour average data (122 points) for this boiler. The 99.9% UPL value is seen to 

be 645 ppm @ 3% O2 assuming the data were normally distributed, but since the data 

were not normally distributed the 99.9% UPL value of the log-normally transformed data 

was estimated and it was 804 ppm @ 3% O2.

Figure 1 shows a plot of the 24-hour average stack CO concentrations over the 4 month 

period. The CO concentrations are shown ordered from the lowest to the highest levels, 

ranging from 143 to 704 ppm. 
B-2

Table 1. Statistics for Daily Averages From CO CEM Data at the GP New Augusta Biomass 

Stoker

mean (X) sd (X) is dist. normal ? TINV 99.9% UPL; m = 11

337.9 96.7 N 3.15895 645

mean (lnX) sd (lnX) is dist. normal ? TINV 99.9% UPL; m = 1

5.8 0.3 Y 3.15895 6.7

UPL of X = 804

1 99.9% UPL = [mean + stdev *Tinv * (1/122+1)0.5]; 2 data was not normal at the 5% Significance Level, 

thus the statistics for the log-normalized data set are also presented;

Figure 1. 24 Hour Average CO CEMS Data – GP, New Augusta, MS – 10-01-10 to 01-31-11

Table 2 shows that the CO limit of 804 ppm @ 3% O2 would never have been exceeded 

for this boiler over the 4-month study period.

Table 2. Exceedances Based on Analyzing Daily Average Data at the GP, New Augusta, 

Biomass Stoker

 If Limit at

# of Days Exceeding 

Limit

Percent of Time 

Limit Exceeded

803.8 ppm @ 3% O2 0 0.0%

Boiler in New Biomass FBC Category With CO CEMS

The Boiler MACT CO limit for new biomass fluidized bed combustors is 260 ppm @ 3% 

O2. This limit was based on a set of three runs at the best performing biomass-fired 

FBC unit at Temple-Inland in Rome, GA (136.3, 60.9 and 99.2 ppm @ 3% O2, avg = 

98.8). However, this boiler is equipped with a CO CEMS. As previously mentioned, 

Temple-Inland had submitted a limited amount of CO CEMS data to EPA and a plot of 

the 30-day rolling average (CO CEM data) for the period between 7/7/09 and 7/7/10. 

0

100

200

300

400

500

600

700

800

1 11 21 31 41 51 61 71 81 91 101 111 121

CO (ppm @ 3% O2)

122 Daily Averages

24 Hr Average CO Profile - 10-01-10 to 01-31-11 - GP, New Augusta, MS

Log-normal Data

99.9% UPL = 

804 ppm @ 3% O2
B-3

These data were not considered by EPA in setting limits for biomass FBCs (new or 

existing). NCASI obtained the detail 24-hour average data for this year-long duration 

directly from the mill. Just as for the GP New Augusta boiler, twenty-four hour average 

blocks (daily) were developed from these detail data (365 days) after eliminating a small 

amount of data that clearly corresponded to startup-shutdown conditions (0.8%). Table 

3 provides a summary of the statistics obtained to derive the 99.9% UPL value of the 

24-hour average data (360 points) for this boiler. The 99.9% UPL value is seen to be 

318 ppm assuming the data were normally distributed, but since the data were not 

normally distributed the 99.9% UPL value of the log-normally transformed data was 

estimated (390 ppm).

Table 3. Statistics for Daily Averages From CO CEM Data at the T-I Rome Biomass FBC

mean (X) sd (X) is dist. normal ? TINV 99.9% UPL; m = 11

114.0 65.3 N

1

3.11309 318

mean (lnX) sd (lnX) is dist. normal ? TINV 99.9% UPL; m = 1

4.6 0.4 N 3.11309 6.0

UPL of X = 390

1 99.9% UPL = [mean + stdev *Tinv * (1/360+1)0.5]; 2

data was not normal at the 5% Significance Level, 

thus the statistics for the log-normalized data set are also shown;

Figure 2 shows a plot of the 24-hour average stack CO concentrations over the 12 

month period. The CO concentrations are shown ordered from the lowest to the highest 

levels, ranging from 41 to 689 ppm. 

Figure 2. 24 Hour Average CO CEMS Data – Temple-Inland Rome, GA – 07-07-09 - 07-07-10

Table 4 shows that the CO limit of 390 ppm @ 3% O2 would have been exceeded for 3 

days or 0.8 percent of the study period.

0

100

200

300

400

500

600

700

1 61 121 181 241 301

CO (ppm @ 3% O2)

360 Daily Averages

24 Hr Average CO Profile - 07-07-09 to 07-07-10 - Temple Inland, Rome, GA

Log-normal Data

99.9% UPL = 

390 ppm @ 3% O2
B-4

Table 4. Exceedances Based on Analyzing Daily Average Data at the T-I Rome, Biomass FBC

 If Limit at

# of Days Exceeding 

Limit

Percent of Time 

Exceeded Limit

390 ppm @ 3% O2 3 0.8%

Conclusion

Based on a limited amount of CO CEMS data presented here, it is seen that the 24-hour 

average limit for boilers already equipped with CO CEMS would have to be higher than 

those derived from short term typically one or two sets of 3 run tests. Since the CO 

CEMS would always be in operation, natural fluctuations in the boiler’s CO emissions 

over a long period of time due to fuel variability and other factors would dictate that a 

higher limit based on long term CO CEMS data analysis is warranted for such boilers. 

Further, it should be recognized that a 99.9% UPL does not mean the limit would never 

be exceeded for an actual data set. As is seen for the Rome boiler, the 99.9% UPL was 

exceeded for 0.8% of the 360 24-hour periods. Thus, if any 24-hour standards are set, 

they should include a 1% exceedance allowance. Finally, since boilers are exempt from 

meeting the CO limit during periods of startup and shutdown, these periods will need to 

be clearly defined relative to the boiler’s operations. 

2. CO Limits For Existing and New Biomass Stokers and FBCs Should Be 

Recalculated By Including Longer Duration CO CEMS Data For Boilers Already 

Determined To Be Best Performing

The recently promulgated Boiler MACT CO limits for existing biomass stokers and 

biomass fluidized bed combustors (FBCs) are based on determining the 99.9% UPL 

value of a limited number of short term 3-run test averages for 12 and 5 “best 

performing” boilers, respectively. Sixteen sets of 3-run test averages were available for 

the 12 best performing biomass stokers, whereas only five sets were available for the 5 

best performing biomass FBCs. The limits for new biomass stokers and FBCs are both 

based on considering just three runs from a single test at the best performing boiler. 

It is generally well known that CO emissions from biomass combustion in boilers are 

highly variable over longer time durations, even when firing more or less the same 

biomass fuel. Seasonal variability in the quality of the biomass fuel fired may be partly 

responsible. Moreover, although the short term 3-run test averages were considered for 

analysis strictly only when the boiler was burning >90% biomass, during a given year a 

biomass boiler as presently categorized can burn other fuels (gas, coal, oil, etc.) up to 

90% of its total heat input. Thus, unless data that sufficiently capture the variability of 

CO emissions in such “best performing” boilers are also included in the analysis for 

determining the floors, the limits as currently derived would not be reflective of the 

variability in CO emissions from these boilers.

The short term 3-run tests were typically carried out using a certified CO CEMS. If 

longer term CO CEMS data were available on these same best performing boilers, 
B-5

these would be very helpful in addressing the variability in CO emissions from such best 

performing units. To demonstrate this fact, two sets of long-term CO CEMS data 

corresponding to one boiler each in the biomass stoker and biomass FBC category are 

presented and analyzed in this document. NCASI recently obtained 4 months of one 

minute average CO CEMS data as a part of an engineering study conducted on the 

Georgia Pacific, New Augusta, MS biomass stoker unit. This boiler already belongs to 

the group of 12 stoker units that has been identified by EPA as the top 12% “best 

performers”, based on which the current limit of 490 ppm @ 3% O2 was derived. 

NCASI also analyzed one year’s duration (7/7/09 and 7/7/10) of hourly average CO 

CEMS data for the biomass FBC unit at Temple-Inland, Rome, GA. In addition to the 

data for a 3 one hour-run test, which caused this boiler to be a best performer in its 

category for both existing and new FBCs, Temple-Inland had also submitted to EPA 30 

days of CO CEMS data (7/1 to 7/30/08) and a plot of the 30-day rolling average (CO 

CEM data) for the period between 7/7/09 and 7/7/10. However, the 30-day CO CEMS 

data appear not to have been considered by EPA in setting limits for biomass FBCs, 

new or existing. 

The analysis presented here looks at the impact on the 99.9% UPL value (floor or limit) 

when the 3 hour-average blocks of CO CEMS data from these two boilers are combined 

with the more limited number of 3-run test averages that were used to determine the 

floors for existing biomass stokers and FBC units. It also looks at the impact on the 

99.9% UPL value for new biomass FBCs based on the CO CEMS data for the TempleInland, Rome, GA unit since this unit was also the best performer in its category. 

Further, it is suggested that just as for the new biomass FBC category, the limits for the 

new biomass stoker category should be revisited after generating additional CO CEMS 

data on the Louisiana Pacific, Sagola, MI biomass stoker, the best performer in the 

biomass stoker category.

Recalculated Limit For Existing Biomass Stokers

The current Boiler MACT CO limit for existing biomass stokers is 490 ppm @ 3% O2. 

This limit was arrived at by analyzing the short term 3 test run averages corresponding 

to 12 biomass stokers that burned >90% biomass “during the tests”. EPA’s protocol for 

determining the floor requires that once the top candidates in the floor are identified, 

then all valid data corresponding to the boilers in this floor that were otherwise not 

included in determining the best performers need to be included in the UPL analysis to 

determine the floor. This was no doubt put in so as to include the impact of the 

variability within a boiler’s own emissions over longer periods of time. 

A 4 month-long CO emissions study was conducted on the MSGPNewAugusta boiler 

using a rented CO CEMS (Oct. 1, 2010 to Jan. 31, 2011). The detail one-minute 

average data are available for analysis. Nine hundred and sixty (960) three-hour 

average blocks were developed from these detail data (122 days) after eliminating a 

small amount of data that clearly corresponded to startup/shutdown/malfunction (SSM) 

conditions (~0.4%). EPA had already considered sixteen 3-hour averages 

corresponding to 12 boilers in estimating the 99.9% UPL value (floor) for CO emissions 

for biomass stokers. Table 1 provides a summary of the statistics obtained when all 
B-6

976 3-hour average data points (960 + 16) are used to derive the 99.9% UPL value. 

The 99.9% UPL value is estimated at 736 ppm @ 3% O2 assuming the data were 

normally distributed, but since the data were not normally distributed, the 99.9% UPL 

value of the log-normally transformed data was estimated and it was 1068 ppm @ 3% 

O2. 

Table 1. Recalculated Statistics for the CO Floor - Existing Biomass Stokers 

mean (X) sd (X) is dist. normal ? TINV 99.9% UPL; m = 1

1

336.6 128.7 N

2

3.0986 736

mean (lnX) sd (lnX) is dist. normal ? TINV 99.9% UPL; m = 1

5.7 0.4 N 3.0986 7.0

UPL of X = 1068

1 99.9% UPL = [mean + stdev *Tinv * (1/976+1)0.5]; 2 data was not normal at the 5% Significance Level, 

thus the statistics for the log-normalized data set are also presented;

Recalculated Limit For Existing Biomass FBCs

The current Boiler MACT CO limit for existing biomass fluidized bed combustors is 430 

ppm @ 3% O2 and it was arrived at by analyzing the short term 3-run test averages 

corresponding to 5 biomass FBCs that burned >90% biomass “during the tests”. As 

previously mentioned, the FBC unit at Temple-Inland, Rome, GA was included in this 

list of the 5 best performing FBCs based solely on data submitted for a single 3-run test. 

NCASI obtained detail hourly-average data for this boiler for the period between 7/7/09 

and 7/7/10. Two thousand seven hundred and ninety three (2793) three-hour average 

blocks were developed from these detail data (365 days) after eliminating a small 

amount of data that clearly corresponded to startup or shutdown conditions (~0.8%). 

EPA had already considered five 3-hour averages corresponding to 5 boilers (including 

the Rome boiler) in estimating the 99.9% UPL value (floor) for CO emissions from 

biomass FBCs. Table 2 provides a summary of the statistics obtained when all 2798 3-

hour average data points (2793 + 5) are used to derive the 99.9% UPL value. The 

99.9% UPL value is estimated at 405 ppm @ 3% O2 assuming the data were normally 

distributed, but since the data were not normally distributed, the 99.9% UPL value of the 

log-normally transformed data was estimated and it was 474 ppm @ 3% O2. 

Table 2. Recalculated Statistics for the CO Floor - Existing Biomass FBCs 

mean (X) sd (X) is dist. normal ? TINV 99.9% UPL; m = 11

113.7 94.2 N

2

3.0931 405

mean (lnX) sd (lnX) is dist. normal ? TINV 99.9% UPL; m = 1

4.6 0.5 N 3.0931 6.2

UPL of X = 474

1 99.9% UPL = [mean + stdev *Tinv * (1/2798+1)0.5]; 2 data was not normal at the 5% Significance Level, 

thus the statistics for the log-normalized data set are also shown;
B-7

Recalculated Limit For New Biomass Stokers

The current Boiler MACT CO limit for new biomass stokers is 160 ppm @ 3% O2 and it 

was arrived at by analyzing data from 3 runs at the best performing biomass stoker at 

the Louisiana Pacific, Sagola, MI mill (51.8, 56.1 and 96.0 ppm @ 3% O2, avg = 68.0). 

Just as for the new biomass FBC unit discussed below, if additional CO CEMS data 

were available for this boiler, an analysis of additional 3 hour average CO blocks would 

have shown that the CO limit should have been higher, correctly reflecting the variability 

in CO emissions in even the best performing biomass stoker unit.

Recalculated Limit For New Biomass FBCs

The biomass FBC unit at Temple-Inland, Rome, GA was also the best performing FBC 

unit relative to CO emissions. The Boiler MACT CO limit for new biomass FBCs is 260 

ppm @ 3% O2. This limit was based on a set of three runs at the Temple-Inland, Rome, 

GA FBC unit (136.3, 60.9 and 99.2 ppm @ 3% O2, avg = 98.8). As previously indicated, 

2793 three-hour average blocks were developed from the detail CO CEMS data (365 

days) on this boiler after eliminating a small amount of data that clearly corresponded to 

startup or shutdown conditions (~0.8%). Table 3 provides a summary of the statistics 

obtained when all 2794 3-hour average data points (2793 + 1) are used to derive the 

99.9% UPL value. The 99.9% UPL value is estimated at 405 ppm @ 3% O2 assuming 

the data were normally distributed, but since the data were not normally distributed, the 

99.9% UPL value of the log-normally transformed data was estimated and it was 473 

ppm @ 3% O2. 

Table 3. Recalculated Statistics for the CO Floor - New Biomass FBCs 

mean (X) sd (X) is dist. normal ? TINV 99.9% UPL; m = 11

113.7 94.2 N

1

3.093154 405

mean (lnX) sd (lnX) is dist. normal ? TINV 99.9% UPL; m = 1

4.6 0.5 N 3.093153 6.2

UPL of X = 473

1 99.9% UPL = [mean + stdev *Tinv * (1/2794+1)0.5]; 2 data was not normal at the 5% Significance Level, 

thus the statistics for the log-normalized data set are also shown;

Conclusion

If the additional 960 CO emission data points representing 3 hour averages for the GP, 

New Augusta, MS biomass stoker unit and 2793 CO emission data points representing 

3 hour averages for the Temple-Inland, Rome, GA biomass FBC unit are included in the 

UPL determinations, the floor for existing biomass stokers and FBCs jump from the 

current 490 ppm and 430 ppm @ 3% O2 to 1068 ppm and 474 ppm @ 3% O2, 

respectively. Using the same 2793 CO emission data points representing 3 hour 

averages for the Temple-Inland, Rome, GA biomass FBC unit, the floor for new 

biomass FBCs jump from the current 260 ppm @ 3% O2 to 473 ppm @ 3% O2. 
B-8

This analysis of longer term CO CEMS data on boilers already considered to be among 

the best performing in their respective categories clearly suggests that a few short tests 

lasting 3 hours do not capture the variability in boiler CO emissions. Biomass boiler CO 

emissions are greatly affected by fuel moisture content and boiler load fluctuations. 

Consequently, EPA must consider long-term data in setting the CO emission limits.