To: Brian Shrager and Mary Johnson, EPA/SPPD 

From: Amanda Singleton, ERG 

Date: August 20, 2010 

Re: Minutes of Council of Industrial Boiler Operators Industry Meeting – August 11th, 2010 

Meeting Agenda 

1) Summary of Comments on Commercial/Industrial Solid Waste Incinerator (CISWI) Proposal 

2) Summary of Comments on the Boiler MACT Proposal 

Meeting Attendees 

Scott Darling, Alcoa 

Steve Gossett, Eastman Chemical 

Fred Cleveland, Eastman Chemical 

Amy Marshall, URS (consultant for ACC, AF&PA, CIBO, and Manufacturers and Chemical 

Industry Council of North Carolina) 

Mike Lewis, Georgia Pacific 

Pat Dennis, Archer Daniels Midland 

John DeRidder, Dupont 

Bob Bessette, Council of Industrial Boiler Operators (CIBO) 

Ketan Patel, EPA/SPPD 

Robin Dunkins, EPA/SPPD 

Brian Shrager, EPA/SPPD 

Mary Johnson, EPA/SPPD 

Toni Jones, EPA/SPPD 

Amanda Singleton, ERG 

Summary of Industry Comments on CISWI Proposal 

 Several representatives requested that the Agency finalize the solid waste definition first, 

and then proceed with the CISWI and boiler rulemakings after an appropriate split can be 

made on the data used to support each of the standards. 

 Steve Gossett led a discussion concerning a need for more subcategories. Given the level 

of subcategorization used in the boiler proposals, he was surprised to see only a single 

energy recovery unit for all types of waste burning boilers. He added that the current 

energy recovery unit subcategory contains liquid, biomass, and wide variety of other 

units. Mr. Eastman added that no boiler firing coal will achieve HCl and SO2 limits 

proposed for energy recovery units, even with the most advanced scrubber technology 

available in the world. 

 Several representatives requested that EPA retain exemptions for burnoff ovens and 

laboratory analysis units. Mr. Gossett indicated that the Tennessee Eastman Chemical 

plant would need to purchase new spare parts while the parts are sent off-site for cleaning 
if these ovens cannot be exempted from the CISWI. The cost to purchase a new set of 

parts would be approximately $350,000 per year, which he added was not considered in 

the regulatory impacts analysis. He added that there are thousands of burnoff ovens 

nationwide, much more than was indicated in the inventory for the proposed rule. In 

addition, the ovens run sporadically with each part cleaning cycle lasting approximately 3 

to 4 hours. Given this limited operation and their small size, these units would be very 

difficult to test. 

 Several representatives requested that instead of taking a “once in always in” approach, 

compliance provisions need to be added to the rules to allow units to be applicable to 

either CISWI or the Boiler MACT emission limits depending on what the unit is burning. 

Mr. Gossett noted that a unit at his facility combusts wastewater treatment sludges that do 

not have meaningful heating value. However, the unit does not always burn sludges and 

so the limits associated with waste materials should be flexible to account for periods 

when no waste is being combusted. He added that the emission profile of this unit is 

affected depending on what materials are being fired in the unit. Specifically, when 

sludge is fired in the unit, emissions of NOx and PM are reduced. Mr. Gossett referenced 

the hazardous waste combustor MACT provision which allows a facility to comply with 

the rule when the unit is firing hazardous waste and comply with another applicable rule 

when the unit is not firing hazardous waste. Mr. Gossett requested that a similar provision 

should be made in the compliance provisions of CISWI to allow units to comply with 

CISWI when firing waste and comply with boiler MACT when not firing waste. 

 John Deridder and Mike Lewis requested EPA to provide an allowance to burn an 

incidental amount of waste and not be a classified as a solid waste incinerator. In NRDC 

v. EPA, 489 F.3d at 1257–58, the Court held that the term “solid waste incineration unit” 

in CAA Section 129(g)(1) “unambiguously include[s] among the incineration units 

subject to its standards any facility that combusts any commercial or industrial solid 

waste material at all — subject to the four statutory exceptions identified [in CAA 

Section 129(g)(1)].” Mr. Deridder and Mike Lewis provided examples of how incidental 

amounts of waste may enter the fuel stream. For example, when coal trucks are dumped 

they contain pieces of railroad ties and other items from the mine. Large chunks of debris 

are filtered out prior to being fed to the boilers but smaller particles will not be identified 

and screened out prior to the boiler. Similarly, at a pulp mill fuel is stored outside in hog 

fuel piles and pieces of trash may blow into a hog fuel pile from neighboring roads. Mr. 

Lewis requested that EPA add provisions to the rule for a waste maintenance plan or best 

practices to ensure that waste feeds are minimized to the practical extent possible instead 

of requiring a signed certification by a responsible official to claim that no waste – at all

– was fired in the boilers. 

 Tire-derived fuel (TDF) and resinated wood products were two materials of concern 

representatives discussed with respect to the non-hazardous secondary materials 

definition. Mr. Lewis noted that resinated wood products, if classified as waste materials, 

will have a huge national impact on waste disposal and economic impacts to the forest 

products industry. He added that resins are made of carbon, hydrogen and oxygen and 

that there is no difference in stack emissions from resinated and non-resinated wood 

products. Mr. Lewis also referenced data that shows how resins improve the combustion 

of the biomass material, by adding heat content to the fuel. Pat Dennis noted that in order 

for the state of Illinois to maintain their waste tire stockpile program, the state needs to 

provide ample fuel outlets. He added that states also use the TDF fuel programs to 

subsidize the tipping fees for disposing used tires in order to prevent illegal dumping of 
tires. At the ADM facility and many other facilities, Mr. Dennis indicated that magnets 

skim the ash in order to extract the steel, and then the steel is sent to a recycling facility. 

Given this ash treatment, he added that it is technically unnecessary and cost prohibitive 

to require metal removal prior to combustion. 

Comments on the Boiler MACT Proposal 

Data Quality 

 John DeRidder led the discussion on concerns with data quality used in the proposal. He 

indicated that industry has been submitting, and will continue to submit, corrections for 

adjusting data to the appropriate fuel category, incorrect test data, boilers being analyzed 

multiple times, or incorrect handling of non-detect data. These corrections include 

corrections to errors identified in the test report itself as well as inadvertent errors in the 

ICR template spreadsheets. 

 In addition to these facility specific corrections, the industry requested that EPA conduct 

a more robust quality assurance on the data used to establish the MACT floors in 

accordance with the EPA Quality Assurance Program. 

 Industry also highlighted several of the most common inconsistencies in the dataset: 

o Inconsistent treatment of detection levels for all five mercury fractions of the 

Method 29 results. 

o Values reported during CO tests were below the bounds of the minimum 

detection levels based on the spans used during the tests. 

o Some TEQ numbers were reported as TEQ instead of a mass basis in the ICR test 

data. As a result the toxic equivalency factors were applied twice to some of the 

dioxin data. 

Fuel Variability 

 Mr. Gossett provided several handouts on the fuel variability data contained in the 

emission database and he indicated that Eastman will be submitting additional fuel 

variability data as part of their written comments. He indicated that the Agency should 

request additional fuel variability data from the top performing units. Most fuel analysis 

data provided by the top performers had less than 40 fuel samples. The facilities with the 

largest number of fuel samples for chlorine [TNEastman (347 samples for chlorine) and 

INPurdue (71 samples for chlorine)] also showed the largest variability in fuel analysis. 

 Mr. Gossett also suggested that the Agency revise its approach of removing outliers from 

the fuel analysis data. These data points represent the true variability in fuel that each 

facility receives. He added that a short 30-day fuel variability sampling is not 

representative of long term trends. 

 Mr. Gossett referenced the hazardous waste combustor MACT rule to provide alternative 

methodology for calculating fuel variability. He will be submitting the details of the 

suggested revised methodology in his written comment, but the general outline of 

methodology used in the hazardous waste combustor MACT calculates the upper 

prediction limit (UPL) of all of the fuel analysis data from the top performing boilers. 

Next, the UPL is divided by the average (mean) of all of the fuel analysis data from the 
top performing units. The ratio of the UPL to the mean is used to calculate a fuel 

variability factor for Hg and HCl.

CO Emission Limits 

 Industry expressed concern that the CO emission limits do not adequately account for 

variability with operations. Since the limits were calculated from stack tests which are 

typically fired at loads in excess of 90 percent of heat input capacity, the limits do not 

reflect CO levels that can be achieved at low loads. 

 The industry disagreed with the Agency assertion in the preamble that CO emissions do 

not vary with load. They indicated that they will be providing additional data from CEMS 

to support this claim for both area and major sources. In reviewing the CEMS data 

collected during the ICR Phase II testing for six boilers the industry provided the 

following observations: 

o The CEMS data provided for the Coal – Stoker boiler have a minimum load of 

50% of design capacity and no start-up, shutdown, or malfunction conditions. 

o The CEMS data for the Coal-PC boiler contains a minimum load of 100 mmBtu. 

Upon inspection of the data, some data points appear to be referencing a row 

number instead of the value of the heat input load. Industry representatives did 

note that the average CO levels during periods of startup, shutdown, and 

malfunction (SSM) were 35 ppm while the average CO levels excluding periods 

of SSM were 27 ppm. 

o The TNEastmanChemical stoker boiler (in the CISWI database) does have CO 

data that shows variation with load. 

 Industry expressed particular concerns with CO emissions during periods of SSM. Mr. 

Gossett indicated that Eastman will also be submitting data to indicate the spikes in CO 

emissions during SSM. 

 Industry representatives indicated that the length of time a start-up takes is specific to the 

type of plant and type and size of boiler. The length of the start-up period will also impact 

how long the averaging time needs to be in order to account for SS periods. Given the 

unit-specific nature of start-ups industry representatives suggested that if SSM periods 

will be included in the average for CO, an averaging provision should be developed in 

order to account for length of start-up. Alternatively, industry suggested having a work 

practice standard during periods of SS due to technical and economic limitations. For 

example, many representatives indicated that during the SS periods personnel safety is 

the top priority, followed by equipment damage from warming the unit too quickly. 

 Mr. DeRidder added that some values for CO are so low that they approach values 

equivalent to zero or non-detect. Most CO analyzer equipment cannot measure accurately 

down to 1 ppm. 

PM CEMS 

 Industry representatives requested clarification on a few provisions of the language 

concerning PM CEMS and opacity monitoring: 

o Mr. Darling noted that the preamble indicates a monthly or 30-day rolling 

average for units complying with a PM CEMS. However, in the rule (63.7525) 

the requirement is listed as a 24-hour block average. Mr. Darling suggested that 

the rolling average is most appropriate. 
 Mr. Darling also indicated that the proposed rule language indicates that if you have an 

applicable opacity limit you must install a monitor. Industry suggests that the language 

should say “applicable opacity limit from this rule”. 

 Many industry representatives had a concern over incorporating periods of SSM on units 

that are required to install a PM CEMS. Mr. Darling presented a graph of the start-up 

periods at Alcoa that he will be submitting in his written comments. 

 Mr. Lewis and other representatives expressed a concern over the PM CEMS requirement 

for biomass units given the variety in the fuel mix. He indicated that the fuel moisture 

and ash characteristics can affect the performance of the monitors. 

Dioxin/Furans (D/F) Emission Limits 

 Industry representatives suggested that EPA does not have sufficient or representative 

data to establish a numerical standard for D/F. Further, nearly all of the D/F data used to 

establish the MACT floor are based on non-detect values. They suggested establishing a 

work practice until sufficient data is made available for the source category. 

 Industry also indicated that there is a lack of knowledge on how D/F are formed and how 

to consistently control D/F emissions to the levels in the proposed rule. Several industry 

representatives contacted D/F control technology vendors and they were unable to 

identify any performance data for D/F controls on industrial boilers. The only 

performance data available were from other types of combustion equipment (e.g., 

hazardous waste combustors, municipal waste combustors), and these sources have much 

higher D/F inlet concentrations than what has been observed in the boiler test data. 

Gas 2 Subcategory 

o Industry representatives indicated that gas 1 and gas 2 subcategories have similar 

emissions profiles and requested that the work practices be extended to other gaseous 

fuels. They noted that large quantities of gas 2 would be flared if gas 2 units were subject 

to emission limits. 

o Industry requested that EPA clarify the definition of refinery gas and suggested that they 

might incorporate a maximum chlorine or mercury content of the gas as part of the 

definition. 

Tune-Up Components 

 Mr. Darling generally agreed with the annual tune-up provisions of the work practice 

standard but he had some concerns regarding the feasibility of implementing the tune-ups 

at his Alcoa facility: 

o The requirement to visually observe the smoke pattern may not be applicable to 

metallurgical furnaces or other units where the exhaust is routed to a common 

tube. Such a tube cannot be viewed by an observer while the heaters are firing. 

As such, Mr. Darling requested that this requirement be conducted on an ‘as 

applicable’ basis. 

o Many facilities have natural gas meters installed per building but the meters are 

not specific to individual units. Therefore the natural gas fed to a specific unit 

cannot be measured. 
o The goal of a tune-up should be to optimize CO emissions or optimize 

combustion efficiency, not necessarily minimize CO. Several industry 

representatives indicated that there is a threshold for low CO levels, below which 

combustion efficiency and NOx emissions are negatively affected. 

Liquid Subcategory 

 Mr. Deridder indicated that the dataset for the liquid fuel MACT floor analysis is based 

mostly on emissions from distillate fuel oil. Industry inquired on whether or not the liquid 

fuel category can be split to divide distillate oils from heavier oil.

 Industry representatives requested that numerical emission limits for distillate oil should 

be reconsidered and perhaps replaced with a fuel oil supplier certification and/or a work 

practice standard.

New Source Limits 

 Industry representatives expressed several concerns with the MACT floor analysis for 

new sources: 

o Can the Agency claim that limits established by the pollutant-by-pollutant 

approach be achieved by the best controlled similar source? 

o Is further subcategorization warranted for new units in order to account for 

regional fuel availability and fuel type at new units? 

o Shouldn’t the best performing unit in each subcategory be based on 100% of the 

fuel type for the category? 

Co-fired Boilers 

 As proposed, units co-firing biomass and coal will be classified as coal units. Industry 

representatives indicated that these units will have difficulty meeting CO limits for the 

coal subcategory when co-firing biomass and coal. Industry will be submitting detailed 

comments on suggested alternative compliance approaches for co-fired units. They 

suggested that one potential approach could be to adopt the compliance format used in 40 

CFR part 60 subpart Db where the limits for SO2 are a ratio of limits for the coal and 

biomass categories, depending on the fraction of boiler’s heat input. 

Emissions Averaging 

 Mr. Gossett and other industry representatives had several clarifying questions for EPA 

on the emission averaging requirements: 

o Mr. Gossett indicated that the TNEastman facility has three coal boilers that are a 

mix of stokers and PC combustor design. The proposal indicates that a facility 

cannot apply the emissions averaging provision across subcategories. In this case 

PM limits are subcategorized by coal, biomass, and liquid but in Table 1 of the 

preamble the coal and biomass subcategories are specific to both the fuel type 

and combustor design, thus preventing a facility from using emissions averaging 

among coal-fired boilers with different combustor designs. Mr. Gossett 

questioned whether the intent emissions averaging provision was to be limited to 

a given fuel type or if it was specific to a particular combustor design. 

o Mr. Gossett also questioned whether or not the provision to use the maximum 

design capacity rating for each of the units used in the emission averaging, as 
opposed to the actual heat input from each of the units, was appropriate. He 

indicated that the HON rule requires a facility to use typical operating rates in the 

rule’s emissions averaging provisions. 

o Mr. Gossett asked for clarification on the definition of affected source. Is the 

affected source everything in the subcategory or everything under the subpart? 

 In addition to the clarifying questions about the emissions averaging provisions industry 

representatives had three requests for major modifications to the provision: 

o Expand the emission averaging provision to all pollutants, included D/F and CO. 

o Do not require a source to be 90% of the emission limit in order to qualify for 

emission averaging. This requirement is overly stringent, especially given the 

extremely low emission limits contained in the proposal. 

o Phase in the emission averaging period to be longer than 30 days after the limits 

being achieved at 30 days after the final rule. 

o Allow facilities to demonstrate compliance on a quarterly basis instead of 

monthly basis in order to adjust for seasonal operating variations and fuel 

variability. 

Stack Testing Frequency 

 Industry representatives were very concerned with costs and availability of qualified 

testing contractors to support the annual test frequency contained in the proposal. The 

representatives noted that although an annual frequency was included in the vacated 

standard, the new proposal requires testing of additional pollutants and longer test run 

times. In addition, the proposal does not include a health based compliance alternative 

which had dramatically reduced the number of facilities that were required to complete 

testing under the vacated standard. Industry representatives asserted that the numerous 

requirements for continuous monitoring and parametric monitoring are sufficient for 

demonstrating continuous compliance with the rule. Mr. Gossett noted that in contrast to 

the proposal, the hazardous waste combustor MACT requires testing every five years and 

the HON rule requires only an initial test. Mr. Gossett added that if gas 2 units remain 

subject to emission limits in the promulgated standard, the TNEastman facility will be 

conducting stack tests every 3 weeks. Industry representatives requested that EPA modify 

the testing frequency and suggested that they could adjust the frequency according to the 

size of the boiler. 

Continuous Compliance 

 Several industry representatives suggested that an SO2 CEMS should be allowed to 

demonstrate scrubber performance and as a surrogate for continuous compliance with the 

HCl limit. 

 Mr. Gossett indicated that although the monitor should not be required, EPA should 

provide facilities an option to demonstrate compliance with an Hg or HCl CEMS. 

 Several representatives disagreed with the provisions to maintain certain operating 

parameters to the values observed during performance tests. For example, parameters 

such as sorbent injection or slurry rates will vary with the load on the boiler. These 

parameters should be allowed to vary. 

 Mr. Lewis and Mr. Gossett both provided example barriers to implementing the proposed 

requirement of re-analyzing fuel every time the fuel type or fuel supplier is changed. Mr. 

Lewis noted that the biomass industry has numerous fuel suppliers and the blend of fuels 

that can change from one hog fuel pile to the next. Similarly, Mr. Gossett indicated that 
the TNEastman facility has an array of fuel suppliers since they participate in the coal 

spot market. Each supplier provides different shipments to the facility, for a total of 302 

different combinations of supplier and type of fuel in year 2009. Instead of re-analyzing 

the fuel at each change of fuel type or supplier the industry suggests a fuel analysis 

tracking plan that is unique to each facility in order to track the quality and quantity of 

fuels. The industry also suggested that the frequency of fuel analysis should be a monthly 

composite sample and that a 12-month rolling average should be incorporated in order to 

address natural fuel variability in the fuel. 

Energy Assessment 

 Several industry representatives expressed concerns that the facility-wide audit is outside 

of the scope of the Clean Air Act for this particular subpart.

 Industry also indicated that the costs of the audit were underestimated in the proposal. 

For example, the TNEastman facility indicated that a limited assessment of the utility 

plant/energy distribution systems at the plant (excluding any other process streams) cost 

the facility $1 million. Mr. Bessette indicated that the recent DOE beta testing program 

will have revised costs on the energy assessment for various types of facilities. 

 Several industry representatives indicated that if a facility were to conduct an audit or 

implement the findings of an energy audit the companies would need additional 

incentives, such as a significant extension to the compliance timeframe.