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 Comme nts on CISWI Proposal

 Several representatives requested that the Agency finalize the solid waste definition first, and then proceed with the CISWI and boiler ru lemakings 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 pr oposals, 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 firi ng 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 cleaningif these ovens cannot be exempted from the CISWI. The cost to purchase a new set of parts would be approximately $350,000 per y ear, 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 limit ed 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 co mbusts 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 material s 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 be ing 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 wast e 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 boile rs 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 th e rule for a waste maintenance plan or best practices to ensure that waste feeds are minimi zed 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 w ood products were two materials of concern representatives discussed with respect to the non-hazardous secondary materials

definition. Mr. Lewis noted that resinated w ood products, if classified as waste materials, will have a huge national impact on waste dis posal and economic impacts to the forest products industry. He added that resins ar e made of carbon, hydrogen and oxygen and

that there is no difference in stack emi ssions from resinated and non-resinated wood products. Mr. Lewis also referenced data th at 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 w aste 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 oftires. 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 w ith data quality used in the proposal. He indicated that industry has been submitting, a nd will continue to submit, corrections for adjusting data to the appropriat e 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 correcti ons, 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 Qua lity 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 sp ans 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 fact ors 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 comme nts. He indicated th at the Agency should request additional fuel variability data from the top performing units. Most fuel analysis data provided by the top performers had less th an 40 fuel samples. The facilities with the largest number of fuel samples for chlori ne [TNEastman (347 sampl es for chlorine) and INPurdue (71 samples for chlorine)] also show ed 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 com bustor 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 wast e combustor MACT calculates the upper prediction limit (UPL) of all of the fuel an alysis data from the top performing boilers. Next, the UPL is divided by the average (mean) of all of the fuel analysis data from thetop 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 emi ssion limits do not adequately account for variability with operations. Since the limits we re 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 ma jor 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 duri ng 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. Th e 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-det ect values. They suggested establishing a work practice until sufficient data is ma de 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 tec hnology vendors and they were unable to identify any performance data for D/F controls on industrial boilers. The only performance data available were from othe r 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 wo rk 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 definiti on 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 wher e 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 th is requirement be conducted on an ‘as applicable’ basis.

o Many facilities have natural gas meters in stalled per building but the meters are not specific to individual units. Therefor e 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 th reshold for low CO levels, below which combustion efficiency and NOx emissions are negatively affected.

Liquid Subcategory

 Mr. Deridder indicated that the dataset for th e 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 numeri cal 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 concer ns with the MACT floor analysis for

new sources:

o Can the Agency claim that limits estab lished 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 SO 2 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 subcategor ies 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, asopposed 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 fo r 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 annua l 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 ru le. 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 promulgate d standard, the TNEastman facility will be conducting stack tests every 3 weeks. Industr y 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 SO 2 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 m onitor 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 pe rformance 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 thatthe TNEastman facility has an array of fuel suppliers since they participate in the coal spot market. Each supplier provides different sh ipments 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 sugg ested that the frequency of fuel analysis should be a monthly composite sample and that a 12-month rolling av erage 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 th e 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 assess ment 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 exte nsion to the compliance timeframe.