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CIBO‐OMB Meeting

December 18, 2012

2:30 PM EST

Boiler MACT – Coal and Related Issues

COAL ISSUES:

1. HCl standard is too strict and costly.  Emission limit for existing sources can be raised (doubled)

by applying fuel variability factors (FVF) differently, i.e., do not remove incorrectly considered

“outliers” which are real data points for one of the top performers, and use 3 sigma to

determine the limit.  The resulting higher HCl limit could reduce compliance costs by $1 Billion

due to the ability of existing sources to utilize more cost‐effective dry sorbent injection (DSI)

control technology.

Illustrations of the problem:

Alternative HCl Control Cost Estimates

HCl Limit HCl Upgrade Cost

Alternate* HCl Upgrade 

Cost

Alternate HCl Upgrade Cost with 

Coal Chloride Cap of 0.12%**

0.022 $3.1B $2.8B $2.2B 

0.04 $2.9B $1.9B $1.9B 

0.05 $2.8B $1.8B $748M 

0.06 $2.7B $912M $704M 

*Assume sorbent injection if have ESP and need 50% control or have FF and need 80% 

control.

**0.095 lb/MMBtu HCl
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Top Performer Maximum Fuel Variability Factors and Number of Analyses

Count Max

ARAnthonyForestProductsSN-12 9 2.34

EastmanBoiler 30 1322 3.80

GAGPMadisonPly800 Wood Waste Boiler 12 0.95

IAArchersDanielsMidlandDesMoinesAsea 

Boiler #1 12 1.03

IARoquetteAmericaCirculating Fluidized Bed 

Boiler (121) 11 2.03

INAlcoaWarrickUnit #3 21 1.19

MSWeyerhaeuserBruceAA-002 No. 2 Boiler 15 1.41

NDCargillWestFargoFoster Wheeler Boiler 

(EU43) 9 1.00

SCCogenSouthB001 - Main Boiler 9 1.12

SCMarlboroPaperHogged Fuel Boiler 12 0.92

VASmurfitStoneWestptPB08 25 1.04

VAUniversityofVirginia7103-1-01R 9 0.91

WINewPageBironB24 9 2.14

Max FVF = 3.8
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CIBO Suggested Method to Determine FVF for HCl, Solid Fuel Boilers:

0.00

1.00

2.00

3.00

4.00

5.00

6.00

7.00

1/26/2006 1/26/2007 1/26/2008 1/26/2009 1/26/2010

Eastman

Boiler 30

HCl Ratios (Sample/Stack Test)

Ratio
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Conclusion:  Use of all legitimate fuel quality data for the top performers and use of 3 sigma to

determine FVF (results in FVF similar to maximum FVF for top performers) instead of EPA method

using average FVF with “outlier” omission would increase the HCl emission limit for existing solid fuel

fired sources and thereby allow many sources to utilize DSI as a more cost effective control and

reduce compliance cost by $1 Billion in capital while still achieving a high percentage reduction of HCl

emissions.

2. CO numerical standards are too tight and will cause unnecessary costs.  EPA projects only $65 M

in capital costs; CIBO predicts ~$1 B. A work practice approach similar to utility MATS is

appropriate for coal fired units using the EPA pilot study report as technical justification.  CO

oxidation catalysts will not reduce organic HAPs (emissions are extremely low to begin with), but

will increase NO2 emissions (NO converts partly to NO2 across the catalyst reactor).  Elimination

of the CO limits and use of a work practice could reduce cost of compliance by another

$1 Billion.

Secondarily, if CO limits remain in the final rule, strong support for CO limits not lower than

100 ppmvd at 7% O2.  There is no correlation of organic HAPs with CO at levels less than 100

ppmvd.  

3. Reinforce CIBO’s prior arguments to allow converted coal‐to‐gas boilers to be included in

emissions averaging.  Scrubbed coal fired boilers will have ND HCl emissions just like a converted

boiler.  This does not detract from the EPA position to allow a work practice approach for Gas 1

units.   

 Emissions averaging for repowered boilers (e.g., coal units converted to 100% natural gas)

could provide cost‐effective compliance flexibility and additional emission reductions.

 Subcategory of a boiler upon the proposed rule publication date (December 23, 2011)

should determine its subcategory relative to emissions averaging.  For example, a coal fired

boiler as of that date that is converted to 100% natural gas firing after that date should be

included within the emissions averaging methodology for solid fuel fired boilers.  

 Conversion of a coal fired boiler to natural gas should allow use of 3 x Reference Method

detection limit (DL) emission rates to be used for that converted boiler in the emissions

average if one‐time actual HCl emissions are < DL.  

 A converted boiler would thereafter be treated as a Gas 1 boiler with work practices

including required tune‐ups, etc.

 Emissions averaging should be allowed across subcategories‐there is precedent in other

MACT rules (e.g., Hazardous Organic NESHAP).
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4. Compliance time is critical.  There are many situations which will require as much time as

possible for compliance:

 Many existing coal fired boilers will be converted to natural gas firing or replaced with gas

fired boilers.  One CIBO member has estimated that it is possible that up to half of the

existing coal fired boilers could be converted to natural gas firing or replaced with gas fired

boilers.  This will put a major strain on equipment suppliers and all associated support

entities.

 Siting and permitting of new gas fired boilers to replace existing coal fired boilers is not as

easy as it may seem‐ some facilities will need to add a gas pipeline hook‐up or expand the

capacity of an existing pipeline to the facility.  Gas transportation/distribution pipeline

installations or upgrades typically rely on local gas distribution companies or other entities

and could require obtaining right‐of‐ways or be required to pass other regulatory hurdles.   

 More time will be needed for compliance.  Three years could be sufficient in a world with no

competition for skilled engineering, materials and construction labor resources.   

 The CAA mandates three years for compliance, but allows EPA the discretion to add a fourth

year.

 Industrial facilities and universities will be in direct competition with electric utilities for

limited supply of engineering, fabrication and construction resources.

o Supply and demand:  Prices will rise

o Some valuable engineering and fabrication work will be off‐shored

0

0.04

0.00007 0.0008 0

Emission Limit

0

0.005

0.01

0.015

0.02

0.025

0.03

0.035

0.04

0.045

Typical Uncontrolled

Coal Boiler

Detection Limit for

Scrubbed Coal Boiler

Detection Limit for

Gas Boiler

HCl Emission Rate

lb/MMBtu

Emissions Averaging

Debits and Credits for HCl

Scrubbed Coal Boiler vs. Repowered Coal Boiler

Credits

Debits
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 Congress never intended to force Industrial facilities and Universities to compete directly

with regulated utilities for the same resources.

 Strong encouragement to states should be provided by EPA to freely grant a one year

extension for unavoidable delays.  EPA should make it clear (e.g., with preamble language)

that the fourth year for compliance should be essentially ”automatic“ for sources making

boiler modifications, installing emissions controls, or switching fuels.   

4a.  Effective date of rule should be 60 days after FR publication since it is a major rule (MATS

uses the 60 day effective date).

5. Boiler MACT startup/shutdown definition.  

 CIBO provided a recommended approach for management of startup and shutdown periods

in comments on the Reconsideration Proposed Rule; these were discussed in detail with

OAQPS.  

 Comments addressed the problem with trying to apply a one‐size‐fits‐all approach to

regulated units that are extremely diverse in design and operation.  

 Unit‐specific startup and shutdown procedures are most appropriate and provide flexibility

for sources to practically and safely operate units depending on the unique circumstances of

the facility and unit.  

o Procedures are reviewable, approvable, and enforceable.  

o Furthermore, states have much experience in approving and enforcing site specific

provisions for startup, shutdown, and malfunction. Most states have been doing this

since the 1970’s.  

 Procedures should be used as a guide for operations to purposefully move through the

startup and shutdown process.  

o Each startup and shutdown should be documented relative to elapsed time and

timing of actions prescribed in the procedures so problems can be identified and

corrected in a timely manner.  

o Deviations from procedures should be reported.  

 The startup/shutdown comments and issues are applicable to both BMACT and Area Source

units with applicable emission limits.  

Implications of Utility MATS Proposed Rule of Nov. 30, 2012 Startup/Shutdown Provisions Relative to

Boiler MACT:  Startup definition and Table 3 to Part 63 Subpart UUUUU

Startup definition:  Startup ends when EGU generates electricity that is sold or

used for any other purpose (including on site use), or the EGU makes useful

thermal energy (such as heat or steam) for industrial, commercial, heating, or

cooling purposes, whichever is earlier.

Table 3:  Once you start firing coal, residual oil, or solid oil‐derived fuel, you

must vent emissions to the main stack(s), and engage all of the applicable

control devices except limestone injection in FBC EGUs, dry scrubber, SNCR, and

SCR.  You must start your limestone injection in FBC EGUs, dry scrubber, SNCR,
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and SCR systems as expeditiously as possible, but in any case, when necessary

to comply with other standards applicable to the source that require operation

of the control devices.

 Stoker coal‐fired boilers that are not equipped with gas or oil burners begin the startup

process by distributing a layer of coal on the grate.  Then oil‐soaked (e.g.,

diesel/distillate/ULSD fuel oil) absorbent combustible materials, such as rags, mats, or

pads, are put on the grate and lit off.  As the materials ignite, more coal is spread over

the grate.  Therefore, if similar wording was used for stoker fired boilers, they would be

required to have at least one baghouse module open to the flue gas, resulting in acid

condensation, corrosion of the baghouse walls and ducts, and deterioration of the bags.  

This will result in longer term baghouse failure and loss of bag integrity, with associated

PM emissions.  The only logical option other than installing gas or oil burners would be

to install a sacrificial baghouse module (one or more) that would only be used for

startup purposes.  This is impractical for many boilers.

 Initial exit of thermal energy from a boiler or process heater is not a logical end of

startup since in most cases combustion and unit operation has not stabilized and

temperatures have not equilibrated.  If a boiler had full capacity to vent steam up to

stable operation, that might provide enough flexibility, but that provision is not always

provided and it would result is a cost impact for vented steam.  (Process heaters do not

have venting capability).

 If EPA intends to apply the MATS approach to Boiler MACT, that would not be a logical

outgrowth of prior rule language for Boiler MACT (or Subpart JJJJJJ).

 The CIBO recommended unit specific startup and shutdown procedure approach

avoids these pitfalls.

6. Need provision in emissions averaging to use something other than P90 for fuel concentrations

when we have a comprehensive sampling program.

 Emissions averaging requires 12 moving totals and requires use of P90 (90th percentile) for

chlorine and mercury concentrations (see 63.7522(f)).  P90 was developed to determine

compliance using 3 grab samples per month (see 63.7530(c)).  For 12 moving averages, the

mean should be used.  Example below is where Eastman compositely samples every train‐

load of coal at the mine loading station. Current provisions increase emissions by 2.3X.   

 We suggest a provision (shown below) to allow the permitting authority to address

alternative methods in the emissions averaging plan:

Er = Emission rate (as determined during the most recent compliance demonstration or

from continuous emissions monitoring systems) of particulate matter, hydrogen

chloride, or mercury from unit, i, in units of pounds per million Btu of heat

input.  Determine the emission rate for particulate matter, hydrogen chloride, or

mercury by performance testing according to Table 5 to this subpart, or by fuel analysis

for hydrogen chloride or mercury using the applicable equation in

§63.7530(c). Alternative equations and sampling and analytical plans for determining
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emission rate by fuel analysis may be proposed to and approved by the applicable

delegated authority as part of the implementation plan for emissions averaging

required in to §63.7522(i).

7. Need PM CEMS to be more like recent MATS proposal and PC MACT.

 EPA proposal is to require PM CEMS on large coal fired and combination fired boilers

burning more than 250 MMBtu/hr coal and use them as parametric monitoring setting

the maximum milliamp from the stack test.  Some form of certification is required

without forcing PS‐11.  This will severely restrict boiler operation.  Our belief is this

technology should be field tested on swing loaded industrial boilers before mandating

its use.  Would like at least consideration of more flexible requirements as in PC MACT

and current reconsideration proposal in MATS.

RELATED ISSUES:

1. The NHSM Fuel definition must allow for tire‐derived fuel, processed construction debris,

railroad ties, and other non‐hazardous materials with recoverable energy content traditionally

used as fuels to continue to be classified as fuels.

0

200

400

600

800

1000

1200

1400

1600

1800 Chlorine (ppm)

Impact of Use of P90 on Monthly Emissions

for Emissions Averaging (Eastman Data)

Monthly P90 Values

Monthly Means

Each sample is an ASTM

composite of a unit

train delivery

2.3X
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2. Need clarity that process gases being burned in combustion units (either for energy recovery or

as a result of control requirements under other regulations) are not solid waste.   

 Return of the 2000 CISWI “contained gaseous material” definition would provide regulatory

certainty and would be advanced further by including similar wording or references in the

final NHSM preamble.

 Not providing this level of certainty will exacerbate current confusion relative to use of

gaseous fuels such as landfill gas.  Without the 2000 wording in the final CISWI rule and clear

exclusion from NHSM consideration, future increased beneficial use of LFG in boilers and

process heaters will cease and continued use of LFG in existing boilers and process heaters

will decrease, leading to loss of environmental and economic benefits.