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Review of the Biomass Stoker CO Limits

and Suggestions for Revisions

Introduction

Some, but not all, companies operating boilers that are in the biomass stoker subcategory 

have concerns with the CO limit of 490 ppm at 3% O2. Compliance with this limit will

be determined with an annual Method 10 test with three runs of minimum one hour 

duration. It is widely acknowledged that biomass boilers have highly variable CO 

emission rates during normal operations, especially boilers that are load-following. 

Although the annual compliance test will most likely be carried out when the boiler is 

operating in a steady state condition at near full load (so that the operating load restriction 

of 110% would not limit boiler firing rates over the subsequent 12 months), there are still 

concerns that the 3-hour average CO levels observed during an annual test will on some 

occasion exceed the 490 ppm limit. Occasional exceedances would be expected to occur 

even on boilers where measures have been taken to minimize CO emissions. 

Additionally, there are a number of biomass stoker boilers with CO CEMS installed to 

meet a permitting requirement. These units will not be able to demonstrate continuous 

compliance with the 490 ppm limit, essentially a 3-hour average limit, given the widely 

known variability of CO concentrations from stoker design boilers. Companies operating 

such boilers would like EPA to set an alternative CO limit for an averaging time much 

longer than 3 hours and base compliance on CEMS data. The forest product industry 

supports EPA’s decision not to require CO CEMS as a compliance requirement in the 

Boiler MACT given the availability of other compliance demonstration options, however, 

giving facilities compliance options and alternative limits will provide the flexibility 

needed to account for the wide range of boiler operations, fuel mixes and equipment 

configurations.

The new source limit for the biomass stoker subcategory is 160 ppm at 3% O2, with 

compliance to be determined by an annual Method 10 stack test. This limit will be even 

more challenging to consistently meet. EPA has predicted no new biomass boilers 

subject to the Boiler MACT rule will be built in the future. This is not a realistic 

prediction, as currently there are a number of proposed biomass boilers in the permitting 

process. 

Previous Dialogue with EPA 

Over the last three months, industry representatives have discussed these concerns with 

EPA technical staff and management. There appears to be some willingness on the part 

of EPA to consider adjusting the current CO limit for biomass stokers and to develop an 

alternative limit for stokers equipped with CO CEMS. EPA feels such revisions cannot 

be justified by the CO data they presently have, and therefore have challenged industry 

stakeholders to provide additional data to support their desired changes to the limits. 

EPA set a July 15 deadline for receiving additional data due to the extremely ambitious 
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schedule set by EPA management . The schedule calls for issuance of a proposal for 

changes to the Boiler MACT and CISWI rules by October 31, 2011 and finalizing it by 

April 30, 2012. 

Given this schedule, EPA has been urging use of existing data rather than generation of 

new data. They feel constrained legally to only consider additional data from the small 

group of boilers in the biomass stoker MACT floor for CO, i.e. the so-called best 

performers. EPA’s current list of best performers in the biomass stoker subcategory is 

shown in Table 1. EPA Method 10 test data, as reported by the facilities and then 

adjusted by EPA to account for potential instrumental inaccuracies, were used to select 

the 12 best performers (12% of the 96 biomass stoker boilers in EPA’s emissions 

database with Method 10 data). To qualify as a best performer, at least 90% of the boiler 

heat input during the test had to come from biomass. 

There are problems with this list of top performers. First, there are several units in the 

stoker subcategory with an identical test result of 210 ppm, which is not the reported test 

value but rather a “maximum CO measurement error for biomass” number, as described 

in the ERG memo “Incorporating Measurement Error in Reported Carbon Monoxide and 

Total Hydrocarbon Data.” Only 6 of 13 units with a 210 ppm value were included in the 

top 12%; these seem to have been selected based on alphabetical order of the facility ID. 

This is arbitrary since 13 units were assigned an identical value. Second, six of the units 

apparently do not belong in the stoker subcategory. Third, the inclusion of 

WIFlambeauRiverPaper was based on a test conducted when the boiler was firing 100% 

coal. Fourth, the MSGPNewAugusta test was conducted while the boiler was firing more 

than 10% natural gas in addition to biomass.

EPA stated this list of top performers is subject to change depending on what new 

information they receive by July 15. Additional Method 10 tests from these or other 

biomass stokers, corrections to previously submitted test data, corrections of errors in 

boiler design information, and changing instructions from the Office of Resource 

Conservation and Recovery about what alternative fuels will be solid wastes, could alter 

the current list of best performers. 

EPA was informed that none of biomass stoker boilers on their current list of top CO 

performers had a CO CEMS, so any additional data for these units would have to come 

from new tests in the coming months. Industry representatives indicated a testing 

program involving installation of temporary CEMS on two or more of these boilers for a 

period of at least four months was under consideration. EPA noted the data from such a 

testing effort would not be available until March 1 at the earliest. This would require 

issuance of a Notice of Data Availability. Further, a placeholder for an alternative, 

longer-term CO standard would need to be adequately described in the October proposal 

to address any notice and comment issues that might arise since the data would be

submitted long after the close of the comment period on the proposed changes to the 

Boiler MACT rule. EPA would then need to amend the final rule if the data supported 
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Table 1. Lowest CO-Emitting Stokers Burning Biomass

Facility ID

Minimum 

Test 

Average

Data 

Type Rank

In Top 

12%?

NCASI Comments

MILPCSagola 68 ET 1 YES 2008 test. Has 6 additional tests for CO between 1997 and 2010. Company states 

unit has not been operated at full load due to PM limits. 

MNAndersonCorpBayport 93 ET 2 YES 2008 test. Additional tests in 2007 (163 ppmv) and 2008 (120 ppmv) on common 

stack with EU620 and EU621. Reportedly a suspension burner, not a stoker.

MNAndersonCorpBayport 99.5 ET 3 YES 2008 test. Additional tests in 2007 (163 ppmv) and 2008 (120 ppmv) on common 

stack with EU620 and EU621. Reportedly a suspension burner, not a stoker.

WVWeyerhaeuserBuckhannon 100 ET 4 YES 2005 test with reported average of 23 ppmv. Additional test from 2010 with average 

of 238 ppmv.

WIFlambeauRiverPaper 108 ET 5 YES Test conducted with 100% coal. Other tests conducted with 100% biomass, but 

results all above 210 ppmv. 

MSGPNewAugusta 130 ET 6 YES

2007 test; reported average 102 ppmv. Test report shows natural gas provided more 

than 10% of the heat input during the CO test runs. 122 days (10/1/10-1/31/11) of 

continuous CO data available from temporary instrument while firing over 90% 

biomass.

ARWestFraserHuttig 210 ET 7 YES 2005 test; reported average 65 ppmv 

IDChilcoLakeSawmill 210 ET 8 YES 2005 test; reported average 51 ppmv 

IDRileyCreekLumber 210 ET 9 YES 2003 test; reported average 161 ppmv

INConsolidatedGrainandBarge 210 ET 10 YES 2008 test on common stack for units P17B and P17C; reported average 87 ppmv

INConsolidatedGrainandBarge 210 ET 11 YES 2008 test on common stack for units P17B and P17C; reported average 87 ppmv

MNWeyerhaeuserIronton 210 ET 12 YES Company says boiler should be classified as a fuel cell; mill currently idle.

MSHoodBeaumont 210 ET 13 NO 2006 test with reported average of 128 ppmv. Also a 2008 test with average of 422

ppmv. Additional test conducted in 2010, reported average of 598 ppm.

MSIPVicksburg 210 ET 14 NO

2007 test; reported average 198 ppmv. Test report shows natural gas and TDF 

provided more than 10% of heat input during test. Also tests in 2005, 2006 with 

averages of 313, 298, and 367 ppmv. 

MSShuqualakLumber 210 ET 15 NO 2006 test with reported value of 122 ppmv; appears to be a single run. Boiler not of 

stoker design – package unit; tangentially fired watertube. 

OHAkronThermalEnergy 210 ET 16 NO 2007 test; reported average of 129 ppmv.

ORStimsonLumberForestGrove 210 ET 17 NO 2007 test on common stack for 3 boilers burning resinated wood. Also have 2006 

test. Company states the 3 boilers are pile burners, not stokers.

ORStimsonLumberForestGrove 210 ET 18 NO 2007 test on common stack for 3 boilers burning resinated wood. Also have 2006 

test. Company states the 3 boilers are pile burners, not stokers.

ORStimsonLumberForestGrove 210 ET 19 NO 2007 test on common stack for 3 boilers burning resinated wood. Also have 2006 

test. Company states the 3 boilers are pile burners, not stokers.

MNDESPHansONyman EU007 215 ET 20 NO 2007 test.
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changes to the CO limits for biomass stoker boilers or establishment of a longer term CO 

limit for units with existing CEMS.

When queried about the use of existing CO CEMS data to determine if boilers other than 

those on EPA’s current list might be best performers, EPA staff opined there would have 

to be a significant portion of 3-hour averages that were at or below those of the best 

performers (which would presumably be an average of 210 ppm at 3% O2 or less 

considering the current group of best performers). In addition, the boiler would have to 

be firing at least 90% biomass during the 3-hr periods when CO was less than 210 ppm.

The CO and O2 CEMS would have to meet the QA/QC provisions of EPA Performance 

Specifications 4 and 3, respectively, for the data to be acceptable to EPA. 

Analyses and Data to Support Revision of the 3-Hour Limits

Prior to undertaking any analyses, boilers in the top 12% must be identified. As 

described in the January 2011 revised MACT floor analysis ERG memorandum, there 

were 96 biomass boilers in the “stoker/sloped grate/other” subcategory with Method 10 

CO tests presumably conducted when at least 90% of the heat input came from biomass. 

Using the lowest Method 10 test for each of these units, the units were ranked from 

lowest to highest and the 12 units with the lowest test results (as adjusted by EPA to 

account for instrument accuracy) were selected as being in the MACT floor for this 

subcategory (12% of 96 units with data). If the Method 10 test was conducted on a stack 

serving two or more stoker boilers, EPA treated the test result as representing the 

emissions from each boiler.

The top 12 units are listed in Table 1. We believe the following units do not belong in 

the stoker/sloped grate/other subcategory: 

• MNAndersonCorpBayport (2 boilers; both should be in suspension subcategory)

• MNWeyerhaeuserIronton (should be in fuel cell subcategory; company informed 

EPA and ERG of this fact in May 2011)

WIFlambeauRiverPaper should be removed since their lowest test was conducted while 

burning 100% coal. MSGPNewAugusta should be removed since less than 90% of the 

heat input came from biomass during the only CO test.

Although not on the top 12 list, the three units at ORStimsonLumberForestGrove should 

be in the Dutch oven/suspension subcategory. The MSIPVicksburg boiler should be 

removed since the 2007 test was conducted when less than 90% of the boiler heat input 

came from biomass. The 2008 survey response from this facility inadvertently omitted 

TDF from the list of fuels burned during the various CO tests. Corrections are being 

submitted to EPA. 

If the six non-stoker boilers are removed from the subcategory, and MSIPVicksburg is 

removed from the boilers that have CO test data while firing over 90% biomass, it would 

leave 89 units having Method 10 test data and thus there would only be 11 units in the top 

12%. With the removal of MSGPNewAugusta, there would only be 10 remaining boilers 

in Table 1 with a CO test having an average of 210 ppm or less. According to the ERG 
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floor memorandum, the next lowest average was 215 ppm for the 

MNDESPHansONyman EU007 boiler, so this unit would have to be added to the best 

performer list.

Effect of Revised List of Top Performers

Using only Method 10 test data contained in the EPA emissions test database for the 

revised group of 11 biomass stoker units having at least one Method 10 test average of 

215 ppm or less, and using the statistical procedures described in the January 2011 

revised MACT floor analysis ERG memorandum, the 99.9% UPL would be 474 ppm at 

3% O2 (log normal distribution with Bhaumik and Gibbons correction). Note this 

calculation includes an additional test for MSHoodBeaumont (2008).

Effect of Additional Method 10 Tests for Best Performers

NCASI has learned there are additional Method 10 tests not in the EPA emissions 

database for three of the remaining best performers. There are six additional tests for 

LPCSagola (1997, 2000, 2002, 2005{two}, and 2011 compliance tests), one for 

WVWeyerhaeuserBuckhannon (2010 compliance test), and one for MSHoodBeaumont 

(2010 compliance test). Incorporating these tests into the 99.9% UPL calculations 

described in the previous section gives a 99.9% UPL of 720 ppm. 

Since LPCSagola is the best performer in the subcategory, the additional Method 10 tests 

on this unit will alter the new source limit for the subcategory. Incorporating these tests 

into the 99.9% UPL calculations for log normal distribution with Bhaumik and Gibbons 

correction gives a 99.9% UPL of 823 ppm. 

Effect of Statistical Procedures 

In calculating the 99.9% UPL which was the basis for the 490 ppm limit, EPA used 

individual Method 10 runs from 16 different tests conducted on the 12 best performing 

boilers. Each of the 48 runs was treated as an independent observation. When a Method 

10 test is conducted, the three runs are generally conducted within a three to four hour 

period and thus should not be viewed as producing independent samples – the three 1-hr 

runs will be highly auto-correlated. It would be more appropriate to treat each Method 10 

test average as an independent sample (refer to NCASI discussion paper on this topic 

submitted separately). If the 99.9% UPL is recalculated using the 16 test means as 

independent observations, the value would be 619 ppm at 3% O2 using a log-normal

distribution. 

Using the revised list of 11 best performers, the effect of using test averages instead of 

individual runs as independent observations would result in a 99.9% UPL of 652 ppm if 

only data currently in the EPA database were used, and 965 ppm if the additional tests for 

MILPCSagola, WVWeyerhaeuserBuckhannon, and MSHoodBeaumont were included. 

The new source limit using all data from MILPCSagola would be 1303 ppm.
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Effect of Adjusting CO Values to Account for Measurement Errors

A January 2011 ERG memorandum (Incorporating Measurement Error in Reported 

Carbon Monoxide and Total Hydrocarbon Data) stated the following:

Each test run for CO and THC was reviewed to determine if the maximum 

measurement error values needed to be incorporated in the data analysis for the 

MACT floor...If the reported emission concentration was lower than the 

measurement error for that test run, the default measurement errors were used in 

lieu of the reported concentration. For the units in Appendix A that had test 

reports available to extract a test-specific calibration span, the measurement error 

for this test was compared to the reported test run concentrations. For all 

remaining test data, the reported test run concentrations were compared to the 

appropriate default measurement error...

Default values for biomass boiler CO tests were 210 ppm for tests conducted through 

May 2008 and 160 ppm for tests conducted after May 2008.

Application of this procedure to Method 10 test data from biomass boilers resulted in 

nine boilers being assigned the default value of 210 ppm for all test runs. One unit was 

assigned a value of 100 ppm for its three runs (although a review of the 2005 test report 

for this unit indicates the CO span gas concentration was 100 ppm rather than 1000 ppm), 

and another 130 ppm for its three runs (see Table 1). 

Having so many runs with identical values affected the standard deviation calculated by 

EPA for the test data for the 12 best performing units. This fact undermines EPA’s claim 

that the variability in CO emissions was accounted for in the 99.9% UPL calculation 

since the standard deviation derived from run-by-run concentrations was used. EPA staff

promised to look into this situation and consult with their statisticians. They hoped they 

could get the stack test reports for the best performing units and determine the actual span 

gas concentrations used for the Method 10 tests so that the default values could be 

replaced. However, this would not adequately address the variability issue since the 

actual CO concentrations would still be unknown for many test runs.

Effect of Additional CO CEMS Data from Non-Best Performers

In the dialogue with EPA, EPA suggested CEMS data from non-best performers might be 

considered in revising the CO limit for biomass stokers if (1) the CEMS for CO and O2

met EPA QA/QC criteria, e.g. PS-4 and PS-3, annual RATAs, periodic calibration and 

drift tests, (2) a significant fraction of the 3-hr block averages were at or below the 

concentrations measured in Method 10 tests by the best performers, and (3) at least 90% 

of the boiler heat input came from biomass during each 3-hr average.

There are at least 26 stoker boilers that burn biomass in the forest products industry with

CO CEMS. Although these boilers would likely be in the biomass subcategory because 

10% or more of their annual heat input comes from biomass, most do not continuously 

get over 90% of their heat input from biomass. Some combust sludge, TDF, resinated 

wood, urban hog fuel, or OCC rejects, and the status of such materials under the solid 
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waste definition rule is uncertain. Also, it is not known how many of monitors satisfy 

PS-4 and other QA/QC requirements. NCASI is gathering more information about these 

monitors to see what data meeting EPA’s three criteria can be obtained. 

Outside of the forest products industry, there are at least 18 biomass stoker units operated 

by electricity generating firms with CO CEMS. The majority of the boilers are at 

facilities which are not major sources of hazardous air pollutants, or the boilers burn 

secondary biomass materials that may be classified as solid wastes. We understand EPA 

will not use any data from boilers that will be subject to GACT or CISWI standards to set 

MACT limits. NCASI is trying to determine which of these units will be subject to the 

MACT standards and would have CEMS data meeting EPA’s three criteria. 

To date, NCASI has obtained two sets of CO CEMS data that should meet EPA’s criteria. 

These data are described and analyzed in the next two paragraphs to illustrate how such 

CEMS information might be employed for revising the current 490 ppm standard for this 

subcategory.

One year (1-1-2010 to 12-31-2010) of hourly CO CEMS data was obtained for the 

WABoiseWallula boiler that burned hog fuel and natural gas (78% biomass annual 

average). This is a 1979 vintage stationary grate, mass feed stoker unit that had an 

overfire air system installed about 5 years ago. Located at a kraft pulp and paper mill, it 

is a load-following boiler with a steaming capacity of 235,000 lb/hr on hog fuel. The CO 

limit is 500 ppm at 7% O2, rolling 12 month average. The CO and O2 stack monitors are 

located after a wet ESP. After eliminating hourly averages corresponding to 

startup/shutdown conditions and CEMS malfunctions (about 3.3% of the hourly 

averages), three-hour block averages were computed. Of the 2833 3-hr average blocks, 

123 (or 4.3%) corresponded to periods when biomass firing exceeded 90% of total heat 

input (rest gas), and 91 of these 123 (or 74%) were less than 210 ppm at 3% O2. The 

calculated 99.9% UPL value of all 2833 3-hour block averages was 810 ppm at 3% O2

(using log normal distribution with Bhaumik and Gibbons correction). The 99.9 

percentile value (4th highest of the block averages) was 979 ppm, and the highest was 

1022 ppm. 

One year (6-1-2010 to 5-31-2011) of hourly CO CEMS data was obtained for the 

Genesee Power Station boiler that burned 100% biomass at all times. The biomass 

usually included a small amount of used animal bedding (wood shavings with manure). 

This is a 1995 vintage tangentially fired stoker with a vibrating grate. It has a heat input 

capacity of 523 x106

Btu/hr and electricity generating capacity of 36 MW. During this 

period, electrical output fluctuated between 10 and 36 MW, generally on a diurnal basis. 

Add-on controls are an ESP and SNCR. The CO limit is 0.35 lb/106

Btu, 24-hr rolling 

average. Nearly 9.8% of the hourly values were eliminated (periods of startup/shutdown

or no steam output, and CEMS malfunctions and calibrations) before computing threehour block averages. Of the 2657 3-hr average blocks, 1721 (or 64.8%) corresponded to 

periods when CO emissions were less than 210 ppm at 3% O2. The 99.9% UPL value of 

all 2657 3-hour block averages was 730 ppm at 3% O2 (using log normal distribution 
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with Bhaumik and Gibbons correction). The 99.9 percentile value (4th highest of the 

block averages) was 972 ppm, and the highest was 1539 ppm. 

Besides these two sets of CO CEMS data, four months of continuous CO data from a 

temporary CEMS were obtained for the MSGPNewAugusta boiler for the period October 

1, 2010 to January 31, 2011. (As noted earlier, the test result that put this boiler in the 

best performer group was conducted when less than 90% of the boiler heat input came 

from biomass.) The monitor was not certified. Minute-by-minute data were reduced to 

1-hr averages and corrected to 3% oxygen. A small amount of data (0.4%) corresponding 

to periods of instrument malfunction and calibration conditions were eliminated before 

computing three-hour block averages. During the entire four month period, with the 

exception of a two hour period when 100% gas was fired, over 90% of boiler heat input 

on an hourly basis came from biomass. The 99.9% UPL value of the 3-hour block 

averages (960 points) was 735 ppm at 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 found to be 928 ppm at 3% O2 (with

the Bhaumik-Gibbons correction). About 14% of the 3-hr block averages were less than 

210 ppm, the maximum level for the current (and revised) group of best performing 

biomass stokers.

The CEMS data illustrate a 3-hr stack test for CO on a biomass boiler could fall 

anywhere on a very broad spectrum of concentrations that occur over the course of 

normal operations. Even though EPA’s CO limit attempts to account for this known 

variability by being set at the 99.9% UPL based on individual run data from best 

performing units, the CEMS data from these three boilers, which could be considered as 

having similar CO emissions to those of the best performers, show a 3-hr average limit of 

490 ppm would be exceeded 3.2% of the time at Genesee, 5.5% of the time at Wallula, 

and about 10% of the time at New Augusta. Thus, a random 3-hr test would have a finite 

probability of being above 490 ppm. The results suggest EPA’s current database and 

statistical procedures have not resulted in a 3-hr average limit that could be achieved by 

the best performers during every stack test they will conduct.