1111 Nineteenth Street, NW, Suite 800 ▪ Washington, DC 20036 

202 463-2700 Fax: 202 463-2785 ▪ www.afandpa.org

222 Catoctin Circle SE, Suite 201 ▪ Leesburg, VA 20176 

 202-463-2766 Fax: 202-463-2791 ▪ www.awc.org 

 

 November 16, 2012 

The Honorable Lisa P. Jackson 

Administrator 

U.S. Environmental Protection Agency 

Ariel Rios Building 

1200 Pennsylvania Ave, N.W. 

Washington, D.C. 20460 

Petition for Reconsideration of 40 C.F.R. Part 98 Subparts C and AA; 

Petition for Rulemaking To Revise 40 C.F.R. Part 98 Subparts C and AA; 

Request for Correction Under Information Quality Act

Dear Administrator Jackson: 

By this letter the American Forest & Paper Association (AF&PA) and the 

American Wood Council (AWC) petition EPA, pursuant to section 307(d)(7)(B) of the 

Clean Air Act, for reconsideration and revision of 40 C.F.R. Part 98 (Mandatory 

Greenhouse Gas Reporting) Subpart AA (Pulp and Paper Manufacturing), specifically, 

the default emission factors for estimating emissions of methane and nitrous oxide from 

pulp mill chemical recovery furnaces. AF&PA and AWC also petition for reconsideration 

and revision of 40 C.F.R. Part 98 Subpart C (General Stationary Fuel Combustion 

Sources), specifically, the default emission factors for estimating emissions of methane 

and nitrous oxide from combustion of solid biomass fuels. These provisions were first 

promulgated in a rule published at 74 Fed. Reg. 56,260 (Oct. 30, 2009). 

Reconsideration pursuant to CAA section 307(d)(7)(B) is appropriate because 

newly available information—stack testing of greenhouse gas emissions from pulp mill 

recovery furnaces and biomass-fired boilers—demonstrate that the default emission 

factors for these units in Subparts AA and C substantially overstate typical emissions 

from these sources.1

 This information was not available during the rulemaking2, and it 

is of central relevance to the outcome of the rulemaking, because it goes to the 

accuracy of the greenhouse gas emission information that the Mandatory Greenhouse 

 

1

 See Appendix A to this petition, Methane (CH4) and Nitrous Oxide (N20) Emissions from 

Biomass-Fired Boilers and Recovery Furnaces. Technical Bulletin No. 998, and Appendix B to 

this petition, containing letters from the National Council for Air and Stream Improvement to 

Paul Noe, AF&PA and Robert Glowinski, AWC. 

2

 See Appendix B.
EPA Air & Radiation Docket (6102T) 

Docket ID No. EPA–HQ–OAR–2007–0492 

August 31, 2012 

Page 2 

Gas Reporting rule is intended to collect and it demonstrates the need for different 

emission factors from those contained in that rule. Under these circumstances, CAA 

section 307(d)(7)(B) requires EPA to reconsider these emission factors (“the 

Administrator shall convene a proceeding for reconsideration of the rule” (emphasis 

added)). In addition, AF&PA and AWC believe that there is other information, which 

arguably might not meet the criteria for a petition for reconsideration, but which supports 

revision of Subparts AA and C of the Mandatory Greenhouse Gas Reporting rule 

nonetheless and therefore is appropriately presented in a petition for rulemaking, as 

authorized by 5 U.S.C. § 553(e). AF&PA and AWC therefore ask that EPA consider the 

following as both a petition for reconsideration under CAA section 307(d)(7)(B) and, to 

the extent EPA believes that the information presented does not require reconsideration 

under CAA section 307(d)(7)(B), then as a petition for rulemaking under 5 U.S.C. § 

553(e).3

Summary of Requested Changes to the Mandatory Greenhouse Gas Reporting 

Rule 

Currently, 40 C.F.R. § 98.273 directs pulp and paper mills subject to the rule to 

estimate methane (CH4) and nitrous oxide (N2O) emissions from chemical recovery 

furnaces using default emission factors, specified in Table AA-1 to 40 C.F.R. Part 98 

Subpart AA, of 0.030 and 0.005 kg/mmBtu HHV, respectively. AF&PA and AWC 

petition EPA to reconsider and revise Table AA-1 to replace those default emission 

factors with emission factors of 0.0019 kg/mmBtu HHV for CH4 and 0.00042 kg/mmBtu 

HHV for N2O. The emission factors currently in the regulations are significantly higher 

than indicated by recovery furnace emission test data, including extensive recentlycompleted stack testing provided with this petition, and they are higher as well than 

emission factors used by various other governmental and nongovernmental 

organizations. The current EPA emission factors therefore result in a substantial 

overstatement of pulp and paper industry CH4 and N2O emissions from recovery 

furnaces. 

For that reason, AF&PA and AWC also request, pursuant to the Information 

Quality Act, that EPA correct its database and greenhouse gas emission inventory 

reports to reflect the fact that a more accurate estimate of recovery furnace emissions is 

approximately an order of magnitude lower than the emissions estimates that EPA 

 

3

 Because CAA section 307(b)(1) provides for judicial review of this type of EPA action only 

through a petition for review, filed in the court of appeals within 60 days after new information 

becomes available, AF&PA and AWC also plan to file today a petition for review of the 

Mandatory Greenhouse Gas Reporting rule, pursuant to CAA section 307(b)(1) and Rule 15(a) 

of the Federal Rules of Appellate Procedure, in the U.S. Court of Appeals for the District of 

Columbia Circuit.
EPA Air & Radiation Docket (6102T) 

Docket ID No. EPA–HQ–OAR–2007–0492 

August 31, 2012 

Page 3 

required pulp mills to submit under the Mandatory Greenhouse Gas Reporting 

regulation. 

Similarly, the emission factors in Table C-2 to 40 C.F.R. Part 98 Subpart C, 

which facilities burning solid biomass fuels are directed by 40 C.F.R. § 98.33(c) to use 

to estimate annual CH4 and N2O emissions, substantially overstate emissions measured 

in numerous stack tests of a variety of wood- and wood-residue-fired boilers. AF&PA 

and AWC therefore petition EPA to reconsider and revise Table C-2 of 40 C.F.R. Part 

98 Subpart C to replace the emission factors for combustion of “Biomass Fuels—Solid” 

of 0.032 kg CH4 and 0.0042 kg N2O per mmBtu with emission factors of 0.0049 

kg/mmBtu for CH4 and 0.0019 kg/mmBtu for N2O. 

Finally, AF&PA and AWC seek revision of Table AA-2 of 40 C.F.R. Part 98 

Subpart AA to clarify what pulp mills are supposed to report for lime kiln emissions 

(other than CH4 emissions from kilns burning natural gas). Formatting problems with 

that table have created and will create confusion unless it is revised. 

(Please note that this petition for rulemaking and request for correction of existing 

databases does not address questions of whether and in what fashion CO2, CH4, and 

N2O emissions from burning black liquor or solid biomass fuels should be counted as 

emissions of greenhouse gases, in light of the fact that the carbon contained in 

emissions from combustion of black liquor and wood and wood residue is part of the 

carbon cycle in which carbon dioxide is removed from the atmosphere through the 

process of photosynthesis. This petition concerns only how to estimate the mass of 

CH4 and N2O emitted from combustion of black liquor in pulp mill recovery furnaces, 

combustion of solid biomass, and operation of lime kilns at pulp mills.) 

New Emission Factors Would Better Reflect Stack Test Data 

Combustion of Pulping Liquor in Recovery Furnaces

The CH4 and N2O emission factors for pulp mill chemical recovery furnaces in 

Table AA-1 to 40 C.F.R. Part 98 Subpart AA were selected from what we believe to be 

the most complete compilation of GHG emission rate estimates for pulp and paper mills: 

Calculation Tools for Estimating Greenhouse Gas Emissions from Pulp and Paper Mills, 

Version 1.1 (July 8, 2005), prepared by the National Council for Air and Stream 

Improvement, Inc. (NCASI), in association with the Climate Change Working Group of 

the International Council of Forest and Paper Associations, for the World Resources 

Institute and World Business Council for Sustainable Development Greenhouse Gas 

Protocol Initiative (the “WRI/WBCSD Greenhouse Gas Protocol Calculation Tools”). 

That document collected information on recovery furnace emissions of CH4 and N2O, 

and emission factors used to estimate those emissions, from Finland, Sweden, and 

Japan and from the European Environment Agency. See WRI/WBCSD Greenhouse 
EPA Air & Radiation Docket (6102T) 

Docket ID No. EPA–HQ–OAR–2007–0492 

August 31, 2012 

Page 4 

Gas Protocol Calculation Tools p. 29 Table 8. It recommended that recovery furnace 

GHG emissions be estimated using emission factors of 2.5 kg/TJ CH4 and 2 kg/TJ N2O, 

reflecting the median of emission factors derived from those sources. Id. at 28-29. 

For the Mandatory Greenhouse Gas Reporting Rule, however, EPA used the 

highest emission factor for both CH4 and N2O suggested by any of the references it 

cited (converted from kg/TJ to kg/MMBtu), rather than using the median values. The 

emission factors EPA chose, from a 2004 report by the Swedish Environmental 

Protection Agency, were 5-10 times higher than the emission rates collected from 

Finland and Japan, and for CH4 the emission factor of 30 kg/TJ EPA used is almost two 

times higher than even the high end of the range of emissions reported by the European 

Environment Agency. See id. Table 8 and June 16, 2011 e-mail from Sean P. Hogan, 

EPA Office of Atmospheric Programs, to Rhea Hale, AF&PA (reproduced in Appendix C 

to this petition).4

Similarly, the 30 kg of CH4 per TJ emission factor EPA used to set the reporting 

requirement for recovery furnaces in the Mandatory Greenhouse Gas Reporting Rule is 

10 times higher than the default emission factor for black liquor combustion derived for 

the latest inventory reporting guidance issued by the Intergovernmental Panel on 

Climate Change (3 kg/TJ), and it is almost twice as high as the highest end of the range 

of the emissions reported in that guidance (1-18 kg/TJ). See 2006 IPCC Guidelines for 

National Greenhouse Gas Inventories, Vol. 2, p. 2.19 Table 2.3 (available online at 

http://www.ipccnggip.iges.or.jp/public/2006gl/pdf/2_Volume2/V2_2_Ch2_Stationary_Combustion.pdf). 

Likewise, the emission factor EPA used in the Mandatory Greenhouse Gas Reporting 

Rule for N2O, derived from an assumed emission rate of 5 kg N2O per TJ, is more than 

double the default emission factor for black liquor combustion in the latest IPCC 

guidance. See id. It is important to note that EPA was an active participant in IPCC’s 

development of recommended emissions factors, and yet in the Mandatory Greenhouse 

Gas Reporting Rule EPA ignored the results of that process and chose emission factors 

much higher than the emission factors recommended by IPCC. 

 

4

 Significantly, the pulp and paper industry has not been able to obtain any justification for the 

very high Swedish EPA emission factors that EPA chose as the basis for the default emission 

factors for recovery furnaces in the Mandatory Greenhouse Gas Reporting Rule. Inquiries by 

NCASI and by AF&PA members with operations in Sweden have been unsuccessful in finding 

the source of that emission factor, and it appears that the Swedish EPA official responsible for 

preparing the cited report is now deceased. This lack of documentation for emission factors that 

are much higher than the emission factors reported by others is further justification for not 

choosing those values for purposes of estimating annual U.S. emissions from pulp and paper 

mills.
EPA Air & Radiation Docket (6102T) 

Docket ID No. EPA–HQ–OAR–2007–0492 

August 31, 2012 

Page 5 

 The current default CH4 and N2O emission factors for burning spent pulping 

liquor in the Mandatory Greenhouse Gas Reporting Rule thus are based on an outlier, 

with the express purpose of overstating those emissions so that the emission factors 

would be “conservative.” See June 16, 2011 e-mail from Hogan. As such, they almost 

certainly result in a large overstatement of annual CH4 and N2O emissions from pulp mill 

chemical recovery furnaces. The emission factors AF&PA and AWC seek in this 

petition for rulemaking would provide a much better estimate of those emissions, as the 

IPCC and others have recognized. 

The compilation of emissions data and emissions factors in the 2005 

WRI/WBCSD Greenhouse Gas Protocol Calculation Tools reflect relatively few recovery 

furnace stack tests. A recent NCASI review of subsequent literature indicated that there 

still is a dearth of accurate and direct emission measurements of CH4 and N2O 

emissions from recovery furnaces, especially those located in North America.5 Because 

of the growing interest in CH4 and N2O emissions, NCASI conducted what may be the 

most extensive testing to date of recovery furnace CH4 and N2O emissions, reported in 

the enclosed NCASI Technical Bulletin, Methane (CH4) and Nitrous Oxide (N2O) 

Emissions from Biomass-fired Boilers and Recovery Furnaces (September 2012) 

(“Technical Bulletin 998”), Appendix A to this petition. That report, released September 

18, 2012, is the basis for this petition for reconsideration. 

NCASI obtained data on CH4 and N2O emissions from five direct contact 

evaporator (DCE) recovery furnaces and three non-direct-contact evaporator (non-DCE 

or NDCE) recovery furnaces at six kraft pulp mills, measured using Fourier transform 

infrared spectroscopy. (Recovery furnaces designed with direct-contact evaporation of 

weak black liquor and those with non-direct contact evaporators were expected to have 

somewhat different CH4 and N2O emissions, which was confirmed by the NCASI stack 

testing.) Multiple runs on multiple days were conducted at each recovery furnace, often 

over two or more days. 

In this extensive testing, both the mean and the median CH4 and N2O emissions 

from recovery furnaces were far less than the default emission factors in the Mandatory 

Greenhouse Gas Reporting Rule, Table AA-1 to 40 C.F.R. Part 98 Subpart AA. See 

Technical Bulletin 998 pp. 23, 27-28.

Because the default recovery furnace emission factors in the Mandatory 

Greenhouse Gas Reporting Rule do not distinguish between DCE and NDCE design 

recovery furnaces, AF&PA and AWC asked NCASI to analyze the data reported in 

Technical Bulletin 998 to determine the mean emission rate for CH4 and N2O for all 

 

5

 See Technical Bulletin 998, infra, pp. 1-2. 

 
EPA Air & Radiation Docket (6102T) 

Docket ID No. EPA–HQ–OAR–2007–0492 

August 31, 2012 

Page 6 

eight of the recovery furnaces tested. The results of that analysis are contained in 

letters from Vipin Varma of NCASI to Paul Noe of AF&PA and Robert Glowinski of AWC 

dated November 8, 2012 and included in Appendix B to this petition (the “Nov. 8, 2012 

Letter”). That analysis allows a direct comparison of the results of NCASI’s study of 

recovery furnaces emissions to the emission factors specified in the Mandatory 

Greenhouse Gas Reporting Rule, Table AA-1 to 40 C.F.R. Part 98 Subpart AA, and to 

those used by the IPCC and WRI/WBCSD. That comparison is shown in the table 

below. 

TABLE 1 

CH4 and N2O Emission Factors for Kraft Pulping Liquors, kg/mmBtu 

GHG IPCC WRI/WBCSD 

GHG Protocol 

EPA6 NCASI 

Study 

Mean 

(%RSD) 

NCASI Study 

Range 

Methane 

(CH4)

0.0030 0.0025 0.030 0.0019 

(190%) 

0.000042 – 

0.010 

Nitrous 

Oxide 

(N2O) 

0.0020 0.0020 0.005 0.00042 

(68%) 

0.00015 – 

0.00082 

Note that even the highest CH4 emission rate reported for any of the stack tests 

at any of the recovery furnaces tested was still only one-third of the default emission 

factor contained in the Mandatory Greenhouse Gas Reporting regulations (and only 

one-tenth for the more-common non-DCE recovery furnaces). See Table 1 and 

Technical Bulletin 998 pp. 23, 27-28. The highest N2O emission rate reported in any of 

the recovery furnace stack tests was only one-sixth of EPA’s default emission factor. Id. 

This further demonstrates how far the emission factors in the Mandatory Greenhouse 

Gas Reporting Rule depart from actual emissions data and from the goal of accurately 

estimating total annual industry emissions. 

 

6

 Emission factors specified in 40 C.F.R. pt. 98 subpt. AA Table AA-1. 
EPA Air & Radiation Docket (6102T) 

Docket ID No. EPA–HQ–OAR–2007–0492 

August 31, 2012 

Page 7 

On the basis of the extensive recent stack testing data reported in NCASI 

Technical Bulletin 998, as well as the emission factors derived by other organizations 

discussed above, AF&PA and AWC petition for revision of Table AA-1 to replace the 

default emission factors for burning kraft pulping liquor of 0.030 kg CH4 per mmBtu HHV 

and 0.005 kg of N2O per mmBtu HHV, with emission factors of 0.0019 kg/mmBtu HHV 

for CH4 and 0.00042 kg/mmBtu HHV for N2O.7

 

Combustion of Solid Biomass Fuels

NCASI also conducted stack testing of CH4 and N2O emissions at five boilers at 

pulp mills that fire wood (also referred to as “hogged fuel”) or bark. In some cases, the 

boilers burn a combination of wood or bark and other fuel, but during the stack testing 

approximately 90 percent of the heat input was from biomass fuels at each of these five 

boilers. NCASI supplemented its own stack tests with an analysis of stack test data 

collected by EPA in connection with development of Maximum Achievable Control 

Technology (MACT) standards for industrial, commercial, and institutional boilers and 

emission standards for commercial and industrial solid waste incineration (CISWI) 

sources. NCASI identified 19 boilers tested as part of the Boiler MACT rulemaking and 

three boilers tested as part of the development of CISWI standards that were deriving 

more than 80 percent of their heat input from wood or bark at the time of stack testing. 

See description of sources tested in Technical Bulletin 998 pp. 7-12. 

Technical Bulletin 998 thus presents perhaps the most comprehensive analysis 

to date of emissions from boilers burning solid biomass fuels. That analysis 

demonstrates that actual stack testing of emissions from boilers burning wood and 

wood residuals produces much lower measured emissions than the emission factors in 

Table C-2 to 40 C.F.R. Part 98 Subpart C – the factors that facilities burning solid 

biomass fuels are directed by 40 C.F.R. § 98.33(c) to use to estimate annual CH4 and 

N2O emissions. Mean CH4 emissions from the 27 boilers evaluated in Technical 

Bulletin 998 were 6.5 times lower than the factor in Table C-2, and the mean N2O 

emissions were less than twice as much as the factor in Table C-2. See Technical 

 

7

 Note that Table AA-1, in the current version of the Code of Federal Regulations, lists CH4 and N2O 

emission factors for North American Softwood but has blanks in the columns for those compounds for 

pulping liquor from the pulping of North American Hardwood and other furnishes. AF&PA understands 

that EPA’s intention is to use the same emission factors for CH4 and N2O for pulping all types of fibers (as 

other organizations have), and this is reflected in EPA’s response to GHG reporting Frequently Asked 

Questions Q678. (Note: Q678 incorrectly states that the problem is an “e-CFR misprint” and that the 

table is correct in the Federal Register. In fact, the Federal Register version also had blanks in the 

columns for CH4 and N2O emissions except for the row for North American Softwood. See 74 Fed. Reg. 

56,260, 56,465-66 (Oct. 30, 2009).) AF&PA requests that EPA fill in all of the rows in the CH4 and N2O 

columns of Table AA-1 with the emission factors of 0.0019 kg/mmBtu HHV for CH4 and 0.00042 

kg/mmBtu HHV, respectively, as justified in this petition for rulemaking. Leaving the other rows blank 

makes it unclear whether and how CH4 and N2O emissions are to be reported for other furnishes. 
EPA Air & Radiation Docket (6102T) 

Docket ID No. EPA–HQ–OAR–2007–0492 

August 31, 2012 

Page 8 

Bulletin 998 pp. 27-28. Significantly, even the highest N2O emission rate from any of 

the boiler tests was less than the emission factor EPA uses in Table C-2, and only two 

boilers had CH4 emissions (slightly) higher than the EPA emissions factor. See 

Technical Bulletin 998 pp. 22, 27-28. (Those relatively high CH4 emissions at two 

boilers definitely are outliers, as their CH4 emissions were approximately five times 

larger than those observed at the other biomass-firing boilers and resulted in a mean 

CH4 emission rate for all 27 boilers that is over four times larger than the median 

emission rate. See Technical Bulletin 998 pp. 22, 24, 28.) 

The stack test data presented and analyzed in Technical Bulletin 998 show that 

the emission factors for CH4 and N2O mandated by 40 C.F.R. § 98.33(c) and Table C-2 

result in a substantial overstatement of true emissions from boilers burning solid 

biomass fuels. Accordingly, AF&PA and AWC are hereby petitioning EPA to reconsider 

and revise Table C-2 of 40 C.F.R. Part 98 Subpart C to replace the emission factors for 

combustion of “Biomass Fuels—Solid (All fuel types listed in Table C-1)” of 0.032 kg 

CH4 and 0.0042 kg N2O per mmBtu, with emission factors of 0.0049 kg/mmBtu for CH4

and 0.0019 kg/mmBtu for N2O. 

The Existing EPA Emission Factors Are Inconsistent with Their Stated Purpose 

In discussing the benefits of the Mandatory Greenhouse Gas Reporting Rule, 

pursuant to Executive Order 12866, EPA described the purpose of the rule as collecting 

“complete and accurate economy-wide data on facility-level GHG emissions,” saying it 

is “essential” to have “accurate and timely information on GHG emissions.” 74 Fed. 

Reg. at 56,369. EPA said the emissions estimates reported pursuant to the rule would 

improve EPA’s “understanding of the relative emissions of specific industries,” and its 

“understanding of the factors that influence GHG emission rates.” Id. In the latest 

version of U.S. Inventory of Greenhouse Gas Emissions and Sinks 1990 – 2009 (April 

15, 2011), EPA 430-R-11-005, EPA claims that data resulting from the requirements of 

the Mandatory Greenhouse Gas Reporting Rule that major facilities calculate and report 

their emissions of CH4 and N2O “will be used in future inventories to improve the 

emission calculations through the use of these collected higher tier methodological 

data.” Id. p. 3-25. 

None of these stated purposes is accomplished by using default CH4 and N2O 

emission factors that deliberately and grossly overstate emissions. The best available 

information is that in most cases recovery furnace CH4 emissions are an order of 

magnitude less than what pulp mills are required to report under 40 C.F.R. § 98.273 and 

Table AA-1, and N2O emissions are less than half of what the rule requires mills to 

report. This produces an inaccurate picture of pulp mill CH4 and N2O emissions, both 

relative to other GHGs and relative to other sources of CH4 and N2O. 
EPA Air & Radiation Docket (6102T) 

Docket ID No. EPA–HQ–OAR–2007–0492 

August 31, 2012 

Page 9 

EPA’s goal of having an accurate picture of GHG emissions from pulp and paper 

mills relative to other industry sectors is not served by using emission factors that 

overstate CH4 and N2O emissions. Nor, obviously, do overly “conservative” CH4 and 

N2O estimated emission rates further EPA’s interest in understanding what factors 

influence (true) GHG emission rates. EPA’s use in the Mandatory Greenhouse Gas 

Reporting Rule of emission factors for CH4 and N2O that are much higher than the 

factors used by other countries, combined with EPA’s stated intention to use the results 

of reporting under that rule to “improve” EPA’s reporting of GHG emissions to the 

international community, will result in inaccurate comparisons of the GHG emissions of 

the United States to those of other countries. 

Both EPA and environmental activist groups have begun to use estimated GHG 

emissions as a justification for identifying source categories that they view as priorities 

for further GHG regulation, such as development of New Source Performance 

Standards. Requiring pulp and paper mills to report CH4 and N2O emissions that are far 

greater than suggested by most emission testing creates the potential for this allocation 

of regulatory resources to be based on an inaccurate estimate of GHG emissions from 

that sector. 

The revised CH4 and N2O default emission factors that AF&PA and AWC are 

seeking in this petition for rulemaking would alleviate these problems and would support 

EPA’s stated goals for the Mandatory Greenhouse Gas Reporting Rule. EPA should 

adopt these revised emission factors as soon as possible, so that they can be used in 

the next round of reporting and EPA and others can have a more-accurate picture of 

pulp and paper mill GHG emissions as soon as possible. EPA has recognized that it is 

appropriate to revise the requirements for estimating GHG emissions in the Mandatory 

Greenhouse Gas Reporting Rule “to better reflect new industry data and current 

practice.” 77 Fed. Reg. 63,538, 63,359 (Oct. 16, 2012) (granting petition for 

reconsideration of emission estimation methods in 40 C.F.R. Part 98 Subpart I filed by 

Semiconductor Industry Association). 

EPA does allow pulp mills to use site-specific emission factors for CH4 and N2O 

for recovery furnaces.8

 That does not, however, alleviate the problems described above 

and the need for the adoption of revised emission factors as requested in this petition 

for rulemaking. First, it is not clear from the regulations whether mills can depart from 

the default emission rates in any way other than using a site-specific HHV. See 75 Fed. 

Reg. at 79,127, 79,166. (The instructions for reporting GHG emissions from pulp and 

paper mills say to use “default or site-specific emission factors,” see 40 C.F.R. § 

 

8

 See 75 Fed. Reg. 79,092, 79,127 (Dec. 17, 2010) and 40 C.F.R. § 98.276(e). The regulations do not 

appear to allow site-specific emission factors for CH4 and N2O for biomass-fueled boilers, however. See 

40 C.F.R. § 98.33(c). 
EPA Air & Radiation Docket (6102T) 

Docket ID No. EPA–HQ–OAR–2007–0492 

August 31, 2012 

Page 10 

98.273(a)(3), but there is no further explanation of this other than the discussion of 

using a site-specific HHV.) But even if it is theoretically possible to rely on site-specific 

emission factors rather than the default emission factors presented in the regulations, 

EPA knows that most mills will use the default emission factors for purposes of reporting 

pursuant to the rule, rather than perform the costly stack sampling and reporting that 

presumably would be necessary to obtain approval of site-specific CH4 and N2O 

emission factors. Cf. 40 C.F.R. § 98.53 (requirements for determining site-specific N2O 

emission factor for Adipic Acid Production). The default emission factors must be 

revised for EPA to get accurate estimates of national CH4 and N2O emissions from the 

pulp and paper sector. 

The Proposed New Emission Factors Would Be Consistent with EPA Policy and 

Practice 

EPA obviously has used emission factors for estimating emissions in a wide 

variety of circumstances in the past. AF&PA and AWC are not aware of any 

circumstance in which EPA has estimated long-term emissions from individual facilities, 

much less total sector emissions for the country, based on the highest emission rate 

tested, rather than a better estimate of average emissions. In fact, the concept of using 

averages is inherent in much of the Mandatory Greenhouse Gas Reporting Rule. The 

reason is obvious: A source’s total annual emissions are equal to the number of 

operating days times the average emission rate per day, not times the maximum rate 

experienced on any day of the year. Likewise, total annual emissions for an industry 

sector cannot be estimated by assuming that all facilities were operating for the entire 

year at the highest emission rate measured at any facility. 

EPA has compiled emission factors for use in Clean Air Act programs since 1972 

(in a publication called AP-42 and in other databases). The EPA-OAQPS document that 

describes procedures for establishing emission factors for AP-42 explains why the 

emission factors EPA derives in other contexts are based on average emissions over 

numerous sources rather than peak short-term emissions from a single source, and why 

it is appropriate to use such emission factors for emission inventories.9

 EPA's emission 

 

9

 Procedures for Preparing Emission Factor Documents, November 1997, EPA-454/R-95-015, 

pp. 2-1 to 2-2. See also Guidance on the Recommended Procedures for Development of 

Emissions Factors and Use of the WebFIRE Emissions Factor Database - Review Draft, 

December 2010, available at http://www.epa.gov/ttn/chief/efpac/procedures/index.html, at p. 2-

1: “For most application purposes, users typically assume that an emissions factor represents 

the long-term average emissions for all facilities in a particular source category (i.e., the 

emissions factor represents a population average).” Id. at p. 2-2: “The emissions rate for the 

source, expressed in terms of mass of pollutant emitted per time unit (e.g., lb PM/hr), is 

calculated as the arithmetic average of the available, quality-assured test data.”
EPA Air & Radiation Docket (6102T) 

Docket ID No. EPA–HQ–OAR–2007–0492 

August 31, 2012 

Page 11 

factors development guidance does not suggest picking the high end of a range of 

values, as EPA did to derive the default CH4 and N2O emission factors required by the 

Mandatory Greenhouse Gas Reporting Rule for recovery furnaces, by picking the 

highest emission factor reported to be used or suggested by any organization.

 

The current default CH4 and N2O emission factors for black liquor combustion in 

Table AA-1 of the Mandatory Greenhouse Gas Reporting Rule are thus inconsistent 

with past EPA practice and guidance. The revised default emission factors requested in 

this petition for rulemaking would correct that. 

The CH4 and N2O emission factors for combustion of solid biomass fuels in Table 

C-2 of the Mandatory Greenhouse Gas Reporting Rule are based on emission factors 

contained in the 2006 IPCC Guidelines for National Greenhouse Gas Inventories. 

Unfortunately, that document does not explain how those emission factors were 

derived, so it is unclear whether they were intended to represent average emission 

rates or the highest rates measured. It is clear, however, that the CH4 emission factor 

for biomass-fired boilers in Table C-2 is almost three times higher than the comparable 

factor in the WRI/WBCSD Greenhouse Gas Protocol Calculation Tools. See Technical 

Bulletin 998 at 27. This suggests that the IPCC factor is not intended to represent a 

central tendency of the data but rather a high-end emission rate. As such, the IPCC 

CH4 emission factor (and therefore the factor in Table C-2 of the EPA rule) does not 

appear to represent an average emission rate that would be more appropriate for use in 

calculating annual U.S. emissions from biomass-fired boilers. The CH4 emission factor 

proposed in this petition does. 

The Proposed New Emission Factors Would Better Conform to the Information 

Quality Act and Other Directives Emphasizing the Importance of Using the Best 

Scientific Information 

Congress has evidenced a strong interest in assuring that federal regulations are 

based on the best scientific information available. That intention is demonstrated, for 

example, by the Information Quality Act, Section 515(a) of the Treasury and General 

Government Appropriations Act for Fiscal Year 2001, P.L. 106-554; 44 U.S.C. § 3516 

(notes) (“IQA”) The IQA requires that information disseminated by EPA be accurate, 

complete, reliable, and unbiased. See Office of Management and Budget, Guidelines 

for Ensuring and Maximizing the Quality, Objectivity, Utility and Integrity of Information 

Disseminated by Federal Agencies, 67 Fed. Reg. 8452 (Feb. 22, 2002) (“OMB 

Guidelines”). In particular, with respect to scientific information concerning 

environmental risks, EPA has recognized that the IQA requires EPA to present 

information that is based on the best available science, data, and supporting studies 

and is conducted in accordance with sound and objective scientific practices and 

methods. See Guidelines for Ensuring and Maximizing the Quality, Objectivity, Utility 

and Integrity of Information Disseminated by the Environmental Protection Agency, 
EPA Air & Radiation Docket (6102T) 

Docket ID No. EPA–HQ–OAR–2007–0492 

August 31, 2012 

Page 12 

EPA/260R-02-2008 (October 2002). Similar directives are contained in Executive Order 

13563 and in the President’s Memorandum for the Heads of Executive Departments 

and Agencies on ‘‘Scientific Integrity’’ (March 9, 2009). 

Directing pulp and paper mills to submit CH4 and N2O annual emissions data for 

chemical recovery furnaces that EPA knows are likely to greatly overstate true 

emissions, and then disseminating that information to the public as EPA did in January 

2012 with its first release of annual GHG emissions data reported under the Mandatory 

Greenhouse Gas Reporting Rule, is contrary to the IQA, the OMB Guidelines, and 

EPA’s own interpretation of its obligations under the IQA, as well as directives from 

President Obama. The same is true of requiring all facilities that combust wood and 

wood residuals to report CH4 and N2O annual emissions much higher than the 

extensive emission testing reported in Technical Bulletin 998 would support. Revising 

the CH4 and N2O emission factors as requested in this petition would correct that 

deficiency for emissions reports submitted after the rule is changed. 

For emissions reports submitted before the emission factors are revised as 

requested in this petition, and for any EPA annual emission inventory reports or other 

databases of greenhouse gas emissions, those reports and databases greatly overstate 

CH4 and N2O annual emissions from pulp mill recovery furnaces and biomass-fired 

boilers. AF&PA and AWC members are adversely affected by that overstatement of 

emissions, because it makes it appear as if pulp and paper mills, as well as other 

facilities combusting wood and wood residuals, are larger sources of CH4 and N2O than 

they actually are, and therefore these types of facilities may be improperly identified as 

targets for reductions in CH4 and N2O emissions by EPA and by other governmental 

and nongovernmental organizations. 

The information AF&PA and AWC seek to correct is the “Greenhouse Gas 

Reporting Program Data for Calendar Year 2010,” the availability of which was 

announced on January 11, 2012 and presented to the public at 

http://epa.gov/climatechange/emissions/ghgdata/index.html, any similar data presented 

for subsequent calendar years that is based on the same inaccurate emission factors 

contained in Table C-2 to 40 C.F.R. Part 98 Subpart C and Table AA-1 to 40 C.F.R. 

Part 98 Subpart AA, and any other EPA databases that rely on the same estimates of 

CH4 and N2O emissions reported by pulp and paper mills pursuant to the Mandatory 

Greenhouse Gas Reporting Rule, prior to the time that EPA revises the emission factors 

for CH4 and N2O as requested in the preceding petition for reconsideration/rulemaking. 

The errors in these emissions estimate data, the way the data fail to comply with the 

IQA and OMB and EPA guidelines for information quality, and the effects of the 

requested corrective action are all described above. AF&PA and AWC believe that it 

would be relatively easy for EPA to make the requested corrections, since the estimated 

biomass boiler and recovery furnace CH4 and N2O emissions used to generate the 

reports and databases for which correction is requested would only have to be adjusted 
EPA Air & Radiation Docket (6102T) 

Docket ID No. EPA–HQ–OAR–2007–0492 

August 31, 2012 

Page 13 

by multiplying those emissions by the ratio of the emission factor requested in the 

foregoing petition to the emission factor contained in Table C-2 to 40 C.F.R. Part 98 

Subpart C or Table AA-1 to 40 C.F.R. Part 98 Subpart AA. 

EPA Should Correct Table AA-2 in 40 C.F.R. Part 98 Subpart AA To Eliminate 

Confusion Caused by the Table’s Formatting 

In addition to the changes in the emission factors for recovery furnaces and 

biomass-fired boilers discussed above, AF&PA and AWC petition EPA for rulemaking to 

eliminate an ambiguity in the emission factors for kraft pulp mill lime kilns caused by the 

formatting of Table AA-2 in 40 C.F.R. Part 98 Subpart AA. Table AA-2 lists an emission 

factor of 0.0027 for CH4 emissions from lime kilns firing natural gas. The table has a 

blank for N2O emissions from lime kilns firing natural gas. For all the other listed fuels, 

Table AA-2 provides an ellipsis or row of about 25 periods for both CH4 and N2O.10 

There is no explanation in the table or accompanying portions of the regulation as to 

what these ellipses signify, or how it differs from the blank space in Table AA-2 for N2O 

emissions from kilns burning natural gas. Adding to the confusion, the title of Table AA2 indicates that the emission factors provided are for “fossil fuel-based CH4 and N2O,” 

and yet one of the rows of the table (for which the table gives ellipses in the columns for 

CH4 and N2O) is biogas, which of course is not a fossil fuel, raising the possibility that 

the ellipses have a different significance in that row of the table. 

It is therefore unclear whether mills should use an emission factor of 0 for CH4

emissions from lime kilns burning residual oil, distillate oil, petroleum coke, and/or 

biomass, or an emission factor of 0.0027, or should not report any number for CH4

emissions from those fuels. It is likewise unclear what mills should report (or not report) 

for N2O emissions from lime kilns. 

The format of Table AA-2 has caused difficulties for pulp mill operators and EPA 

alike. In at least one instance, EPA posted incorrect messages concerning lime kiln 

CH4 and N2O emission reporting in a pulp mill’s eGGRT account, later giving different 

instructions in an e-mail message. AF&PA members have sought clarification of the 

implications of Table AA-2 and have been told that the problem is just one of formatting 

in the eCFR, and that EPA’s intent is clear from the version of Table AA-2 in the 

proposed regulations published at 75 Fed. Reg. 48,744 (Aug. 11, 2010), on page 

48,811. But that version of Table AA-2 was no clearer, showing a 0.0027 in the CH4

column and a 0 in the N2O for lime kilns burning natural gas, but blanks in both the CH4

column and the N2O column for all other fossil fuels (and biogas). 

 

10 In contrast, Table AA-1 has blank spaces in the columns for CH4 and N2O emissions from the 

pulping of all types of fiber besides North American Softwood. 
EPA Air & Radiation Docket (6102T) 

Docket ID No. EPA–HQ–OAR–2007–0492 

August 31, 2012 

Page 14 

Obviously, the regulation as published is unclear and is causing confusion 

among both pulp mill operators and regulators. EPA should correct Table AA-2 to 

clearly indicate what default emission factor should be used for each pollutant for each 

type of fuel, or whether no emission number (not even 0) should be reported. 

* * * * * * 

 For the reasons set forth above, AF&PA and AWC urge you promptly to 

reconsider and revise the default emission factors for CH4 and N2O emissions from 

burning spent pulping liquor in chemical pulp mill recovery furnaces, in Table AA-1 to 40 

C.F.R. Part 98 Subpart AA, and for burning solid biomass fuels, in Table C-2 to 40 

C.F.R. Part 98 Subpart C, as described above. We also request prompt revision of 

Table AA-2 to make clear EPA’s intention about the default emission factors to be used 

in estimating CH4 and N2O emissions from lime kilns at pulp mills. 

If you have any questions about this petition for reconsideration/petition for 

rulemaking, please contact Ms. Nancy Clark, AF&PA’s Director, Climate and Air, at 

(202) 463-2709 or at Nancy_Clark@afandpa.org. 

 

 

Sincerely, 

 

Paul Noe 

Vice President for Public Policy 

American Forest & Paper Association 

Robert W. Glowinski 

President and CEO 

American Wood Council 

cc: Gina McCarthy, Asst. Administrator, Office of Air and Radiation 

 Sarah Dunham, Dir., Office of Atmospheric Programs
APPENDIX A 
ncasi

NATIONAL COUNCIL FOR AIR AND STREAM IMPROVEMENT 

METHANE (CH4) AND 

NITROUS OXIDE (N2O) EMISSIONS 

FROM BIOMASS-FIRED BOILERS 

AND RECOVERY FURNACES 

TECHNICAL BULLETIN NO. 998 

SEPTEMBER 2012

by 

J. Derek Sain 

NCASI Southern Regional Center 

Newberry, Florida 
Acknowledgments 

This study was conducted at NCASI’s Southern Regional Center where Ashok Jain is the Regional Manager. 

The study was coordinated by Derek Sain, Ashok Jain, and Lee Carlson. The report was written by Derek Sain 

with contributions from Vipin Varma and input from Brad Upton and Reid Miner. Assistance during the field 

sampling portion was provided by Lee Carlson, Zach Emerson, Ed Hopwood, and Bill Rice. Lab support was 

provided by Jim Stainfield. Database support was provided by Karen Mentz. This report was edited by Susan 

Kirkland. NCASI thanks all the companies who participated in the testing program and provided data from their 

Boiler MACT/CISWI testing for inclusion in this report. 

For more information about this research, contact: 

J. Derek Sain 

Senior Research Associate 

NCASI 

402 SW 140th Terrace 

Newberry, FL 32669 

(352) 331-1745, ext. 265 

dsain@ncasi.org

Dr. Vipin Varma 

Vice President, Air Quality 

NCASI 

402 SW 140th Terrace 

Newberry, FL 32669 

(352) 331-1745, ext. 260 

vvarma@ncasi.org

For information about NCASI publications, contact: 

Publications Coordinator 

NCASI 

P.O. Box 13318 

Research Triangle Park, NC 27709-3318 

(919) 941-6400 

publications@ncasi.org

Cite this report as: 

National Council for Air and Stream Improvement, Inc. (NCASI). 2012. Methane (CH4) and nitrous oxide (N2O) 

emissions from biomass-fired boilers and recovery furnaces. Technical Bulletin No. 998. Research Triangle Park, 

N.C.: National Council for Air and Stream Improvement, Inc. 

© 2012 by the National Council for Air and Stream Improvement, Inc. 
National Council for Air and Stream Improvement 

ncasi

serving the environmental research needs of the forest products industry since 1943 

PRESIDENT’S NOTE 

The Mandatory Reporting of Greenhouse Gases Rule (40 CFR Part 98), issued by the United States 

Environmental Protection Agency in 2009, requires the annual reporting of greenhouse gas data and 

other relevant information from large emissions sources. Under this rule, reporting is required of pulp 

and paper mills and other facilities with stationary combustion units where facility-wide greenhouse 

gas emissions from applicable sources are greater than 25,000 metric tonnes of carbon dioxide (CO2) 

equivalents (CO2 eq.) per year. Wood products facilities are also required to report if the aggregate 

maximum rated heat input capacity of stationary fuel combustion units at the facility is 30 MMBtu/hr 

or greater and the facility emits 25,000 metric tonnes CO2 eq. or more per year. While biogenic CO2

emissions are not considered when determining if a facility’s total emissions exceed the reporting 

threshold, emissions of methane (CH4) and nitrous oxide (N2O) from biogenic sources are 

considered. Emissions from most pulp and paper mills and a limited number of wood products 

facilities are expected to exceed these reporting thresholds. 

As part of this reporting requirement, pulp and paper mills have to report CH4 and N2O emissions 

from all fuels, both separated by fuel type and in aggregate. This requirement applies to emissions 

from stationary combustion devices, chemical recovery furnaces, and lime kilns. Given the limited 

data availability and uncertainty surrounding currently available emission factors, NCASI has carried 

out a study to develop additional data for CH4 and N2O emissions from biomass-fired boilers and 

kraft recovery furnaces. CH4 and N2O emissions from five combination boilers, five direct contact 

evaporator (DCE) recovery furnaces, and three non-direct contact evaporator (NDCE) recovery 

furnaces were measured using Fourier transform infrared spectroscopy (FTIR). Additionally, data 

on CH4 emissions from 22 biomass-fired boilers, obtained as part of the 2009 Boiler MACT/CISWI 

testing program, have been reviewed and summarized as part of this study. 

The emission factors developed from this study are generally lower than those in current use and are 

likely more reflective of current emissions from sources in North America. 

Ronald A. Yeske 

September 2012 

 

National Council for Air and Stream Improvement 

ncasi

serving the environmental research needs of the forest products industry since 1943 

NOTE DU PRÉSIDENT 

Le règlement sur la déclaration obligatoire des gaz à effet de serre (40 CFR Part 98) qui a été publié 

par l’Agence de protection de l’environnement des États-Unis (EPA) en 2009 oblige les grands 

émetteurs à produire une déclaration annuelle sur leurs émissions de gaz à effet de serre et à fournir 

d’autres renseignements pertinents. En vertu de ce règlement, les usines de pâtes et papiers et tout 

autre établissement ayant des unités de combustion stationnaires doivent produire une déclaration si la 

somme des émissions de gaz à effet de serre de toutes les sources applicables de l’établissement est 

supérieure à 25 000 tonnes métriques en équivalents CO2 par année. Les usines de produits du bois 

doivent aussi produire une déclaration si la somme de la capacité nominale maximale de chaque unité 

de combustion stationnaire de l’usine est égale ou supérieure à 30 MMBtu/h et si l’usine émet 25 000 

tonnes métriques ou plus d’équivalents CO2 par année. Bien que l’on ne tienne pas compte des 

émissions biogéniques de CO2 pour déterminer si les émissions totales d’un établissement excèdent le 

seuil de déclaration, il faut cependant tenir compte des émissions de méthane (CH4) et d’oxyde 

nitreux (N2O) provenant de sources biogéniques. On prévoit que les émissions de la plupart des 

usines de pâtes et papiers et celles d’un petit nombre d’usines de produits du bois dépasseront les 

seuils de déclaration. 

En vertu de ce règlement, les usines de pâtes et papiers doivent déclarer les émissions de CH4 et de 

N2O de tous les combustibles de deux façons : le total par type de combustible et le total pour 

l’ensemble des combustibles combinés. Cette exigence s’applique aux unités de combustion 

stationnaires, aux chaudières de récupération des usines de pâte kraft et aux fours à chaux. Compte 

tenu du peu de données existant dans la littérature et de l’incertitude entourant les facteurs d’émission 

actuels, NCASI a réalisé une étude pour générer des données supplémentaires sur les émissions de 

CH4 et de N2O provenant des chaudières à biomasse et des chaudières de récupération. NCASI a 

mesuré les émissions de CH4 et de N2O provenant de cinq chaudières à biomasse, cinq chaudières de 

récupération avec évaporateurs à contact direct (DCE) et de trois chaudières de récupération avec 

évaporateurs à contact indirect (NDCE) à l’aide d’un spectromètre infrarouge à transformée de 

Fourier (IRTF). De plus, NCASI a analysé les données sur les émissions de CH4 de 22 chaudières à 

biomasse obtenues dans le cadre du programme de caractérisation Boiler MACT/CISWI réalisé en 

2009, et a inclus un résumé de cette analyse dans la présente étude. 

Les facteurs d’émission développés dans le cadre de la présente étude sont généralement inférieurs 

aux facteurs présentement en usage et sont probablement plus représentatifs des émissions actuelles 

des sources d’émission en Amérique du Nord. 

Ronald A. Yeske 

Septembre 2012 

National Council for Air and Stream Improvement 

METHANE (CH4) AND NITROUS OXIDE (N2O) EMISSIONS FROM 

BIOMASS-FIRED BOILERS AND RECOVERY FURNACES 

TECHNICAL BULLETIN NO. 998 

SEPTEMBER 2012 

ABSTRACT 

NCASI conducted a study to quantify methane (CH4) and nitrous oxide (N2O) emissions from 

biomass-fired boilers and kraft recovery furnaces in order to develop emission factors for potential 

use in greenhouse gas (GHG) inventories. As part of this study, CH4 and N2O emissions from five 

biomass-fired boilers, five direct contact evaporator (DCE) recovery furnaces, and three non-direct 

contact evaporator (NDCE) recovery furnaces were measured using extractive Fourier Transform 

Infrared (FTIR) spectroscopy. Data on CH4 emissions from 22 biomass-fired boilers, provided in the 

2009 Boiler MACT/CISWI test reports, were also included in this study. For biomass boilers, average 

CH4 and N2O emissions were 0.0049 kg/MMBtu and 0.0019 kg/MMBtu, respectively. For DCE 

recovery furnaces, average CH4 and N2O emissions were 0.0024 kg/MMBtu and 0.00036 kg/MMBtu, 

respectively. In the case of NDCE recovery furnaces, average CH4 and N2O emissions were 0.0014 

kg/MMBtu and 0.00044 kg/MMBtu, respectively. Average emissions of CH4 and N2O were found to 

be lower than the default emission factors provided by EPA in the Federal Register [74 FR 56260] 

for use in GHG reporting calculations (solid biomass fuels: 0.032 kg CH4/MMBtu and 0.0042 kg 

N2O/MMBtu in Table C-2; softwood kraft pulping liquor: 0.030 kg CH4/MMBtu and 0.005 kg 

N2O/MMBtu in Table AA-1). 

KEYWORDS 

biomass boilers, boilers, combination boilers, GHG emission factors, GHGRR, greenhouse gas 

(GHG) emissions, methane (CH4), nitrous oxide (N2O), recovery furnaces 

RELATED NCASI PUBLICATIONS 

Technical Bulletin No. 984 (April 2011). Greenhouse gas and non-renewable energy benefits of black 

liquor recovery. 

Special Report No. 08-05 (September 2008). The greenhouse gas and carbon profile of the U.S. 

forest products sector. 

Special Report No. 07-09 (October 2007). The greenhouse gas and carbon profile of the Canadian 

forest products industry. 

Special Report No. 07-02 (February 2007). The greenhouse gas and carbon profile of the global 

forest products industry. 

Special Report No. 01-05 (December 2001). Technologies for reducing carbon dioxide emissions: a 

resource manual for pulp, paper, and wood products manufactures. 

Special Report No. 99-02 (June 1999). Estimating costs for the U.S. forest products industry to meet 

the greenhouse gas reduction target in the Kyoto protocol. 

 

National Council for Air and Stream Improvement 

ÉMISSIONS DE MÉTHANE (CH4) ET D’OXYDE NITREUX (N2O) PROVENANT 

DES CHAUDIÈRES À BIOMASSE ET DES CHAUDIÈRES DE RÉCUPÉRATION 

BULLETIN TECHNIQUE NO 998 

SEPTEMBRE 2012 

RÉSUMÉ 

NCASI a réalisé une étude pour quantifier les émissions de méthane (CH4) et d’oxyde nitreux (N2O) 

provenant de chaudières à biomasse et de chaudières de récupération (procédé kraft) afin de développer 

des facteurs d’émission pouvant servir éventuellement à établir des inventaires de gaz à effet de serre 

(GES). Dans le cadre de cette étude, NCASI a mesuré les émissions de CH4 et de N2O provenant de 

cinq chaudières à biomasse, cinq chaudières de récupération avec évaporateurs à contact direct (DCE) 

et de trois chaudières de récupération avec évaporateurs à contact indirect (NDCE) à l’aide d’un 

spectromètre infrarouge à transformée de Fourier (IRTF). NCASI a également inclus les données sur les 

émissions de CH4 provenant de 22 chaudières à biomasse contenues dans les rapports de caractérisation 

du programme Boiler MACT/CISWI réalisé en 2009. La valeur moyenne des émissions de CH4 et de 

N2O des chaudières à biomasse était 0,0049 kg/MMBtu et 0,0019 kg/MMBtu, respectivement. La 

valeur moyenne des émissions de CH4 et de N2O des chaudières de récupération avec évaporateurs à 

contact direct (DCE) était 0,0024 kg/MMBtu et 0,00036 kg/MMBtu, respectivement. La valeur 

moyenne des émissions de CH4 et de N2O des chaudières de récupération avec évaporateurs à contact 

indirect (NDCE) était 0,0014 kg/MMBtu et 0,00044 kg/MMBtu, respectivement. On constate que les 

valeurs moyennes des émissions de CH4 et de N2O sont inférieures aux valeurs des facteurs d’émission 

inscrits dans le registre fédéral [74 FR 56260] par l’EPA pour calculer les émissions de GES à déclarer 

(biomasse solide : 0,032 kg CH4/MMBtu et 0,0042 kg N2O/MMBtu dans le tableau C-2; liqueur usée 

de pâte kraft de résineux : 0,030 kg CH4/MMBtu et 0,005 kg N2O/MMBtu dans le tableau AA-1). 

MOTS-CLÉS 

chaudières, chaudières à biomasse, chaudières de récupération, émissions de gaz à effet de serre 

(GES), exigences de déclaration des GES, facteurs d’émission des GES, méthane (CH4), oxyde 

nitreux (N2O) 

AUTRES PUBLICATIONS DE NCASI 

Bulletin technique no

 984 (avril 2011). Greenhouse gas and non-renewable energy benefits of black 

liquor recovery. 

Rapport spécial no

 08-05 (septembre 2008). The greenhouse gas and carbon profile of the U.S. forest 

products sector. 

Rapport spécial no

 07-09 (octobre 2007). The greenhouse gas and carbon profile of the Canadian 

forest products industry. 

Rapport spécial no

 07-02 (février 2007). The greenhouse gas and carbon profile of the global forest 

products industry. 

Rapport spécial no

 01-05(décembre 2001). Technologies for reducing carbon dioxide emissions: a 

resource manual for pulp, paper, and wood products manufactures. 

Rapport spécial no

 99-02 (juin 1999). Estimating costs for the U.S. forest products industry to meet 

the greenhouse gas reduction target in the Kyoto protocol. 

National Council for Air and Stream Improvement 

CONTENTS 

1.0 INTRODUCTION ................................................................................................................... 1 

 1.1 Background .................................................................................................................... 1 

 1.2 Study Objectives ............................................................................................................ 2 

2.0 SAMPLING AND ANALYSIS METHODS ............................................................................ 2 

 2.1 FTIR .............................................................................................................................. 2 

 2.2 Boiler MACT/CISWI Testing ......................................................................................... 7 

3.0 SOURCE DESCRIPTIONS ..................................................................................................... 7 

 3.1 NCASI Testing ............................................................................................................... 7 

 3.2 Boiler MACT/CISWI Testing ....................................................................................... 12 

4.0 RESULTS ............................................................................................................................. 12 

 4.1 NCASI Testing ............................................................................................................. 12 

 4.2 Boiler MACT/CISWI Testing ....................................................................................... 20 

 4.3 Category Results .......................................................................................................... 23 

5.0 DISCUSSION ....................................................................................................................... 24 

 5.1 Category Results .......................................................................................................... 24 

 5.2 Drivers of Methane (CH4) and Nitrous Oxide (N2O) Formation and Emissions ............. 25 

 5.3 Existing Emission Factors ............................................................................................ 26 

6.0 CONCLUSIONS ................................................................................................................... 28 

REFERENCES ............................................................................................................................... 29 

APPENDICES 

 A Detailed Source Results ............................................................................................... A1 

 B Principles of FTIR Analysis.......................................................................................... B1 

 C Method Development ................................................................................................... C1 

National Council for Air and Stream Improvement 

TABLES 

Table 3.1 NCASI Testing – General Source Descriptions ............................................................. 10 

Table 3.2 Boiler MACT/CISWI Testing – General Source Descriptions ....................................... 11 

Table 4.1 Recovery Furnace (DCE) ARF3, kg/MMBtu ................................................................ 13 

Table 4.2 Bark Boiler ABB2, kg/MMBtu ..................................................................................... 14 

Table 4.3 Recovery Furnace (NDCE) BRF5, kg/MMBtu.............................................................. 14 

Table 4.4 Combination Boiler CCB4, kg/MMBtu ........................................................................ 15 

Table 4.5 Recovery Furnace (NDCE) DRF1, kg/MMBtu ............................................................. 16 

Table 4.6 Bark Boiler DBB1, kg/MMBtu ..................................................................................... 16 

Table 4.7 Recovery Furnace (NDCE) ERF1, kg/MMBtu .............................................................. 17 

Table 4.8 Recovery Furnace (DCE) FRF1, kg/MMBtu ................................................................. 17 

Table 4.9 Recovery Furnace (DCE) FRF3, kg/MMBtu ................................................................. 18 

Table 4.10 Combination Boiler FBB1, kg/MMBtu ......................................................................... 18 

Table 4.11 Recovery Furnace (DCE) GRF1, kg/MMBtu ................................................................ 19 

Table 4.12 Recovery Furnace (DCE) GRF2, kg/MMBtu ................................................................ 19 

Table 4.13 Combination Boiler GCB3, kg/MMBtu ........................................................................ 20 

Table 4.14 Boiler MACT/CISWI Testing – CH4 Emissions by Source, kg/MMBtu ........................ 21 

Table 4.15 Bark/Combination Boiler Category Results, kg/MMBtu ............................................... 22 

Table 4.16 Recovery Furnace (NDCE) Category Results, kg/MMBtu ............................................ 23 

Table 4.17 Recovery Furnace (DCE) Category Results, kg/MMBtu ............................................... 23 

Table 5.1 WRI/WBCSD and IPCC Emission Factors ................................................................... 26 

Table 5.2 CH4 Emissions, kg/MMBtu .......................................................................................... 27 

Table 5.3 N2O Emissions, kg/MMBtu .......................................................................................... 28 

FIGURES 

Figure 2.1 FTIR Sampling System .................................................................................................. 4 

National Council for Air and Stream Improvement 

NITROUS OXIDE (N2O) AND METHANE (CH4) EMISSIONS FROM 

BIOMASS-FIRED BOILERS AND RECOVERY FURNACES 

1.0 INTRODUCTION 

1.1 Background 

The US Environmental Protection Agency (EPA) issued the Mandatory Reporting of Greenhouse Gases 

Rule (40 CFR Part 98) in October 2009, requiring the annual reporting of greenhouse gas (GHG) data and 

other relevant information from large sources and suppliers in the United States (USEPA 2009). 

Implementation of Part 98 is referred to as the Greenhouse Gas Reporting Rule (GHGRR). Under this 

rule, reporting is required of pulp and paper mills and other facilities with stationary combustion units 

where facility-wide greenhouse gas (GHG) emissions from applicable sources are greater than 25,000 

metric tonnes of carbon dioxide (CO2) equivalents (CO2 eq.) per year. This rule is intended to facilitate 

the development of comprehensive, nationwide emissions data that provide a better understanding of the 

sources of GHGs and guide the development of policies and programs to reduce emissions. Additionally, 

the public availability of data is intended to allow reporters to benchmark their emissions against those 

from similar facilities and aid in identifying cost-effective opportunities to reduce emissions in the future. 

CO2, methane (CH4), and nitrous oxide (N2O) are the three major GHGs produced in pulp and paper 

manufacturing. Of the three major GHGs, CO2 emissions are predominant and can be attributed to the 

burning of fossil fuels and solid biomass fuels (e.g., wood/wood residuals, bark, etc.) in boilers and 

pulping liquors in chemical recovery furnaces. The pulp and paper industry is heavily reliant on these 

sources for both energy and chemical recovery. Although biogenic CO2 emissions do not apply towards 

the reporting threshold under GHGRR, facilities exceeding the reporting threshold are required to report 

biogenic CO2 emissions under a separate category. CH4 and N2O emissions from these sources, both of 

fossil and of biogenic origin, also need to be reported, both separated by fuel type and in aggregate. CH4

and N2O are emitted in much lower concentrations than CO2 from combustion sources in the pulp and 

paper industry. However, given the greater global warming potentials of CH4 and N2O (21 times and 310 

times the warming potential of CO2, respectively; IPCC 1996) it is important to develop additional data 

on emissions of these compounds from pulp and paper industry sources. 

In the GHGRR, EPA has provided default emission factors for use in estimating CH4 and N2O emissions 

from the combustion of solid biomass fuels and kraft pulping liquors. The default CH4 and N2O emission 

factors for solid biomass fuels are 0.032 kg/MMBtu and 0.0042 kg/MMBtu1

, respectively. For North 

American softwood kraft pulping liquor, the emission factors are 0.030 kg CH4/MMBtu and 0.005 kg 

N2O/MMBtu (USEPA 2009). The factors for solid biomass combustion were derived by EPA from Tier 1 

CH4 and N2O emission factors published by the Intergovernmental Panel on Climate Change (IPCC 

2006). The factors for kraft pulping liquor were derived by EPA from an analysis of a summary, prepared 

by NCASI, of literature generated between 1985 and 2004, and published by The World Research 

Institute and The World Business Council for Sustainable Development (WRI/WBCSD 2005). EPA 

chose the highest of the values provided in the summary for use in the GHGRR. 

 

1 Note on emission units: In the GHGRR [74 FR 56260], EPA has mandated the use of specific emission factors for 

CH4 and N2O (USEPA 2009). These default emission factors are expressed in kg/MMBtu. Additionally, the rule 

requires the use of High Heating Values (HHV) of the fuel when using these emission factors to calculate mass 

emissions of GHG. The emission factors are, in essence, expressed in kg/MMBtu HHV. In order to be consistent 

with the approach used by EPA in the rulemaking and to better facilitate comparison, all emission data generated 

from the NCASI study are also expressed in kg/MMBtu, with HHV for the fuel being used as opposed to the Low 

Heating Value (LHV). It is assumed that there is a 5% difference between the LHV and HHV of the fuels. 
2 Technical Bulletin No. 998 

National Council for Air and Stream Improvement 

An NCASI review of more recent literature indicates a dearth of accurate and direct emission 

measurements of CH4 and N2O from biomass-fired boilers and kraft recovery furnaces, especially those 

located in North America. As a result, the validity of existing emission factors, including those 

recommended by EPA, has come under scrutiny. Given the emphasis being placed on GHG inventories, 

the limited data availability, and uncertainty surrounding currently available emission factors, NCASI 

carried out a study to develop additional data for CH4 and N2O emissions from these sources. 

As part of NCASI testing, emission measurements were conducted at 13 sources, including five biomassfired boilers, five direct contact evaporators (DCE) recovery furnaces, and three non-direct contact 

evaporator (NDCE) recovery furnaces. CH4 and N2O concentrations in the stack gases were quantified 

using a portable Fourier transform infrared (FTIR) analyzer. 

EPA, using its authority under Section 114 of the Clean Air Act, issued an information collection request 

(ICR) in June 2009 to approximately 300 industrial, commercial, and institutional boilers and commercial 

and industrial solid waste incineration (CISWI) sources nationwide, requiring them to conduct emissions 

testing for several hazardous air pollutants (HAPs) and surrogates like CH4. The data collected from this 

effort have been used in the Boiler MACT rulemaking for floor determinations and setting emission 

standards. In addition to generating data from targeted testing, NCASI has compiled additional data on 

CH4 emissions from the Boiler MACT/CISWI test reports in order to increase the sample size and 

develop a more robust emission factor for CH4 from biomass-fired boilers. CH4 emission data from 19 

boilers tested as part of Boiler MACT program and three boilers tested as part of the commercial and 

industrial solid waste incineration (CISWI) program have been incorporated into the emission factors 

developed as part of this study. These boilers were predominantly burning biomass fuels during these 

tests (>80% of heat input from biomass fuels). CH4 emissions at these sources were quantified using gas 

chromatography (GC) as required by EPA Method 18. 

1.2 Study Objectives 

This study was initiated in response to the need for accurate and direct emission measurements of CH4

and N2O from biomass boilers and recovery furnaces and the lack of availability of such data. Specific 

objectives of this study were to (1) obtain direct emission measurements of CH4 and N2O from biomassfired boilers, DCE recovery furnaces, and NDCE recovery furnaces via FTIR analysis, (2) summarize 

CH4 emissions data from EPA’s recent Boiler MACT ICR, (3) develop CH4 and N2O emission factors for 

potential use in future PSD and Title V permit modifications, and (4) facilitate a comparison of these 

factors with the default emission factors mandated by EPA for use in GHG inventories as part of the 

GHGRR. 

2.0 SAMPLING AND ANALYSIS METHODS 

2.1 FTIR 

During the NCASI testing, target analytes were quantified on site using a portable FTIR analyzer. In this 

instance, EPA Method 320—Measurement of Vapor Phase Organic and Inorganic Emissions by 

Extractive Fourier Transform Infrared (FTIR) Spectroscopy (USEPA 1999)—is the most appropriate 

method available. ASTM International Standard Test Method D 6348-03—Determination of Gaseous 

Compounds by Extractive Direct Interface FTIR Spectroscopy (ASTM 2003)—is an EPA-approved 

alternative to Method 320. The ASTM method was employed as the primary reference method for all 

FTIR analyses carried out during this study. 

2.1.1 Hardware Components

FTIR Spectrometer: The spectrometer used for analysis was a portable GasmetTM DX-Series FTIR. The 

IR source is a ceramic element heated to 1275°C. The interferometer is a Temet Instruments CICCOR 

Interferometer with a resolution of 8 cm-1 and an aperture of 1". The sample cell is a 0.5 L multipass cell 
Technical Bulletin No. 998 3 

National Council for Air and Stream Improvement 

with gold/rhodium-coated mirrors and a fixed path length of 5 m. The detector is a thermo-electrically 

cooled MCT detector. 

Data Acquisition System: Laptop with Temet Instruments CALCMETTM software for data acquisition 

and analysis of IR data. All IR spectra and supporting information were stored on the laptop. 

Sample Conditioning System: A sample conditioning system was employed in this study in order to (1) 

prevent interferences and potential bias due to high levels of source moisture and (2) enhance bag sample 

stability. The conditioning system was placed in front of the heated-filter assembly and consisted of an 

empty impinger to condense source moisture and a silica gel impinger to remove entrained moisture and 

SO2 from the gas stream. The performance of the conditioning system was evaluated both in the 

laboratory and in the field. The results provided in Appendix C indicate that this setup is appropriate for 

conditioning the gas stream.1 

Sample Probe: 3/8" stainless steel 316 tubing of sufficient length to access the sampling location on the 

stack. 

Heated Filter Assembly: Ceramic filter, rated at 2 m, seated inside heated-filter housing. Dilution/spike 

gases can be added upstream of the heated filter through a T-valve assembly. 

Sampling Lines: Heated 1⁄4" PTFE line. Additional heated 1⁄4" line for dilution/spike gases. 

Heated Sample Pump Assembly: The assembly contains a heated KNF pump and a ZrO2 oxygen sensor. 

Assembly also includes heater controllers for the sample pump and heated lines, as well as a vacuum 

gauge for leak checks. 

Mass Flow Control: Two Brooks® mass flow controllers capable of supplying an accurate, constant flow 

of dilution air or spike gas to the heated probe assembly. 

Nitrogen Pneumatic Assembly: The assembly allows a single nitrogen source to be split for continuous 

optical purge and delivery of nitrogen to the heated filter assembly for background measurement. 

Gas cylinders: Ultra-high purity nitrogen and EPA protocol calibration standards for analyte spiking and 

CTS measurements. 

Figure 2.1 depicts the FTIR sampling system configuration. 
4 Technical Bulletin No. 998 

National Council for Air and Stream Improvement 

Figure 2.1 FTIR Sampling System 

2.1.2 Analysis Procedure

The FTIR analysis software requires that, for each source, an appropriate analysis method be set up to 

deconstruct and analyze the IR spectra. The analysis method can be tailored to the source being tested and 

defines all elements of the analysis, including the list of compounds being analyzed (analytes), the 

reference spectra used for calibration, a list of compounds that could be interferences, and specific 

wavelengths to be evaluated for quantifying the target analytes. This approach serves to minimize 

interferences and maximize accuracy, given the ability to identify unique interferences for any given 

source. These analyses methods are provided in Appendix A. A detailed description of FTIR analyzers 

and the process of FTIR analysis can be found in Appendix B. 

2.1.3 Sample Run

The following procedures were followed as part of a complete sample run. 

Pre-Run Stack Flow Measurement – Procedure outlined in Section 2.1.6. 

Background Spectrum – Ultra-high purity nitrogen was flushed through the system. When the sampling 

system was completely saturated with nitrogen, a background spectrum was obtained. 

Pre-Run CTS Spike – Calibration transfer standard (CTS) spikes were used to ensure the stability of the 

sampling system. Ethylene from a cylinder of known concentration was flushed through the system. A 

CTS spectrum was obtained and analyzed. The results from CTS spiking must be within ±5% of the 

certified cylinder value in order for the testing to proceed. 

Sample Source Gas Stream – The source gas stream was sampled from a single point for a period of 30 to 

60 minutes. 

Analyte Spike 

CTS Spike 

Mass Flow 

Controller 

Laptop 

UHP Nitrogen 

Pneumatic Assembly

FTIR 

Vent 

Heated Line

O2

Heated Sample

Pump 

Heated Line

Conditioning System

SS Probe Heated Filter 
Technical Bulletin No. 998 5 

National Council for Air and Stream Improvement 

Analyte Spiking – The analyte spiking procedure described in Section 2.1.5.2 was conducted for N2O and 

CH4. 

Post-Run CTS Spike – The CTS spike result must be within ±5% of the certified cylinder value. 

Post-Run Stack Flow Measurement – Procedure outlined in Section 2.1.6. 

For each sample spectrum, the target analyte concentration and minimum detectable concentration were 

determined. Concentration data were combined with flow measurements and process data to determine an 

emission factor corresponding to each run. 

To minimize the number of flow measurements taken, one set of stack flow measurements was often used 

for multiple runs. Run groupings can be found in Appendix A. 

2.1.4 Bag Sampling

Direct source measurements using the FTIR sampling setup could not be accomplished in some cases. 

Where direct sampling was impossible or impractical, the source gas was collected in Tedlar® bags and 

subsequently analyzed onsite using the FTIR. Sample gas was drawn through the sample conditioning 

system described in Section 2.1.1, through a sample pump box, and into a 100 L Tedlar® bag. Sample 

flow was maintained around 3 L/min by employing a critical orifice. Bags were analyzed on site with the 

FTIR sampling setup. The sample collected in the bag was considered to be a representative composite of 

the source gas over the sampling period. As discussed earlier, the results from the sample conditioning 

evaluation provided in Appendix C indicate that the target analytes were stable in the bag for a period of 

up to four hours. 

2.1.5 Quality Assurance/Quality Control 

2.1.5.1 Minimum Detectable Concentrations

The minimum detectable concentration (MDC), or detection limit (DL), is the minimum concentration of 

a compound at which a change can be detected by the instrument with a given statistical probability 

(typically with a 95% confidence). The MDC for each analyte is a function of two parameters: instrument 

noise and residual noise in the analysis area. As these two noise parameters increase, the MDC will 

increase correspondingly. In general, instrument noise remains at a constant level throughout a sampling 

period. Residual noise, on the other hand, will increase or decrease based on the performance of the 

analysis algorithm for a particular sample. Residual noise will decrease to zero when all components of 

the gas stream are identified and accurately quantified. The following calculation is used to determine the 

MDC for each analyte. 

ı ı ı = 

ı ı ı ı ı ı

ı ı ıı ı ı

 ∗ ı ı ı ı

where 

REArms = root mean square of the residual absorption peaks in the analysis area 

REFrms = root mean square of the reference absorption peaks in the analysis area, and 

Cref = concentration of the analyte reference spectra. 

The number of detects obtained during each sample run at a source is also provided in Appendix A as part 

of the run-by-run results. 
6 Technical Bulletin No. 998 

National Council for Air and Stream Improvement 

Concentrations below the DL were considered to be non-detects (ND). In the case of sample runs with a 

mixture of detects and NDs, the concentrations were evaluated using the Kaplan-Meier statistical method 

(NCASI 2009a, 2009b). The Kaplan-Meier method determines the mean, median, and standard deviation 

(SD) of a dataset containing both NDs and detects. The Kaplan-Meier mean was calculated and the run 

was subsequently characterized as a detect. In the case of data sets with all NDs, the average DL was 

calculated and the run was labeled as ND. 

2.1.5.2 Analyte Spiking

Analyte spiking was used to determine the effectiveness of the FTIR measurement system to quantify the 

target analytes. From the sample runs, native analyte concentrations were quantified. Total flow was 

measured at the inlet of the FTIR system to calculate dilution factors (DFs). Dynamic spiking was 

performed while either sampling directly from the source or from a Tedlar® bag. Certified analyte gas of 

a known concentration was combined with sample gas upstream of the heated filter at a rate ≤10% of the 

total flow. Spike flow rates were controlled using a mass flow controller. When possible, equivalent 

spiking concentrations were kept within ±50% of the native source concentration. An expected 

concentration was calculated based on the following calculation. 

ı ı ı ı ı ı ı ı ı ı ıı ı ı ı ı ı ı ı ı ı = ı ı + (ı ı ∗ ı1 − ı ı ı)

where 

CS = (cylinder concentration * DF) 

Ua = native source gas concentration. 

Percent recovery of the spiked analyte is calculated using the following formula. 

% ı ı ı ı ı ı ı ı = 

ı ı ı ı ı ı ı ı ı ı ıı ı ı ı ı ı ı ı ı

ı ı ı ı ı ı ı ı ı ı ıı ı ı ı ı ı ı ı ı ı

∗ 100%

Concentration observed corresponds to the quantified concentration of the analyte spike sample. Spike 

recoveries between 70% and 130% were considered acceptable. Results on CH4 and N2O spike recoveries 

are also provided in Appendix A. Analyte spiking was used only as a quality check and the percent 

recoveries calculated from this procedure were not used as scaling factors to adjust the results. 

2.1.5.3 Equipment Calibration and Certification

Equipment calibrations and certifications were verified ahead of each sampling trip. Recalibrations were 

performed, as needed, either by NCASI personnel or by the manufacturer. 

2.1.5.4 Gas Cylinder Certification

Ultra-high purity nitrogen was used for background measurements and dilutions. CH4 and N2O cylinders 

used for spiking were either certified using EPA protocol or a NIST standard and the certified 

concentration was no more than ±2% of the tag concentration. The ethylene mixture used for CTS spiking 

was also certified at ±2% of the tag concentration. 

2.1.5.5 Reference Spectra

Reference spectra were generated using either certified gas cylinders or from neat compounds. Dilutions 

were obtained by directly measuring flows using a certified bubble-tube meter. For neat compounds, only 
Technical Bulletin No. 998 7 

National Council for Air and Stream Improvement 

solutions of known purity were used. Neat solutions were injected using a Cole-Parmer® syringe pump 

into a heated manifold, vaporized, and subsequently diluted with ultra-high-purity nitrogen to the desired 

concentration. 

2.1.6 Stack Flow Rate and Process Data

From the list of methods provided in Appendix A of 40 CFR Part 60 (Standards of Performance for New 

Stationary Sources), Methods 1 through 4 (USEPA 2000, pp. 61779-61832) were used to determine flow 

rates and moisture content of the source. For stack flow rates, a Type S pitot tube with portable 

Magnehelic® pressure gauges was used. The pitot was equipped with a K-type thermocouple on the end 

to measure source temperature at each sample location. A Meriam Instrument digital manometer was used 

to measure stack and ambient pressure. Oxygen and carbon dioxide concentrations were also measured 

using the FTIR analyzer. Source moisture was determined using a Rockwell 175-S dry gas meter and an 

Ohaus® NavigatorTM scale for impinger weights. Results of source flow measurements are found in 

Appendix A. 

Data on boiler and furnace operating parameters, fuel firing rates, and fuel heat content were obtained 

from the facility. In the absence of recent data on fuel heating values, a representative default value 

provided by the mill was used. The facilities also provided data on firing rates of auxiliary fuels, if any, 

during sampling. A summary of the process data for each source is provided in Appendix A. 

2.2 Boiler MACT/CISWI Testing 

CH4 emissions were measured in the 2009 Boiler MACT/CISWI testing program using EPA Method 18 –

Measurement of Gaseous Organic Compound Emissions by Gas Chromatography (USEPA 2000, pp. 

62007-62028). It was assumed that all these tests were conducted in accordance with the appropriate 

equipment, procedure, and QA/QC requirements as outlined in the method. Flow rates were obtained 

directly from the test reports. The total heat input into the boiler during a test run was determined using Ffactors and concurrent data on fuel firing rates. 

3.0 SOURCE DESCRIPTIONS 

3.1 NCASI Testing 

3.1.1 Mill A

Mill A is a kraft mill located in the southeast United States. It produces approximately 1,200 tons per day 

(TPD) of bleached softwood dissolving grade/specialty pulp. One recovery furnace and one bark boiler 

were tested at this facility. The recovery furnace is referred to as source ARF3. The bark boiler is referred 

to as source ABB2. 

Source ARF3 is a DCE recovery furnace with a permitted capacity of 82,350 pounds of black liquor 

solids per hour and a steaming capacity of 267,000 pounds per hour (PPH). Particulate is controlled via a 

dry bottom electrostatic precipitator (ESP). Sampling on source ARF3 was accomplished over a three-day 

period during which 10 runs were conducted. CH4 and N2O concentrations were determined using FTIR 

analysis. The boiler produced an average of 217,000 PPH of steam (81% capacity) during these runs. A 

small amount of No. 6 fuel oil was fired intermittently during the 10 runs, with an average firing rate of 

1.9 gallons per minute. 

Source ABB2 is a stoker bark boiler with a permitted capacity of 601 MMBtu/hr and a steaming capacity 

of 400,000 PPH. Particulate is controlled via a venturi scrubber. A portion of the exhaust flow leaving the 

boiler is diverted to a rotary bark dryer. The two gas streams are recombined before entering the venturi 

scrubber. Sample ports are located downstream of the scrubber. Sampling on source ABB2 was 

accomplished over a one-day period during which five runs were conducted. CH4 and N2O concentrations 
8 Technical Bulletin No. 998 

National Council for Air and Stream Improvement 

were determined using GC and FTIR analyses, respectively. The boiler produced an average of 254,000 

PPH of steam (66% capacity) during the runs. The boiler burned 100% bark during the sampling period. 

3.1.2 Mill B

Mill B is a kraft mill located in the southeast United States. It produces approximately 2,240 TPD of 

unbleached softwood linerboard. One NDCE recovery furnace was tested at this facility. The recovery 

furnace is referred to as source BRF5. 

Source BRF5 has a permitted capacity of 156,780 PPH of black liquor solids and a steaming capacity of 

495,700 PPH. Particulate is controlled via a dry bottom ESP. The ESP has two chambers in parallel, with 

the exhaust gas venting through separate stacks. Concentration measurements were performed on a single 

stack. Flow data were collected from both stacks. Sampling on source BRF5 was accomplished over a 

four-day period during which five sample runs were conducted. CH4 and N2O concentrations were 

determined using FTIR analysis. Five additional runs were conducted as part of the method development 

study described in Appendix C. The source produced an average of 477,000 PPH of steam (96% capacity) 

during sampling. 

3.1.3 Mill C

Mill C is a hardwood/softwood kraft mill located in the southeast United States. It produces a mixture of 

bleached tissue and unbleached kraft paper and linerboard with a total capacity of 1,447 TPD. One 

combination boiler was tested. The combination boiler is referred to as source CCB4. 

Source CCB4 is a stoker boiler burning a combination of bark and No. 6 fuel oil. The boiler has a design 

capacity of 513 MMBtu/hr and 360,000 PPH of steam. Particulate is controlled via an ESP. Six runs were 

completed over a two-day period. CH4 and N2O concentrations were determined using FTIR analysis. The 

boiler produced 241,000 PPH of steam (67% capacity) during the sample runs. The average firing rates 

during the runs were 2,140 PPH of No. 6 fuel oil and 33.65 tons per hour of bark, resulting in 11% and 

88% of total heat input, respectively. 

3.1.4 Mill D

Mill D is a kraft mill in the southeast United States. It produces approximately 1,560 TPD of bleached 

softwood dissolving/specialty pulp. One NDCE recovery furnace and one bark boiler were tested at this 

facility. The recovery furnace is referred to as source DRF1. The bark boiler is referred to as source 

DBB1. 

Source DRF1 is an NDCE recovery furnace with a rated capacity of 243,750 PPH of black liquor solids 

and a steaming capacity of 980,000 PPH. Particulate is controlled with a dry bottom ESP. Eight runs were 

completed over a one-day period with the boiler producing 806,000 PPH (82% capacity) during the 

sample runs. CH4 and N2O concentrations were determined using FTIR analysis. 

Source DBB1 is a stoker boiler designed to burn a combination of bark and natural gas. The boiler is 

permitted at 642 MMBtu/hr and has a steaming capacity of 540,000 PPH. Particulate is controlled via an 

ESP. The ESP has two chambers in parallel, with the exhaust gas venting through a common stack. Ten 

runs were completed over a two-day period with the boiler producing an average of 235,000 PPH (44% 

capacity). The boiler burned 100% bark during sampling. CH4 and N2O concentrations were determined 

using FTIR analysis. 

3.1.5 Mill E

Mill E is a kraft mill located in the southeast United States capable of producing 860 TPD of bleached 

softwood pulp. One NDCE recovery furnace was tested at the facility. The recovery furnace is referred to 

as source ERF1. 
Technical Bulletin No. 998 9 

National Council for Air and Stream Improvement 

Source ERF1 is an NDCE recovery furnace with a permitted capacity of 195,800 PPH of black liquor 

solids and a design steaming capacity of 700,000 PPH. The gas stream is divided into two parallel ESPs 

and then vented out of separate stacks. Ten runs were completed over a two-day period. CH4 and N2O 

concentrations were determined using FTIR analysis. An average of 171,700 PPH of black liquor solids 

were fired (88% capacity) during the sample runs. 

3.1.6 Mill F

Mill F is a kraft mill located in the southeast United States. It produces approximately 1,180 TPD of 

unbleached linerboard. Two DCE recovery furnaces and one combination boiler were tested. The two 

recovery furnaces are referred to as source FRF1 and source FRF3. The combination boiler is referred to 

as source FBB1. 

Source FRF1 is a DCE recovery furnace with a steaming capacity of 110,000 PPH and a design black 

liquor firing capacity of 34,400 PPH. Particulate is controlled with a wet ESP. Six runs were carried out 

over a one-day period. CH4 and N2O concentrations were determined using FTIR analysis. During 

sampling, the boiler produced an average of 85,200 PPH of steam (78% capacity). 

Source FRF3 is a DCE recovery furnace with a steaming capacity of 165,000 PPH and a black liquor 

capacity of 48,300 PPH. Particulate is controlled with a wet bottom ESP. Nine runs were completed over 

a two-day period with the boiler producing an average of 152,600 PPH of steam (92% capacity). CH4 and 

N2O concentrations were determined using FTIR analysis. 

Source FBB1 is a combination of a Riley stoker boiler and a CE stoker bark boiler. The two boilers 

exhaust through a common stack. The Riley boiler has a steaming capacity of 225,000 PPH, while the CE 

bark boiler has a design steaming capacity of 150,000 PPH, for a combined total capacity of 375,000 

PPH. Particulate emissions from both sources are controlled by a common venturi scrubber. Ten runs 

were completed over a two-day period. CH4 and N2O concentrations were determined using FTIR 

analysis. The boilers produced a total of 310,000 PPH of steam (83% total capacity). During the testing 

period, both boilers fired 100% wood. 

3.1.7 Mill G

Mill G is a kraft mill located in the southeast United States. It produces approximately 900 TPD of 

bleached hardwood linerboard. Two DCE recovery furnaces and one combination boiler were tested. The 

two DCE recovery furnaces are referred to as source GRF1 and source GRF2. The combination boiler is 

referred to as source GCB3. 

Source GRF1 is a DCE recovery furnace with a design capacity of 124,000 PPH of black liquor and a 

steaming capacity of 398,000 PPH of steam. Emissions are divided into two parallel dry bottom ESPs and 

then vented through separate stacks. Concentration measurements were performed on a single stack. Flow 

data were collected from both stacks. Six runs were conducted at the source over a one-day period. CH4

and N2O concentrations were determined using FTIR analysis. During sampling an average of 120,400 

PPH of black liquor solids were fired (97% capacity). 

Source GRF2 is a DCE recovery furnace with a design capacity of 124,000 PPH of black liquor and a 

steaming capacity of 398,000 PPH of steam. Emissions are divided into two parallel wet bottom ESPs and 

then vented through separate stacks. Concentration measurements were performed on a single stack. Flow 

data were collected from both stacks. Six runs were conducted over a one-day period. CH4 and N2O 

concentrations were determined using FTIR analysis. An average of 104,900 PPH of black liquor solids 

were fired (85% capacity) during testing. 
Table 3.1 NCASI Testing – General Source Descriptions 

Data Source Mill ID Source ID Type Primary Fuel Secondary Fuel Capacit

NCASI Testing A ARF3 DCE Recovery Black Liquor No. 6 Fuel Oil 267,000 

NCASI Testing A ABB2 Stoker Bark 601 

NCASI Testing B BRF5 NDCE Recovery Black Liquor 495,700 

NCASI Testing C CCB4 Stoker Bark No. 6 Fuel Oil 513 

NCASI Testing D DRF1 NDCE Recovery Black Liquor 980,000 

NCASI Testing D DBB1 Stoker Bark 642 

NCASI Testing E ERF1 NDCE Recovery Black Liquor 700,000 

NCASI Testing F FRF1 DCE Recovery Black Liquor 110,000 

NCASI Testing F FRF3 DCE Recovery Black Liquor 165,000 

NCASI Testing F FBB1 Combo. Stoker Wood 375,000 

NCASI Testing G GRF1 DCE Recovery Black Liquor 398,000 

NCASI Testing G GRF2 DCE Recovery Black Liquor 398,000 

NCASI Testing G GCB3 Stoker Bark No. 6 Fuel Oil 499 

National Council for Air and Stream Improvement
Table 3.2 Boiler MACT/CISWI Testing – General Source Descriptions 

Data Source Mill ID Source ID Type Primary Fuel Secondary Fuel Cap

MACT H HCB1 Stoker Bark Resinated Wood, Natural Gas 4

MACT I ICB1 Fluidized Bed Bark Municipal Solid Waste, Natural Gas 12

MACT J JCB2 Stoker Bark TDF, No. 6 Fuel Oil 5

MACT K KCB2 Fuel Cell Bark 1

MACT L LCB1 Fuel Cell Wood/Bark 1

MACT M MCB3 Fuel Cell Wood/Bark 29

MACT N NCB1 Stoker Bark 4

MACT O OCB4 Stoker Bark No. 6 fuel oil, Natural Gas 8

MACT P PCB4 Fluidized Bed Bark WWT Sludge, TDF 8

MACT Q QCB8 Stoker WWT Sludge Wood/Bark 2

MACT R RCB1 Fuel Cell Bark

MACT S SCB1 Stoker Bark Cross ties, Natural Gas, WWT Sludge 4

MACT T TCB1 Fuel Cell Wood 2

CISWI U UCB2 Stoker Wood/Bark OCC rejects, WWT Sludge, Natural Gas 9

CISWI V VCB2 Stoker Bark WWT Sludge, Cross ties, Natural Gas 6

CISWI W WCB1 Stoker Bark Natural Gas, WWT Sludge, OCC rejects 9

MACT X XCB1 Stoker Bark 20

MACT Y YCB1 Stoker Bark Natural Gas 3

MACT Z ZCB1 Bark 

MACT AA AACB1 Fuel Cell Wood/Bark 

MACT AB ABCB1 Dutch oven Wood/Bark 90

MACT AC ACCB1 Fluidized Bed Bark 8

National Council for Air and Stream Improvement
12 Technical Bulletin No. 998 

National Council for Air and Stream Improvement 

Source GCB3 is a stoker boiler burning a combination of wood and No. 6 fuel oil. The boiler has a design 

capacity of 499 MMBtu/hr and 300,000 PPH of steam. Particulate is controlled with a venturi scrubber. 

Six runs were completed over a one-day period. CH4 and N2O concentrations were determined using 

FTIR analysis. The boiler produced an average of 183,600 PPH of steam (61% capacity). During the 

testing period, the source fired 244.6 MMBtu/hr of bark and 4.3 MMBtu/hr of No. 6 fuel oil, resulting in 

98% and 2% of the total Btu input, respectively. 

3.2 Boiler MACT/CISWI Testing 

Test data from 22 biomass-fired boilers were extracted from EPA’s 2009 Boiler MACT and CISWI 

databases (19 boilers and 3 incinerators). Boilers were selected if CH4 testing was conducted with > 80% 

of the heat input on average coming from biomass fuels. With the exception of one source, OCB4, where 

only two tests were conducted with the boiler burning predominantly biomass, all other sources had three 

test runs. In all cases, CH4 concentrations were determined using EPA Method 18. Table 3.2 provides a 

general description of each source selected from the database, along with information on the types of 

fuels being burned during testing. Appendix A contains the percentages of each fuel burned during 

individual runs. 

4.0 RESULTS 

In the final GHG reporting rule [74 FR 56260], EPA has mandated the use of specific emission factors for 

CH4 and N2O (USEPA 2009). These emission factors are expressed in units of kg/MMBtu. Additionally, 

the rule requires use of high heating value (HHV) of the fuel when utilizing these emission factors to 

calculate mass emissions of GHG (in kg). These emission factors are, in effect, expressed in kg/MMBtu 

HHV. In order to be consistent with the approach used by EPA in the rulemaking and to better facilitate 

comparison, all emission data in this report are also expressed in kg/MMBtu, with HHV for the fuel being 

used as opposed to the low heating value (LHV) in calculations. It has been assumed that there is a 5% 

difference between the LHV and HHV of fuels. 

4.1 NCASI Testing 

All reported emissions have been calculated from measured in-stack concentrations, expressed on a dry 

basis. Emissions are reported in kg/MMBtu to be consistent with the approach used by EPA in the 

GHGRR. Emissions are calculated and reported using the high-heating value (HHV) of the fuel as the 

basis. Detailed results for each source are listed in Appendix A. 

In the case of combination boilers burning a mixture of biomass and other fuels, emissions are expressed 

based on the combined fuel energy input. CH4 and N2O emissions are expected to be dictated more by 

combustion conditions than fuel properties (WRI/WBCSD 2005; Bonn, Pelz, and Baumann 1995). Even 

though multiple fuels were being burned during some of these tests, biomass fuels were the predominant 

fuel and accounted for ~ 90% of heat input in all cases. Subsequently, it is reasonable to compare these 

emission factors against the default factors for solid biomass fuels in the GHG reporting rule. 

4.1.1 Treatment of Non-detect (ND) Data 

When utilizing the direct sampling and analysis methodologies with the FTIR, as outlined above in 

Section 2.1, each sample run involves the recording and analysis of multiple IR spectra. In effect, each 

reported data point (labeled as a Run in Tables 4.1 through 4.14) reflects an average of multiple 

measurements. For each IR spectrum analyzed, the target analyte concentration and DL were calculated. 

Detection limits were determined as outlined in Section 2.1.5.1. All analytical results were used to 

determine the minimum, maximum, mean, standard deviation (SD), and median concentrations for CH4

and N2O for the sample run. Non-detect (ND) data was treated as follows: 
Technical Bulletin No. 998 13 

National Council for Air and Stream Improvement 

· When a sample run dataset included a mixture of detects and NDs, the concentrations were 

evaluated using the Kaplan-Meier statistical method (NCASI 2009a, 2009b). The Kaplan-Meier 

statistical mean concentration for the run was calculated and the run was characterized as a detect. 

· In the case of sample runs with all NDs, the mean DL was calculated and the run was marked as 

ND. 

· In the case of sample runs with only one detect, the ND values are reduced to 1⁄2 the DL, the 

resulting mean concentration was calculated, and the run was characterized as a detect. 

· ND data from multiple sample runs at a given source were also treated as described above. 

Spike recoveries were calculated for each run as described in Section 2.1.5.2. In the case of data sets with 

a mixture of detects and NDs, spike recovery was calculated by using the Kaplan-Meier statistical mean 

as the native source gas concentration. For runs with all NDs, no spike recovery was calculated. Spike 

recoveries between 70% and 130% were considered acceptable. Runs with spike recoveries outside this 

range were removed. 

4.1.2 Mill A

4.1.2.1 Recovery Furnace (DCE) ARF3

Ten sample runs were completed at source ARF3. One of the 10 sample runs yielded a ND for CH4. N2O 

concentrations were above the DL for all sample runs. Run 4 did not meet the QA requirements in terms 

of spike recovery for N2O. Subsequently, this data point was excluded from summary calculations. The 

average spike recoveries for the reported CH4 and N2O concentrations were 91.1% and 86.8%, 

respectively. Table 4.1 summarizes the CH4 and N2O emissions for source ARF3. 

Table 4.1 Recovery Furnace (DCE) ARF3, kg/MMBtu 

Run CH4 N2O

1 0.00015 0.00043

2 0.00068 0.00032

3 0.00010 0.00028

4 0.00014

5 0.00019 0.00035

6 0.00016 0.00027

7 0.00012 0.00024

8 0.00008 0.00013

9 ND[0.00013] 0.00027

10 0.00027 0.00015

Range 0.00008 – 0.00068 0.00013 – 0.00043

Mean 0.00020 0.00027

St. Dev 0.00017 0.00009

Median 0.00014 0.00027

4.1.2.2 Bark Boiler ABB2

Five sample runs were completed at source ABB2. However, sample interferences prevented the accurate 

quantification of CH4 using the FTIR. Subsequently, the bag samples were analyzed for CH4 using a 
14 Technical Bulletin No. 998 

National Council for Air and Stream Improvement 

GC/FID (equivalent to using EPA Method 18). Four of the five sample runs were analyzed. The Tedlar 

bag corresponding to Run 4 did not contain adequate amounts of sample gas to carry out a GC analysis. 

No spiking was conducted for CH4. All sample runs were above the DL for N2O concentrations. The 

average spike recovery for N2O was 91.7%. Table 4.2 summarizes the CH4 and N2O emissions for source 

ABB2. 

Table 4.2 Bark Boiler ABB2, kg/MMBtu 

Run CH4 N2O

1 0.00044 0.0018

2 0.00083 0.0014

3 0.0015 0.0023

4 0.0040

5 0.0016 0.0038

Range 0.00044 – 0.0016 0.0014 – 0.0040

Mean 0.0011 0.0027

St. Dev 0.0006 0.0012

Median 0.0012 0.0023

4.1.3 Mill B

4.1.3.1 Recovery Furnace (NDCE) BRF5

Five sample runs were completed at source BRF5. One of these runs yielded a ND for CH4. Additionally, 

Run 2 and Run 3 CH4 spike recovery results did not meet QA requirements. These data points were 

removed from summary calculations. All sample runs were above the DL for N2O concentrations. The 

average spike recoveries for the reported CH4 and N2O concentrations were 81.2% and 113.1%, 

respectively. Table 4.3 summarizes the CH4 and N2O emissions for source BRF5. 

Table 4.3 Recovery Furnace (NDCE) BRF5, kg/MMBtu 

Run CH4 N2O

1 0.00090 0.00062

2 0.00065

3 0.00086

4 ND[0.00039] 0.0011

5 0.0010 0.00088

Range ND[<0.00039] –

0.0010 

0.00062 – 0.0011

Mean 0.00093 0.00082

St. Dev 0.00007 0.00020

Median 0.00039 0.00086
Technical Bulletin No. 998 15 

National Council for Air and Stream Improvement 

4.1.4 Mill C

4.1.4.1 Combination Boiler CCB4

Six sample runs were completed at source CCB4. All sample runs were above the DL for CH4 and N2O 

concentrations. The average spike recovery for CH4 and N2O was 99.3% and 98.9%, respectively. Table 

4.4 summarizes the CH4 and N2O emissions for source CCB4. 

Table 4.4 Combination Boiler CCB4, kg/MMBtu 

Run CH4 N2O

1 0.00076 0.0014

2 0.00040 0.0012

3 0.0048 0.0014

4 0.0046 0.0016

5 0.0077 0.0019

6 0.00042 0.0014

Range 0.00040 – 0.0077 0.0012 – 0.0019

Mean 0.0031 0.0015

St. Dev 0.0030 0.0002

Median 0.0027 0.0014

4.1.5 Mill D

4.1.5.1 Recovery Furnace (NDCE) DRF1

Eight sample runs were completed at source DRF1. Seven of the eight runs yielded NDs for CH4. As 

outlined in the approach laid out in Section 4.1.1, since seven of the eight runs were NDs, the ND values 

were reduced to 1⁄2 DL and characterized as detects for summary calculations. The spike recovery for the 

lone detect was 93.0%. Four of the eight runs were ND for N2O. Run 1 for N2O was ND at a detection 

level that was greater than the highest detected concentration for the set of runs. Since the Kaplan-Meier 

method states that there is no useful information in such a value, this data point was removed from the 

data set (NCASI 2009a). The average spike recovery for N2O was 80.9%. Table 4.5 summarizes CH4 and 

N2O emissions for DRF1. 
16 Technical Bulletin No. 998 

National Council for Air and Stream Improvement 

Table 4.5 Recovery Furnace (NDCE) DRF1, kg/MMBtu 

Run CH4 N2O

1 0.000042

2 0.000047 0.00012

3 0.000041 ND[0.00018]

4 0.000046 ND[0.00016]

5 0.000034 0.00018

6 0.000047 0.00018

7 0.000037 ND[0.00014]

8 0.000038 0.00017

Range 0.000034 – 0.000047 0.00012 – 0.00018

Mean 0.000042 0.00015

St. Dev 0.00003

Median 0.00014

NOTE: Shaded values are 1⁄2 DL.

4.1.5.2 Bark Boiler DBB1

Ten runs were completed at source DBB1. All 10 runs were above the DL for CH4 concentrations. The 

average spike recovery was 95.6%. Two of the 10 runs were ND for N2O concentrations. The average 

spike recovery was 90.4%. Table 4.6 summarizes CH4 and N2O emissions for DBB1. 

Table 4.6 Bark Boiler DBB1, kg/MMBtu 

Run CH4 N2O

1 0.00022 0.00091

2 0.00047 0.0013

3 0.00017 0.0011

4 0.00020 0.00090

5 0.00022 0.0012

6 0.00046 0.0012

7 0.00025 ND[0.00062]

8 0.00030 0.0013

9 0.00023 0.0010

10 0.00024 ND[0.00070]

Range 0.00017 – 0.00047 ND[0.00062] – 0.0013

Mean 0.00028 0.0011

St. Dev 0.00011 0.0002

Median 0.00023 0.0010

4.1.6 Mill E

4.1.6.1 Recovery Furnace (NDCE) ERF1

Ten runs were completed at source ERF1. All 10 runs were above the DL for CH4 concentrations. The 

average spike recovery was 98.7%. Seven of the 10 runs were ND for N2O concentrations. The average 

spike recovery was 99.9%. Table 4.7 summarizes CH4 and N2O emissions for ERF1. 
Technical Bulletin No. 998 17 

National Council for Air and Stream Improvement 

Table 4.7 Recovery Furnace (NDCE) ERF1, kg/MMBtu 

Run CH4 N2O

1 0.000065 ND[0.000099]

2 0.0013 ND[0.00019]

3 0.0056 ND[0.00051]

4 0.0029 ND[0.00030]

5 0.00087 ND[0.00016]

6 0.0051 ND[0.00051]

7 0.0033 0.00065

8 0.0041 ND[0.00044]

9 0.0023 0.00065

10 0.0057 0.00027

Range 0.000065 – 0.0057 ND[0.000099] – 0.00065

Mean 0.0031 0.00034

St. Dev 0.0020 0.00015

Median 0.0031 0.00016

4.1.7 Mill F

4.1.7.1 Recovery Furnace (DCE) FRF1

Six runs were completed at source FRF1. All CH4 and N2O concentrations were above the DLs. The 

average spike recoveries for CH4 and N2O were 99.0% and 101.9%, respectively. Table 4.8 summarizes 

CH4 and N2O emissions for FRF1. 

Table 4.8 Recovery Furnace (DCE) FRF1, kg/MMBtu 

Run CH4 N2O

1 0.014 0.00072

2 0.016 0.00085

3 0.0098 0.00044

4 0.0061 0.00054

5 0.0020 0.00069

6 0.015 0.00069

Range 0.0020 – 0.016 0.00044 – 0.00085

Mean 0.010 0.00065

St. Dev 0.005 0.00015

Median 0.012 0.00069

4.1.7.2 Recovery Furnace (DCE) FRF3

Nine runs were completed at source FRF1. All CH4 and N2O concentrations were above the DLs. The 

average spike recoveries for CH4 and N2O were 98.2% and 92.8%, respectively. Table 4.9 summarizes 

CH4 and N2O emissions for FRF3. 
18 Technical Bulletin No. 998 

National Council for Air and Stream Improvement 

Table 4.9 Recovery Furnace (DCE) FRF3, kg/MMBtu 

Run CH4 N2O

1 0.00077 0.00045

2 0.00057 0.00044

3 0.0011 0.00049

4 0.0016 0.00049

5 0.0015 0.00042

6 0.0015 0.00060

7 0.00041 0.00039

8 0.00026 0.00034

9 0.0021 0.00076

Range 0.00026 – 0.0021 0.00034 – 0.00076

Mean 0.0011 0.00049

St. Dev 0.00063 0.00012

Median 0.0011 0.00045

4.1.7.3 Combination Boiler FBB1

Ten runs were completed at source FBB1. All CH4 concentrations were above the DL. The average spike 

recovery was 100.2%. Two of the 10 runs were ND for N2O concentrations. The average spike recovery 

was 101.4%. Table 4.10 summarizes CH4 and N2O emissions for FBB1. 

Table 4.10 Combination Boiler FBB1, kg/MMBtu 

Run CH4 N2O

1 0.054 0.00054

2 0.078 0.00067

3 0.024 0.00028

4 0.058 ND[0.00041]

5 0.017 0.0014

6 0.017 0.0023

7 0.057 ND[0.00043]

8 0.028 0.00069

9 0.054 0.00030

10 0.027 0.00066

Range 0.017 – 0.078 0.00028 – 0.0023

Mean 0.041 0.00073

St. Dev 0.021 0.00060

Median 0.041 0.00054

4.1.8 Mill G

4.1.8.1 Recovery Furnace (DCE) GRF1

Six runs were completed at source GRF1. Five of the six runs were below the DL for CH4. The ND values 

were reduced to 1⁄2 DL and marked as detect for calculations. The spike recovery for the detect run was 
Technical Bulletin No. 998 19 

National Council for Air and Stream Improvement 

99.1%. All N2O concentrations were above the DL. The average spike recovery was 98.7%. Table 4.11 

summarizes CH4 and N2O emissions for GRF1. 

Table 4.11 Recovery Furnace (DCE) GRF1, kg/MMBtu 

Run CH4 N2O

1 0.00011 0.00012

2 0.00010 0.00019

3 0.00011 0.00031

4 0.00015 0.00026

5 0.00011 0.00018

6 0.00010 0.00014

Range 0.00010 – 0.00015 0.00012 – 0.00031

Mean 0.00011 0.00020

St. Dev 0.00007

Median 0.00018

NOTE: Shaded values are 1⁄2 DL.

4.1.8.2 Recovery Furnace (DCE) GRF2

Six runs were completed at source GRF2. Run 2 was ND for CH4 and the DL was greater than the highest 

detected concentration. The ND value was removed before statistical calculations. The average spike 

recovery was 94.7%. All N2O concentrations were above the DL. The average spike recovery was 97.0%. 

Table 4.12 summarizes CH4 and N2O emissions for GRF2. 

Table 4.12 Recovery Furnace (DCE) GRF2, kg/MMBtu 

Run CH4 N2O

1 0.00016 0.00026

2 0.00033

3 0.00013 0.000092

4 0.00010 0.00012

5 0.00011 0.00017

6 0.00013 0.00018

Range 0.00010 – 0.00016 0.000092 – 0.00033

Mean 0.00013 0.00019

St. Dev 0.00002 0.00009

Median 0.00013 0.00017

4.1.8.3 Combination Boiler GCB3

Six runs were completed at source GCB3. All CH4 and N2O concentrations were above the DLs. 

The average spike recoveries for CH4 and N2O were 100.9% and 103.6%, respectively. Table 4.13 

summarizes CH4 and N2O emissions for GCB3. 
20 Technical Bulletin No. 998 

National Council for Air and Stream Improvement 

Table 4.13 Combination Boiler GCB3, kg/MMBtu 

Run CH4 N2O

1 0.00099 0.0020

2 0.00065 0.0024

3 0.00075 0.0036

4 0.00056 0.0037

5 0.00062 0.0048

6 0.00054 0.0038

Range 0.00054 – 0.00099 0.0020 – 0.0048

Mean 0.00068 0.0034

St. Dev 0.00017 0.0010

Median 0.00064 0.0036

4.2 Boiler MACT/CISWI Testing 

For sources tested as part of Boiler MACT/CISWI testing, individual test results (labeled as Runs) were 

also subjected to the statistical treatment outlined in Section 4.1.1. 

The source emissions for CH4 reported in Table 4.14 have been calculated from the measured, in-stack 

concentrations expressed on a dry basis. All emissions have been calculated using the combined energy 

inputs from the fuel, on a high-heating value (HHV) basis. Detailed results for each source are provided 

in Appendix A. 
Table 4.14 Boiler MACT/CISWI Testing – CH4 Emissions by Source, kg/MMBtu 

Source Run 1 Run 2 Run 3 Range Mean 

HCB1 ND[0.00012] ND[0.00011] ND[0.00011] ND[0.00011] – ND[0.00012] ND[0.00012]

ICB1 0.0018 0.0016 0.0020 0.0016 – 0.0020 0.0018 

JCB2 0.0087 0.0037 0.010 0.0037 – 0.010 0.0076 

KCB2 0.00061 0.00029 0.00037 0.00029 – 0.00061 0.00043 

LCB1 0.00092 0.00037 0.00086 0.00037 – 0.00092 0.00072 

MCB3 0.00022 0.00025 0.00048 0.00022 – 0.00048 0.00032 

NCB1 0.0014 0.0011 0.00050 0.00050 – 0.0014 0.0010 

OCB4 0.00015 0.00031 0.00015 – 0.00031 0.00023 

PCB4 0.00017 0.00016 0.00021 0.00016 – 0.00021 0.00018 

QCB8 0.00076 0.00069 0.00064 0.00064 – 0.00076 0.00070 

RCB1 0.0036 0.00067 0.00046 0.00046 – 0.0036 0.0016 

SCB1 0.0012 0.0047 0.00078 0.00078 – 0.0047 0.0022 

TCB1 0.00053 0.0017 0.0024 0.00053 – 0.0024 0.0015 

UCB2 0.0050 0.0023 0.00075 0.00075 – 0.0050 0.0027 

VCB2 0.00055 0.00075 0.0023 0.00055 – 0.0023 0.0012 

WCB1 0.0013 0.0014 0.00093 0.00093 – 0.0014 0.0012 

XCB1 0.0056 0.0038 0.0030 0.0030 – 0.0056 0.0041 

YCB1 0.048 0.056 0.032 0.032 – 0.056 0.046 

ZCB1 0.0046 0.0042 0.0034 0.0034 – 0.0046 0.0041 

AACB1 0.0030 0.011 0.00091 0.00091 – 0.011 0.0048 

ABCB1 0.00084 0.00063 0.00063 0.00063 – 0.00084 0.00070 

ACCB1 0.00096 0.00014 0.00043 0.00014 – 0.00096 0.00051 

National Council for Air and Stream Improvement
22 Technical Bulletin No. 998 

National Council for Air and Stream Improvement 

4.3 Category Results 

4.3.1 Biomass-Fired Boilers

Five biomass-fired boilers were tested using FTIR. The mean CH4 emission from these sources was 

0.0093 kg/MMBtu. Data on CH4 emissions from 22 biomass-fired boilers were extracted from 

available Boiler MACT/CISWI reports. The mean CH4 emission from these sources was 0.0039 

kg/MMBtu. Combining the two data sets then results in a mean CH4 emission of 0.0049 kg/MMBtu. 

The mean N2O emission was 0.0019 kg/MMBtu. Table 4.15 summarizes the CH4 and N2O emissions 

from bark/combination boilers. 

Table 4.15 Bark/Combination Boiler Category Results, kg/MMBtu 

Data Source Source ID CH4 N2O 

NCASI Testing ABB2 0.0011 0.0027 

NCASI Testing CCB4 0.0031 0.0015 

NCASI Testing DBB1 0.00028 0.0011 

NCASI Testing FBB1 0.041 0.00073 

NCASI Testing GCB3 0.00068 0.0034 

MACT HCB1 ND[0.00012] 

MACT ICB1 0.0018 

MACT JCB2 0.0076 

MACT KCB2 0.00043 

MACT LCB1 0.00072 

MACT MCB3 0.00032 

MACT NCB1 0.0010 

MACT OCB4 0.00023 

MACT PCB4 0.00018 

MACT QCB8 0.00070 

MACT RCB1 0.0016 

MACT SCB1 0.0022 

MACT TCB1 0.0015 

CISWI UCB2 0.0027 

CISWI VCB2 0.0012 

CISWI WCB1 0.0012 

MACT XCB1 0.0052 

MACT YCB1 0.046

MACT ZCB1 0.0048

MACT AACB1 0.0048

MACT ABCB1 0.00070

MACT ACCB1 0.00051

Range ND[0.00012] –

0.046 0.00073 – 0.0034 

Mean 0.0049 0.0019 

St. Dev 0.011 0.0011 

Median 0.0012 0.0015 
Technical Bulletin No. 998 23 

National Council for Air and Stream Improvement 

4.3.2 NDCE Recovery Furnaces

Three NDCE recovery furnaces were tested. The mean CH4 emission was 0.0014 kg/MMBtu. The 

mean N2O emission was 0.00044 kg/MMBtu. Table 4.16 summarizes the CH4 and N2O emissions 

from NDCE recovery furnaces. 

Table 4.16 Recovery Furnace (NDCE) Category Results, kg/MMBtu 

Data Source Source ID CH4 N2O

NCASI Testing BRF5 0.00093 0.00082

NCASI Testing DRF1 0.000042 0.00015

NCASI Testing ERF1 0.0031 0.00034

Range 0.000042 – 0.0031 0.00015 – 0.00082

Mean 0.0014 0.00044

St. Dev 0.0016 0.00035

Median 0.00093 0.00034

4.3.3 DCE Recovery Furnaces)

Five DCE recovery furnaces were tested. The mean CH4 emission was 0.0024 kg/MMBtu. The mean 

N2O emission was 0.00036 kg/MMBtu. Table 4.17 summarizes the CH4 and N2O emissions from 

DCE recovery furnaces. 

Table 4.17 Recovery Furnace (DCE) Category Results, kg/MMBtu 

Data Source Source ID CH4 N2O

NCASI Testing ARF3 0.00020 0.00027

NCASI Testing FRF1 0.010 0.00065

NCASI Testing FRF3 0.0011 0.00049

NCASI Testing GRF1 0.00011 0.00020

NCASI Testing GRF2 0.00013 0.00019

Range 0.00011 – 0.010 0.00019 – 0.00065

Mean 0.0024 0.00036

St. Dev 0.0045 0.00020

Median 0.00020 0.00027
24 Technical Bulletin No. 998 

National Council for Air and Stream Improvement 

5.0 DISCUSSION 

5.1 Category Results 

5.1.1 Biomass-Fired Boilers

Five biomass-fired boilers were tested using the FTIR as part of NCASI testing and data from 22 

biomass-fired boilers were obtained from the Boiler MACT/CISWI reports. On average, CH4

emissions from boilers were higher than those observed in DCE and NDCE recovery furnaces , and 

amounted to 0.0049 kg/MMBtu (with median emissions of 0.0012 kg/MMBtu). N2O emissions from 

biomass boilers were higher than those observed in NDCE and DCE recovery furnaces. The mean 

and median N2O emission rate from biomass-fired boilers was 0.0019 kg/MMBtu and 0.0015 

kg/MMBtu, respectively. 

As indicated in Table 4.15, CH4 emissions from two out of the 27 boilers included in this study, viz., 

FBB1 and YCB1, were significantly higher than emissions from other boilers included in this study. 

Specifically, CH4 emissions from these two sources were approximately five times greater than the 

next smallest value measured, and contributed to the higher mean value for CH4 emissions as 

compared to the median. While typical boiler operating parameters at these two sources were within 

normal operating ranges, the carbon monoxide (CO) concentrations measured during these tests were 

significantly higher than those observed on the other sources. It is well documented that CO is a 

surrogate for incomplete combustion in boilers. The prevailing higher CO concentrations could 

therefore explain the higher CH4 emission rates measured from these two sources. It is possible that 

the test runs encompassed periods of transient changes in fuel quality or boiler operation that affected 

the overall quality of combustion. While a more detailed examination of the correlation between CO 

and CH4 emissions from the sources tested during this study is beyond the scope of this report, it is 

worthwhile to note this observed discrepancy in measured CO concentrations. 

5.1.2 NDCE Recovery Furnaces

A total of three NDCE recovery furnaces were tested as part of this study. CH4 emissions from this 

source category were low and quite variable. The mean and median CH4 emission rate was 0.0014 

kg/MMBtu and 0.00093 kg/MMBtu, respectively. Mean and median N2O emissions were 0.00044 

kg/MMBtu and 0.00034 kg/MMBtu, respectively. 

Source ERF1 contained the highest and most variable CH4 emissions, ranging from 0.000065 to 

0.0057 kg/MMBtu. CH4 results for source BRF5 were calculated using three of the five runs, as the 

remaining two runs provided unacceptable analyte spiking results. For this source, dynamic spiking 

was carried out while sampling directly from the stack. Given the observed variability in CH4

concentrations at this source and the potential for concentrations to change between the spiking run 

and the sample run, it is not surprising that spike recoveries for 2 of the runs were outside the 

acceptable range of 70% to 130%. 

5.1.3 DCE Recovery Furnaces 

The mean and median CH4 emission rate was 0.0024 kg/MMBtu and 0.00020 kg/MMBtu, 

respectively in the five DCE furnaces tested during this study. N2O emissions from DCE recovery 

furnaces were the lowest of the three categories, with mean and median emissions rate of 0.00036 

kg/MMBtu and 0.00027 kb/MMBtu, respectively. 

CH4 emissions from source FRF1 were significantly higher than emissions from the other four DCE 

furnaces tested during this study. One of the sample runs at source ARF3 did not meet the QA spiking 

requirements for N2O and was subsequently removed from the dataset. The cause of the low spike 

recovery could not be determined. 
Technical Bulletin No. 998 25 

National Council for Air and Stream Improvement 

5.2 Drivers of Methane (CH4) and Nitrous Oxide (N2O) Formation and Emissions 

The variability observed in CH4 and N2O emissions can be attributed to a number of factors. In the 

case of CH4, combustion conditions inside the boiler are expected to be the dominant contributing 

factor. N2O emissions, on the other hand, can be influenced both by combustion conditions and fuel 

nitrogen content. 

According to Flagan and Seinfeld (1988), the oxidation rate of hydrocarbons like CH4 increases when 

combustion parameters are maintained at optimum levels. CH4 oxidation rates are expected to 

decrease and emissions are expected to increase when combustion conditions do not allow for 

complete mixing of fuel and air, or when oxidation reactions are quenched early in the combustion 

process. In general, boiler parameters or operating conditions that result in an increase in CO 

concentrations are also likely to lead to increases in CH4. As discussed earlier, both CO 

concentrations and CH4 emissions at sources FBB1 and YCB1 were higher than those observed at the 

other sources. 

The formation of N2O within a boiler is a more complicated process. N2O emissions depend on fuel 

nitrogen content and combustion parameters like temperature, excess air, boiler load, and catalytic 

activity of char and mineral matter. N2O emissions, if attributed purely to fuel nitrogen content, 

would exhibit the following order: emissions from coal > lignite > peat > wood (Leckner 1998). The 

difference between wood/wood residuals/bark and kraft pulping liquor, as it relates to the potential to 

generate N2O emissions, is not clear. It has been shown that most of the nitrogen in wood is 

transferred to the black liquor during kraft pulping. As a consequence, fuel nitrogen is not expected to 

be the contributing factor of the differential in N2O emissions observed between solid biomass fuels 

and kraft pulping liquor in this study (Veverka et al. 1993). 

While several combustion parameters can have minor effects on N2O formation, changes in 

combustion temperature are expected to have the most dramatic impact. Studies have established that 

N2O formation peaks around 700°C. On the other hand, combustion temperatures below 500°C and 

above 950°C prevent the formation of N2O (Tsupari 2007). Although information on combustion 

zone temperatures was not available for the sources tested during this study, they were expected to be 

higher than 950oC and therefore not expected to be a factor. This parameter is potentially more 

important in fluidized bed boilers, where boiler temperatures can be lower than 950°C (Fortum 2001, 

Bonn, Pelz, and Baumann 1995). 

As discussed above, several parameters can influence the formation of CH4 and N2O during 

combustion. A study that correlates CH4 and N2O emissions to these parameters would involve a 

more comprehensive testing plan that encompasses varying ranges of these parameters, in conjunction 

with the ability to reliably measure these variations. Such an analysis is beyond the scope of this 

study. 

To the extent that fuel characteristics may dictate the efficiency of combustion and any related 

combustion parameters, the co-firing of fossil fuels along with biomass may also have an impact on 

both CH4 and N2O emissions. This study was geared towards developing emission factors for biomass 

firing and not intended to investigate the impact of co-firing. As discussed earlier, all the boilers 

included in this study were predominantly burning biomass fuels. In the case of boilers that co-fired 

No. 6 fuel oil, heat inputs from oil were ~ 10% and not variable enough to develop trends in 

emissions. The impact of co-firing can be better investigated by carrying out tests with varying levels 

of co-firing. 
26 Technical Bulletin No. 998 

National Council for Air and Stream Improvement 

5.3 Existing Emission Factors 

In the GHGRR, EPA mandates the use of specific emission factors when quantifying the emissions of 

CH4 and N2O due to the burning of solid biomass fuels and kraft pulping liquors in boilers and 

recovery furnaces, respectively. These factors were derived primarily from previously reported values 

by the IPCC and WRI/WBCSD, two of the most prominent international agencies studying GHG 

emissions and compiling available emission factors. Table 5.1 reproduces currently available CH4

and N2O emission factors published by WRI/WBCSD and Tier 1 factors from IPCC (WRI/WBSCD 

2005, IPCC 2006). These factors are reported in kilogram per terajoule (kg/TJ) and utilize a low 

heating value (LHV). 

Table 5.1 WRI/WBCSD and IPCC Emission Factors 

kg kg 

Emission Factor Description CH4/TJ N2O/TJ Reference

Wood waste-fired boilers

Wood, wood waste, and other biomass and 

wastes 

30 4 Tier 1 – IPCC 2006

Uncontrolled emissions from wood-fired stoker 

 boilers 

15 - Tier 2 – IPCC 1997

Average for wood residue combustion 9.5a 5.9a USEPA 2001

Average for circulating fluidized bed boilers 

burning 

 peat or bark 

1 8.8 Fortum 2001

Average for bubbling fluidized bed boilers burning 

 peat or bark 

2b <2 Fortum 2001

Pre-1980 wood residue-fired stoker boilers sampled 

 ahead of control devices 

8.2a - NCASI 1980

Pre-1980 wood residue-fired stoker boilers sampled 

 after wet scrubbers 

2.7a - NCASI 1985

Wood-fired boiler 41c 3.1c JPA 2001

Wood as fuel 24c 3.4c AEA Tech. 2001

Wood waste 30 5 Swedish EPA 2004

WRI Median emission factors for wood waste 12 4 

1 – 40 1.4 – 75 EEA 2004

Recovery furnaces

Sulfite lyes (Black Liquor) 3 2 Tier 1 – IPCC 2006

Recovery furnace <1 <1 Fortum 2001

Recovery furnace – black liquor 2.5d - JPA 2001

Black liquor 30 5 Swedish EPA 2004

 WRI Median emission factors for black liquor 2.5 2 

1 – 17.7 1 – 21.4 EEA 2004

a

 Converted from GCV to NCV assuming a 5% difference. 

b

 Excludes one very high number associated with low oxygen-high carbon monoxide conditions. 

c

 Based on heat content of 20 GJ/t dry solids. 

d

 Based on liquor heat content of 13.3 GJ/t dry solids. 
Technical Bulletin No. 998 27 

National Council for Air and Stream Improvement 

As discussed earlier, there is significant variability in the emission factors provided in Table 5.1. 

Additional factors, besides fuel and operating parameters, may have contributed to this variability in 

previously reported emission factors. Some of these factors have been estimated based on limited data 

or data derived from measurements that utilized improper sampling techniques (Fortum 2001; Muzio 

et al. 1989). An example of an improper sampling technique would be the collection of an 

unconditioned grab sample that is subsequently shipped off-site for analysis. It has been shown that 

N2O can be generated within a collection vessel from compounds typically found in combination 

boilers and recovery furnaces. Therefore, any emission factors for N2O that are derived from 

improperly conditioned grab samples are likely to overestimate actual emissions. Appendix C 

provides an example of this artifact formation along with a more detailed discussion of the 

mechanism. 

IPCC has taken these considerations into account and has estimated the uncertainties in its 

measurements. For CH4, it estimates an uncertainty range of 50% to 150%, while the uncertainty 

associated with N2O measurement is an order of magnitude higher. 

To compare the results of our study with previously published emission factors, the IPCC and 

WRI/WBCSD factors must first be converted to kg/MMBtu and then adjusted from a LHV to a HHV. 

This adjustment can be made using the assumption that there is a 5% difference in heat values for 

biomass fuels. The IPCC, WRI/WBCSD, and EPA factors do not distinguish between DCE and 

NDCE recovery furnaces. Consequently, for purposes of comparison, the existing emission factors 

have been assumed to apply to both recovery furnace categories. Methane and nitrous oxide emission 

factors are shown in Tables 5.2 and 5.3, respectively. 

Table 5.2 CH4 Emissions, kg/MMBtu 

IPCCa,d 

WRI/WBCSD 

GHG Protocolb,d EPAc

NCASI Study 

Mean 

(%RSD) 

NCASI Study 

(range) 

Biomass-fired

 boilers 

0.032 0.012 0.032 0.0049

(232%) 

ND<[0.00012] –

0.046 

Non-DCE

 furnaces e 

0.0030 0.0025 0.030 0.0014 

(117%)

0.000042 – 0.0031

DCE furnaces e 0.0030 0.0025 0.030 0.0024 

(187%)

0.00011 – 0.010

a

 IPCC (2006). 

b

 WRI/WBCSD (2005). 

c

 Emission factors mandated for use in GHG Inventories (USEPA 2009). 

d Factors are converted from LHV to HHV assuming a 5% difference. 

e

 DCE and NDCE furnaces have the same emission factors. EPA mandates the use of a single emission factor 

for kraft pulping liquor (North American Softwood). 
28 Technical Bulletin No. 998 

National Council for Air and Stream Improvement 

Table 5.3 N2O Emissions, kg/MMBtu 

IPCCa 

WRI/WBCSD 

GHG Protocolb,d EPAc

NCASI Study 

Mean 

(%RSD) 

NCASI Study 

(range) 

Biomass-fired

 boilers 

0.0042 0.0042 0.0042 0.0019 

(61%)

0.00073 – 0.0034

Non-DCE

 furnaces e 

0.0020 0.0020 0.0050 0.00044 

(79%)

0.00015 – 0.00082

DCE furnaces e 0.0020 0.0020 0.0050 0.00036 

(57%)

0.00019 – 0.00065

a

 IPCC (2006). 

b

 WRI/WBCSD (2005). 

c

 Emission factors mandated for use in GHG Inventories (USEPA 2009). 

d Factors are converted from LHV to HHV assuming a 5% difference. 

e

 DCE and NDCE furnaces have the same emission factors. EPA mandates the use of a single emission factor 

for kraft pulping liquor (North American Softwood). 

As indicated in Tables 5.2 and 5.3, the emission factors for CH4 and N2O developed during this study 

are lower than those mandated by EPA for these three source categories. The CH4 and N2O emission 

factors developed during this study for biomass boilers are substantially lower than the EPA, IPCC, 

and WRI/WBCSD factors. In the case of kraft pulping liquors, CH4 and N2O emission factors 

developed during this study are over an order of magnitude lower than EPA mandated factors. 

6.0 CONCLUSIONS 

An NCASI review of more recent literature indicates a dearth of accurate and direct emission 

measurements of CH4 and N2O from biomass-fired boilers and kraft recovery furnaces. As a result, 

the validity of existing emission factors, including those mandated by EPA in the GHG reporting rule, 

has come under scrutiny. Given the emphasis being placed on GHG inventories, the limited data 

availability, and uncertainty surrounding currently available emission factors, NCASI carried out a 

study to develop additional data for CH4 and N2O emissions from these sources.

As part of the NCASI testing study, CH4 and N2O stack concentrations were measured using a 

portable FTIR spectrometer. When the sample stream was properly conditioned, the FTIR provided 

reliable analysis for the target analytes with acceptable detection limits. Quality assurance results 

confirmed the accuracy of the analysis. Additionally, CH4 data from the 2009 Boiler MACT/CISWI 

testing were gathered and incorporated into the study. 

NCASI conducted emission measurements at 13 sources, including five wood-fired combination 

boilers, five DCE recovery furnaces, and three NDCE recovery furnaces. From the 2009 Boiler 

MACT/CISWI testing program, CH4 data from 19 boilers and three CISWI units were also 

incorporated into this study. For wood/biomass fired boilers, the mean and median CH4 emission 

factors were 0.0049 kg/MMBtu and 0.0012 kg/MMBtu, respectively. CH4 emissions from two of 

these boilers were approximately five times larger than those observed at the other sources and 

contributed to the higher mean emission factors as compared to the median. The higher CH4

emissions could be explained by the higher CO concentrations observed on these sources. The mean 

and median N2O emission factors for wood/biomass fired boilers were 0.0019 kg/MMBtu and 0.0015 

kg/MMBtu, respectively. For DCE recovery furnaces, mean and median CH4 emission factors were 

0.0024 kg/MMBtu and 0.00020 kg/MMBtu, respectively. The mean and median N2O emission 
Technical Bulletin No. 998 29 

National Council for Air and Stream Improvement 

factors were 0.00036 kg/MMBtu and 0.00027 kg/MMBtu, respectively. For NDCE recovery 

furnaces, the mean and median CH4 emission factors were 0.0014 kg/MMBtu HHV and 0.00093 

kg/MMBtu, respectively. The mean and median N2O emission factors were 0.00044 kg/MMBtu and 

0.00034 kg/MMBtu, respectively. 

The emission factors for CH4 and N2O developed during this study are lower than those mandated by 

EPA for use in GHG inventories for these three source categories. The CH4 and N2O emission factors 

developed during this study for biomass boilers are substantially lower than the EPA, IPCC, and 

WRI/WBCSD factors. In the case of kraft pulping liquors, CH4 and N2O emission factors developed 

during this study for DCE and NCDE recovery furnaces are over an order of magnitude lower than 

EPA mandated factors. 

REFERENCES 

AEA Technology. 2001. UK greenhouse gas inventory 1990–1999: Annual report for submission 

under the Framework Convention on Climate Change. Oxfordshire, England: AEA Technology 

National Environmental Technology Centre. 

American Society for Testing and Materials (ASTM). 2003. Standard Test Method D 6348-03 –

Determination of gaseous compounds by extractive direct interface Fourier transform infrared 

(FTIR) spectroscopy. West Conshohocken, PA: American Society for Testing and Materials. 

Bonn, B., Pelz, G., and Baumann, H. 1995. Formation and decomposition of N2O in fluidized bed 

boilers. Fuel 74:165-171. http://dx.doi.org/10.1016/0016-2361(95)92650-U

European Environment Agency (EEA). 2004. EMEP/CORINAIR Emission inventory guidebook 3rd

ed., September 2004 update. Copenhagen: European Environment Agency. 

Flagan, R.C., and Seinfeld, J.H. 1988. Fundamentals of air pollution engineering. Englewood Cliffs, 

NJ: Prentice Hall.

Fortum Power and Heat Oy (Fortum). 2001. Methane and nitrous oxide emissions in the Finnish 

energy production. Fortum, Finland: Fortum Power and Heat Oy. 

Intergovernmental Panel on Climate Change (IPCC). 1996. Climate change 1995, the science of 

climate change. New York, NY: Cambridge University Press. 

———. 1997. Revised 1996 IPCC guidelines for national greenhouse gas inventories: Reference 

manual (Vol. 3). IPCC National Greenhouse Gas Inventory Program. 

___________. 2006. 2006 IPCC Guidelines for national greenhouse gas inventories. Hayama, 

Kanagawa, Japan: Intergovernmental Panel on Climate Change, Institute for Global 

Environmental Strategies. 

Japan Paper Association (JPA). 2002. Various personal communications between JPA and Reid 

Miner of NCASI. Tokyo: Japan Paper Association. 

Leckner, B. 1998. Fluidized bed combustion: Mixing and pollutant limitation. Progress in Energy 

and Combustion Science 24:31-61. http://dx.doi.org/10.1016/S0360-1285(97)00021-X

Muzio, L.J., Teague, M.E., Kramlich, J.C., Cole, J.A., McCarthy, J.M., and Lyon, R.K. 1989. Errors 

in grab sample measurements of N2O from combustion sources. Journal of the Air Pollution 

Control Association 39:287-293. 

National Council [of the Paper Industry] for Air and Stream Improvement, Inc. (NCASI). 1980. A 

study of wood-residue fired power boiler total gaseous non-methane organic emissions in the 
30 Technical Bulletin No. 998 

National Council for Air and Stream Improvement 

Pacific Northwest. Air Quality Technical Bulletin No. 109. New York: National Council of the 

Paper Industry for Air and Stream Improvement, Inc. 

———. 1985. Volatile organic carbon emissions from wood residue fired power boilers in the 

Southeast. Technical Bulletin No. 455. New York: National Council of the Paper Industry for Air 

and Stream Improvement, Inc. 

———. 2009a. Revised statistical data treatment procedures for pulp and paper mill 'air toxic' 

emissions data. In SARA handbook (04.F.01). Research Triangle Park, NC: National Council for 

Air and Stream Improvement, Inc. 

———. 2009b. Appendix A: An overview of the steps and statistical procedures used to develop air 

emissions factors for the wood products industry. In SARA handbook (03.B.24). Research 

Triangle Park, NC: National Council for Air and Stream Improvement, Inc. 

Swedish Environmental Protection Agency (Swedish EPA). 2004. Sweden’s national inventory report 

2004 – Submitted under the United National Convention on Climate Change. Stockholm: 

Swedish Environmental Protection Agency. 

Tsupari, E., Monni, S., Tormonen, K., Pellikka, T., and Syri, S. 2007. Estimation of annual CH4 and 

N2O emissions from fluidized bed combustion: An advance measurement-based method and its 

application to Finland. International Journal of Greenhouse Gas Control 1:289-297. 

http://dx.doi.org/10.1016/S1750-5836(07)00019-9

United States Environmental Protection Agency (USEPA). 1999. Method 320 – Measurement of 

vapor phase organic and inorganic emissions by extractive Fourier Transform Infrared (FTIR) 

spectroscopy. Part 63, Appendix A. Federal Register 64(113): 31937-31951. June 14. 

———. 2000. 40 CFR Part 60, 61, and 63 Amendments for testing and monitoring provisions; final 

rule. Federal Register 65(201): 61743-62273. October 17. http://www.gpo.gov/fdsys/pkg/FR2000-10-17/pdf/FR-2000-10-17.pdf

———. 2001. AP-42 emission factors for wood residue combustion in boilers – Supplement G, July 

2001. Washington, DC: United States Environmental Protection Agency. 

———. 2009. Mandatory Reporting of Greenhouse Gases. (40 CFR Part 98). Federal Register

74(209): 56260-56519. 

Veverka, P.J., Nichols, K.M., Horton, R.R., and Adams, T.N. 1993. On the form of nitrogen in wood 

and its fate during kraft pulping. IPST Technical Paper Series Number 460. Atlanta, GA: Institute 

of Paper Science and Technology. 

The World Research Institute and The World Business Council for Sustainable Development 

(WRI/WBCSD). 2005. Calculation tools for estimating greenhouse gas emissions from pulp and 

paper mills. Report version 1.1. The World Resource Institute and The World Business Council 

for Sustainable Development Greenhouse Gas Protocol Initiative. 
A1 

APPENDIX A 

DETAILED SOURCE RESULTS 

Table A1 Run Data for Source ARF3 

Test Parameters 

Date 1/13/2009 1/14/2009 1/14/2009 1/14/2009 

Stack Pressure (in. Hg) 29.68 30.06 30.03 29.96 

Stack Temperature (°F) 321 318 318 319 

Percent O2 (%) 5.80 6.85 6.40 6.85 

Percent CO2 (%) 14.25 13.65 14.05 13.65 

Percent H O 2 (%) 33.77 33.81 34.65 33.88 

Stack Velocity (ft/sec) 67.24 60.81 60.12 60.33 

Stack Flow Rate (acfm) 184922 167220 165322 165920 

Stack Flow Rate (dscfm) 82065 75459 73595 74471 

 

Run Number 1 2 3 4 5 6 7 8 

BLS Fired (lb/hr) 81343 81759 75040 75000 75012 74981 74958 74978 

BLS Heat Input (MMBtu/hr) 465.4 467.7 429.3 429.1 429.1 429.0 428.8 429.0 

Oil Heat Input (MMBtu/hr) 33.2 32.5 0 0 37.0 37.0 15.5 16.3 

Total Input (MMBtu/hr) 498.6 500.2 429.3 429.1 466.1 466.0 444.3 445.2 

 

CH4 Results 

Concentration (ppmvd) 0.79 3.65 0.50 0.68 1.04 0.90 0.63 0.43 

Mass Emission (lb/hr) 0.16 0.75 0.09 0.13 0.19 0.16 0.12 0.08 

Production Based 

Emission (kg/MMBtu) 0.00015 0.00068 0.00010 0.00014 0.00019 0.00016 0.00012 0.00008 

Number of Detects 21/30 25/30 7/30 9/30 15/30 17/30 2/30 3/30 

Spike Recovery (%) 100.4 85.0 95.8 82.3 

 

N O Results 2 

Concentration (ppmvd) 0.84 0.63 0.51 0.53 0.72 0.55 0.46 0.25 

Mass Emission (lb/hr) 0.47 0.36 0.26 0.28 0.36 0.28 0.24 0.13 

Production Based 

Emission (kg/MMBtu) 0.00043 0.00032 0.00028 0.00029 0.00035 0.00027 0.00024 0.00013 

Number of Detects 30/30 24/30 40/40 27/30 29/30 28/30 27/30 23/30 

Spike Recovery (%) 85.0 61.0 78.7 88.7 

 
Table A2 Analysis Method for Source ARF3 

Method: GHG Mill A Recovery

Analyte List Unit Compensation References Interferences Analysis Area 1 

Water Vapor % Wet 21 9 3200-3450 

Carbon Dioxide % Dry 14 7 2015-2215 

Carbon Monoxide ppm Dry 19 6 2005-2177 

Nitrous Oxide ppm Dry 6 5 2138-2231 

Nitric Oxide ppm Dry 12 24 1829-2020 

Nitrogen Dioxide ppm Dry 5 37 2800-3000 

Methane ppm Dry 6 14 2956-3203 

Ethylene ppm Dry 5 41 895-1134 

Sulfur Dioxide ppm Dry 6 23 1057-1259 

Oxygen % Sensor 
Table A3 Run Data for Source ABB2 

Test Parameters 

Date 7/8/2008 7/8/2008 

Stack Pressure (in. Hg) 29.86 29.82 

Stack Temperature (°F) 144 141 

Percent O2 (%) 8.7 11.7 

Percent CO2 (%) 11.4 7.6 

Percent H O 2 (%) 24.79 23.66 

Stack Velocity (ft/sec) 50.36 50.93 

Stack Flow Rate (acfm) 254419 257322 

Stack Flow Rate (dscfm) 167038 172107 

Run Number 1 2 3 4 

Bark Fired (lb/hr) 53418 59728 51507 38639 

Bark Heat Input (MMBtu/hr) 427.3 477.8 412.1 309.1 

CH4 Results 

Concentration (ppmvd) 1.0 2.1 3.2 

Mass Emission (lb/hr) 0.42 0.88 1.38 

Production Based Emission (kg/MMBtu) 0.00044 0.00083 0.0015 

Number of Detects 1/1 1/1 1/1 

Spike Recovery (%) 

N O Results 2

Concentration (ppmvd) 1.52 1.3 1.74 2.32 

Mass Emission (lb/hr) 1.74 1.49 2.06 2.74 

Production Based Emission (kg/MMBtu) 0.0018 0.0014 0.0023 0.0040 

Number of Detects 5/5 5/5 5/5 5/5 

Spike Recovery (%) 89.9 92.7 90.5 93.7 
Table A4 Analysis Method for Source ABB2 

Method: GHG Mill A Bark Boiler (Cond)

Analyte List Unit Compensation References Interferences Analysis Area 1 

Water Vapor % Wet 21 10 3200-3450 

Carbon Dioxide % Dry 9 7 2015-2215 

Carbon Monoxide ppm Dry 19 6 2005-2177 

Nitrous Oxide ppm Dry 6 5 2146-2223 

Nitric Oxide ppm Dry 12 23 1829-2020 

Nitrogen Dioxide ppm Dry 5 37 2800-3000 

Methane ppm Dry 6 14 2956-3203 

Methanol ppm Dry 5 37 930-1120 

-Pinene ppm Dry 3 39 2625-3250 

-Pinene ppm Dry 4 37 2750-3105 

Limonene ppm Dry 3 40 895-976 

Oxygen % Sensor 
Table A5 Run Data for Source BRF5 

Test Parameters 

Date 5/6/2008 5/6/2008 5/7/2008 5/7/2008 

Stack Pressure (in. Hg) 29.75 29.74 29.67 29.63 

Stack Temperature (°F) 425 422 424 422 

Percent O2 (%) 6.9 6.5 8.8 7.0 

Percent CO2 (%) 12.4 12.5 11.3 11.0 

Percent H O 2 (%) 28.01 27.74 25.96 25.41 

Stack Velocity (ft/sec) 49.27 50.23 48.75 49.05 

Stack Flow Rate (acfm) 376131 383488 372188 374435 

Stack Flow Rate (dscfm) 160605 164794 163163 165557 

 

Run Number 1 2 3 4 

BLS Fired (lb/hr) 107488 112749 103360 87966 

BLS Heat Input (MMBtu/hr) 432.1 453.3 415.5 353.6 

 

CH4 Results 

Concentration (ppmvd) 2.14 1.75 13.95 ND[0.85] 

Mass Emission (lb/hr) 0.86 0.72 5.68 ND[0.30] 

Production Based 

Emission (kg/MMBtu) 0.00090 0.00072 0.0062 ND[0.00039] 

Number of Detects 24/30 18/30 30/30 0/30 

Spike Recovery (%) 83.8 134.5 49.7 

N O Results 2 

Concentration (ppmvd) 0.54 0.57 0.71 0.77 

Mass Emission (lb/hr) 0.59 0.65 0.79 0.87 

Production Based 

Emission (kg/MMBtu) 0.00062 0.00065 0.00086 0.00111 

Number of Detects 23/30 24/30 5/30 27/30 

Spike Recovery (%) 123.7 111.4 116.7 92.2 
Table A6 Analysis Method for Source BRF5 

Method: GHG Mill B Recovery Boiler (Cond)

Analyte List Unit Compensation References Interferences Analysis Area 1 

Water Vapor % Wet 21 10 3200-3450 

Carbon Dioxide % Dry 9 7 2015-2215 

Carbon Monoxide ppm Dry 19 6 2005-2177 

Nitrous Oxide ppm Dry 6 5 2146-2223 

Nitric Oxide ppm Dry 12 20 1829-2020 

Nitrogen Dioxide ppm Dry 5 33 1552-1625 

Methane ppm Dry 6 14 2771-3203 

Hydrochloric Acid ppm Dry 4 28 2532-2879 

Methanol ppm Dry 5 30 930-1120 

Dimethyl Sulfide ppm Dry 1 34 903-1142 

Sulfur Dioxide ppm Dry 6 23 1057-1259 

Oxygen % Sensor 
Table A7 Run Data for Source CCB4 

Test Parameters 

Date 12/2/2008 12/4/2008 

Stack Pressure (in. Hg) 30.25 30.21 

Stack Temperature (°F) 441 464 

Percent O2 (%) 9.0 8.5 

Percent CO2 (%) 11.5 11.8 

Percent H O 2 (%) 15.13 18.76 

Stack Velocity (ft/sec) 64.99 66.43 

Stack Flow Rate (acfm) 196005 200346 

Stack Flow Rate (dscfm) 98436 93827 

Run Number 1 2 3 4 

Bark Fired (lb/hr) 69980 66040 70300 74140 650

Bark Heat Input (MMBtu/hr) 329.9 313.2 335.0 350.2 31

Oil Fired (lb/hr) 2375 2391 2336 2348 16

Oil Heat Input (MMBtu/hr) 44.80 45.12 44.07 44.31 31

Total Heat Input (MMBtu/hr) 374.7 358.3 379.1 394.5 34

CH4 Results 

Concentration (ppmvd) 2.57 1.27 17.02 16.97 24

Mass Emission (lb/hr) 0.63 0.31 3.99 3.98 5.

Production Based Emission (kg/MMBtu) 0.00076 0.00040 0.0048 0.0046 0.0

Number of Detects 8/8 5/5 8/8 5/5 8

Spike Recovery (%) 99.0 98.8 

N O Results 2

Concentration (ppmvd) 1.69 1.45 1.81 2.17 2.

Mass Emission (lb/hr) 1.14 0.98 1.16 1.39 1.

Production Based Emission (kg/MMBtu) 0.0014 0.0012 0.0014 0.0016 0.0

Number of Detects 8/8 5/5 8/8 5/5 8

Spike Recovery (%) 102.4 81.7 
Table A8 Analysis Method for Source CCB4 

Method: GHG Mill C Combination 

Analyte List Unit Compensation References Interferences Analysis Area 1 

Water Vapor % Wet 22 11 3200-3450 

Carbon Dioxide % Dry 9 7 2015-2215 

Carbon Monoxide ppm Dry 19 6 2005-2177 

Nitrous Oxide ppm Dry 6 5 2146-2223 

Nitric Oxide ppm Dry 12 24 1829-2020 

Nitrogen Dioxide ppm Dry 5 38 2800-3000 

Methane ppm Dry 6 14 2956-3203 

Sulfur Dioxide ppm Dry 6 23 1057-1259 

Oxygen % Sensor 
Table A9 Run Data for Source DRF1 

Test Parameters 

Date 2/17/2009 2/17/2009 

Stack Pressure (in. Hg) 29.97 29.83 

Stack Temperature (°F) 378 379 

Percent O2 (%) 4.2 3.9 

Percent CO2 (%) 15.8 16.0 

Percent H O (%) 2 27.57 28.14 

Stack Velocity (ft/sec) 64.44 65.49 

Stack Flow Rate (acfm) 539888 548653 

Stack Flow Rate (dscfm) 246690 247370 

Run Number 1 2 3 4 5 6 

BLS Fired (lb/hr) 228794 228575 228768 229131 228971 228156 2

BLS Heat Input (MMBtu/hr) 1401.4 1400.0 1401.2 1403.4 1402.4 1397.5 1

CH4 Results 

Concentration (ppmvd) 0.21 0.24 0.21 0.23 0.17 0.24 

Mass Emission (lb/hr) 0.13 0.15 0.13 0.14 0.11 0.15 

Production Based 

Emission (kg/MMBtu) 0.000042 0.000047 0.000041 0.000046 0.000034 0.000047 0.0

Number of Detects 0/5 0/6 0/5 0/5 0/5 1/5 

Spike Recovery (%) 93.0 

N O Results 2

Concentration (ppmvd) ND[0.45] 0.22 ND[0.33] ND[0.29] 0.33 0.32 ND

Mass Emission (lb/hr) ND[0.77] 0.38 ND[0.55] ND[0.49 0.56 0.55 ND

Production Based 

Emission (kg/MMBtu) ND[0.00023] 0.00012 ND[0.00018] ND[0.00016] 0.00018 0.00018 ND[

Number of Detects 0/5 1/6 0/5 0/5 3/5 4/5 

Spike Recovery (%) 85.6 81.5 80.2 
Table A10 Analysis Method for Source DRF1 

Method: GHG Mill D

Analyte List Unit Compensation References Interferences Analysis Area 1 

Water Vapor % Wet 21 9 3200-3450 

Carbon Dioxide % Dry 14 7 2015-2215 

Carbon Monoxide ppm Dry 19 6 2005-2177 

Nitrous Oxide ppm Dry 6 5 2138-2231 

Nitric Oxide ppm Dry 12 24 1829-2020 

Nitrogen Dioxide ppm Dry 5 37 2800-3000 

Methane ppm Dry 6 14 2956-3203 

Ethylene ppm Dry 5 41 895-1134 

Sulfur Dioxide ppm Dry 6 23 1057-1259 

Oxygen % Sensor 
Table A11 Run Data for Source DBB1 

Test Parameters 

Date 2/18/2009 2/18/2009 2/18/2009 2/19/2009 

Stack Pressure (in. Hg) 29.57 29.48 29.41 30.12 

Stack Temperature (°F) 326 330 330 304 

Percent O2 (%) 11.6 12.3 11.9 12.9 

Percent CO2 (%) 8.4 8.2 8.6 7.2 

Percent H O 2 (%) 15.16 14.90 14.99 12.92 

Stack Velocity (ft/sec) 66.64 74.60 73.50 59.55 

Stack Flow Rate (acfm) 263889 295393 291057 235819 

Stack Flow Rate (dscfm) 148510 165580 162413 142896 

 

Run Number 1 2 3 4 5 6 7 8 

Bark Fired (lb/hr) 102643 94210 103480 103272 105986 111673 88132 66489 88

Bark Heat Input (MMBtu/hr) 461.9 423.9 465.7 464.7 476.9 502.5 396.6 299.2 39

 

CH4 Results 

Concentration (ppmvd) 0.61 1.18 0.42 0.49 0.58 1.27 0.61 0.55 0

Mass Emission (lb/hr) 0.23 0.44 0.17 0.20 0.24 0.51 0.22 0.20 0

Production Based 

Emission (kg/MMBtu) 0.00022 0.00047 0.00017 0.00020 0.00022 0.00046 0.00025 0.00030 0.0

Number of Detects 6/6 5/5 4/5 6/6 5/5 6/6 7/7 5/5 5

Spike Recovery (%) 97.3 97.7 94.5 95.5 92.9 99.7 98.2 94.3 9

 

N O Results 2 

Concentration (ppmvd) 0.91 1.16 1.00 0.81 1.15 1.18 ND[0.55] 0.86 0

Mass Emission (lb/hr) 0.93 1.18 1.13 0.92 1.28 1.32 ND[0.54] 0.84 0

Production Based 

Emission (kg/MMBtu) 0.0009 0.0013 0.0011 0.0009 0.0012 0.0012 ND[0.0006] 0.0013 0.0

Number of Detects 6/6 5/5 5/5 6/6 5/5 6/6 0/5 5/5 5

Spike Recovery (%) 87.9 96.4 91.0 90.6 87.6 92.0 87.0 9

 
Table A12 Analysis Method for Source DBB1 

Method: GHG Mill D

Analyte List Unit Compensation References Interferences Analysis Area 1 

Water Vapor % Wet 21 9 3200-3450 

Carbon Dioxide % Dry 14 7 2015-2215 

Carbon Monoxide ppm Dry 19 6 2005-2177 

Nitrous Oxide ppm Dry 6 5 2138-2231 

Nitric Oxide ppm Dry 12 24 1829-2020 

Nitrogen Dioxide ppm Dry 5 37 2800-3000 

Methane ppm Dry 6 14 2956-3203 

Ethylene ppm Dry 5 41 895-1134 

Sulfur Dioxide ppm Dry 6 23 1057-1259 

Oxygen % Sensor 
Table A13 Run Data for Source ERF1 

Test Parameters 

Date 2/24/2009 2/24/2009 2

Stack Pressure (in. Hg) 30.47 30.37 

Stack Temperature (°F) 374 376 

Percent O2 (%) 4.1 3.7 

Percent CO2 (%) 15.1 15.4 

Percent H O 2 (%) 24.80 24.80 

Stack Velocity (ft/sec) 87.28 87.34 

Stack Flow Rate (acfm) 497680 497993 

Stack Flow Rate (dscfm) 241344 240244 

Run Number 1 2 3 4 5 6 7 8 

BLS Fired (lb/hr) 173298 173339 173323 173758 174545 174641 166068 1662

BLS Heat Input (MMBtu/hr) 947.9 948.2 948.1 950.6 954.8 955.3 908.4 909

 

CH4 Results 

Concentration (ppmvd) 0.23 4.38 19.42 9.98 3.07 17.87 10.83 13.3

Mass Emission (lb/hr) 0.14 2.64 11.71 6.02 1.84 10.73 6.63 8.1

Production Based 

Emission (kg/MMBtu) 0.00007 0.0013 0.0056 0.0029 0.0009 0.0051 0.0033 0.00

Number of Detects 1/10 5/5 6/6 5/5 5/5 5/5 7/7 5/5 

Spike Recovery (%) 96.8 101.3 98 97.8 98.5 97.5 97.

N O Results 2

Concentration (ppmvd) ND[0.13] ND[0.24] ND[0.65] ND[0.38] ND[0.21] ND[0.66] 0.77 ND[0

Mass Emission (lb/hr) ND[0.21] ND[0.39] ND[1.08] ND[0.63] ND[0.35] ND[1.08] 1.29 ND[0

Production Based 

Emission (kg/MMBtu) ND[0.0001] ND[0.00019] ND[0.00051] ND[0.0003] ND[0.00016] ND[0.00051] 0.00065 ND[0.0

Number of Detects 0/10 0/5 0/6 0/5 0/5 0/6 2/7 0/

Spike Recovery (%) 85.3 

 
Table A14 Analysis Method for Source ERF1 

Method: GHG Mill E

Analyte List Unit Compensation References Interferences Analysis Area 1 

Water Vapor % Wet 21 9 3200-3450 

Carbon Dioxide % Dry 14 7 2015-2215 

Carbon Monoxide ppm Dry 19 6 2005-2177 

Nitrous Oxide ppm Dry 6 5 2146-2215 

Nitric Oxide ppm Dry 12 24 1829-2020 

Nitrogen Dioxide ppm Dry 5 37 2800-3000 

Methane ppm Dry 6 14 2956-3203 

Oxygen % Sensor 
Table A15 Run Data for Source FRF1 

Test Parameters

Date 3/28/2009 3/28/20

Stack Pressure (in. Hg) 29.35 29.26

Stack Temperature (°F) 316 316

Percent O2 (%) 6.9 7.2

Percent CO2 (%) 12.1 12.5

Percent H O2 (%) 34.26 33.22

Stack Velocity (ft/sec) 40.88 40.91

Stack Flow Rate (acfm) 87765 87845

Stack Flow Rate (dscfm) 38485 3903

Run Number 1 2 3 4 5 

BLS Fired (lb/hr) 31680 31803 31957 31737 31562 

BLS Heat Input (MMBtu/hr) 186.9 187.6 188.5 187.2 186.2 

CH4 Results

Concentration (ppmvd) 60.01 67.12 42.18 25.87 8.40 

Mass Emission (lb/hr) 5.77 6.45 4.05 2.52 0.82 

Production Based Emission (kg/MMBtu) 0.0140 0.0156 0.0098 0.0061 0.002

Number of Detects 5/5 5/5 6/6 7/7 6/6 

Spike Recovery (%) 97.8 99.4 99.3 

N O Results 2

Concentration (ppmvd) 1.13 1.33 0.69 0.83 1.06 

Mass Emission (lb/hr) 0.30 0.35 0.18 0.22 0.28 

Production Based Emission (kg/MMBtu) 0.00072 0.00085 0.00044 0.00054 0.0006

Number of Detects 5/5 5/5 6/6 7/7 6/6 

Spike Recovery (%) 112.9 97.9 91.9 
Table A16 Analysis Method for Source FRF1 

Method: GHG Mill F

Analyte List Unit Compensation References Interferences Analysis Area 1 

Water Vapor % Wet 21 10 3200-3450 

Carbon Dioxide % Dry 14 7 2015-2215 

Carbon Monoxide ppm Dry 20 6 2005-2177 

Nitrous Oxide ppm Dry 6 5 2138-2215 

Nitric Oxide ppm Dry 12 24 1829-2020 

Nitrogen Dioxide ppm Dry 5 38 2800-3000 

Methane ppm Dry 6 14 2956-3203 

Ethylene ppm Dry 5 42 895-1134 

Sulfur Dioxide ppm Dry 6 23 1057-1259 

Oxygen % Sensor 
Table A17 Run Data for Source FRF3 

Test Parameters 

Date 3/25/2009 3/25/2009 

Stack Pressure (in. Hg) 29.63 29.58 

Stack Temperature (°F) 318 318 

Percent O2 (%) 7.3 7.2 

Percent CO2 (%) 12.8 12.8 

Percent H O 2 (%) 30.56 32.64 

Stack Velocity (ft/sec) 65.43 65.55 

Stack Flow Rate (acfm) 137030 137284 

Stack Flow Rate (dscfm) 63957 62039 

Run Number 1 2 3 4 5 6 7 

BLS Fired (lb/hr) 53174 53237 53408 52703 51262 51797 46136 

BLS Heat Input (MMBtu/hr) 313.7 314.1 315.1 311.0 302.5 305.6 272.2 

 

CH4 Results 

Concentration (ppmvd) 3.34 2.48 4.95 6.84 6.51 6.69 1.52 

Mass Emission (lb/hr) 0.53 0.40 0.79 1.06 1.01 1.04 0.24 

Production Based Emission (kg/MMBtu) 0.00077 0.00057 0.00114 0.00155 0.00151 0.00154 0.0004

Number of Detects 6/6 5/5 6/6 5/5 5/5 6/6 6/6 

Spike Recovery (%) 98.9 98.1 99.3 98.3 99.6 99.9 

N O Results 2

Concentration (ppmvd) 0.71 0.70 0.77 0.79 0.66 0.95 0.54 

Mass Emission (lb/hr) 0.31 0.31 0.34 0.34 0.28 0.40 0.24 

Production Based Emission (kg/MMBtu) 0.00045 0.00044 0.00049 0.00049 0.00042 0.00060 0.0003

Number of Detects 6/6 5/5 6/6 5/5 5/5 6/6 6/6 

Spike Recovery (%) 90.0 94.3 96.2 93.2 91.9 93.6 

 
Table A18 Analysis Method for Source FRF3 

Method: GHG Mill F

Analyte List Unit Compensation References Interferences Analysis Area 1 

Water Vapor % Wet 21 10 3200-3450 

Carbon Dioxide % Dry 14 7 2015-2215 

Carbon Monoxide ppm Dry 20 6 2005-2177 

Nitrous Oxide ppm Dry 6 5 2138-2215 

Nitric Oxide ppm Dry 12 24 1829-2020 

Nitrogen Dioxide ppm Dry 5 38 2800-3000 

Methane ppm Dry 6 14 2956-3203 

Ethylene ppm Dry 5 42 895-1134 

Sulfur Dioxide ppm Dry 6 23 1057-1259 

Oxygen % Sensor 
Table A19 Run Data for Source FBB1 

Test Parameters 

Date 3/23/2009 3/24/2009 3/2

Stack Pressure (in. Hg) 29.71 29.79 2

Stack Temperature (°F) 147 143 

Percent O2 (%) 6.8 8.7 

Percent CO2 (%) 10.3 9.7 

Percent H O 2 (%) 23.73 21.12 2

Stack Velocity (ft/sec) 30.29 29.76 3

Stack Flow Rate (acfm) 172724 169690 18

Stack Flow Rate (dscfm) 113795 116671 12

 

Run Number 1 2 3 4 5 6 7 8 

Bark Fired (lb/hr) 118414 105743 114525 125992 99798 88599 126158 1294

Bark Heat Input (MMBtu/hr) 503.3 449.4 486.7 535.5 424.1 376.6 536.2 550.

 

CH4 Results 

Concentration (ppmvd) 210.82 272.91 89.66 236.14 53.40 49.68 216.26 108.2

Mass Emission (lb/hr) 59.93 77.58 26.13 68.83 15.56 14.48 66.97 33.5

Production Based 

Emission (kg/MMBtu) 0.054 0.078 0.024 0.058 0.017 0.017 0.057 0.02

Number of Detects 5/5 5/5 5/5 6/6 6/6 6/6 6/6 5/5 

Spike Recovery (%) 101.3 100.2 101.5 99.8 99.6 97.7 100.

 

N O Results 2 

Concentration (ppmvd) 0.76 0.85 0.37 ND[0.61] 1.58 2.37 ND[0.61] 0.9

Mass Emission (lb/hr) 0.59 0.66 0.30 ND[0.48] 1.26 1.90 ND[0.51] 0.83 

Production Based 

Emission (kg/MMBtu) 0.00054 0.00067 0.00028 ND<[0.00041] 0.00135 0.00229 ND[0.00043] 0.000

Number of Detects 2/5 5/5 1/5 0/6 6/6 6/6 0/6 5/5 

Spike Recovery (%) 93.9 101.1 99.2 100.7 91.3 

 
Table A20 Analysis Method for Source FBB1 

Method: GHG Mill F Bark Boiler

Analyte List Unit Compensation References Interferences Analysis Area 1 

Water Vapor % Wet 21 10 3200-3450 

Carbon Dioxide % Dry 14 7 2015-2215 

Carbon Monoxide ppm Dry 20 6 2005-2177 

Nitrous Oxide ppm Dry 6 5 2138-2215 

Nitric Oxide ppm Dry 12 24 1829-2020 

Nitrogen Dioxide ppm Dry 5 38 2800-3000 

Methane ppm Dry 6 14 2956-3203 

Ethane ppm Dry 2 39 2663-3180 

Acetylene ppm Dry 1 43 1219-1428 

Ethylene ppm Dry 5 42 895-1134 

Formaldehyde ppm Dry 5 38 2500-3211 

Benzene ppm Dry 3 38 949-1096 

Oxygen % Sensor 
Table A21 Run Data for Source GRF1 

Test Parameters 

Date 6/11/2009 6/11/2009 

Stack Pressure (in. Hg) 29.82 29.77 

Stack Temperature (°F) 329 330 

Percent O2 (%) 6.6 6.9 

Percent CO2 (%) 14.2 13.9 

Percent H O 2 (%) 32.8 33.3 

Stack Velocity (ft/sec) 94.21 94.86 

Stack Flow Rate (acfm) 335070 337380 

Stack Flow Rate (dscfm) 150183 149616 

Run Number 1 2 3 4 5 

BLS Fired (lb/hr) 120100 121800 121800 121800 118

BLS Heat Input (MMBtu/hr) 672.6 682.1 682.1 682.1 664

CH4 Results 

Concentration (ppmvd) 0.44 0.40 0.45 0.59 0.4

Mass Emission (lb/hr) 0.17 0.15 0.17 0.22 0.

Production Based Emission (kg/MMBtu) 0.00011 0.00010 0.00011 0.00015 0.00

Number of Detects 0/5 0/5 0/5 2/5 0/

Spike Recovery (%) 99.1 

N O Results 2

Concentration (ppmvd) 0.17 0.28 0.46 0.38 0.2

Mass Emission (lb/hr) 0.17 0.29 0.47 0.39 0.2

Production Based Emission (kg/MMBtu) 0.00012 0.00019 0.00031 0.00026 0.00

Number of Detects 2/5 5/5 5/5 5/5 5/

Spike Recovery (%) 98.1 95.9 110.7 93
Table A22 Analysis Method for Source GRF1 

Method: GHG Mill G RF1

Analyte List Unit Compensation References Interferences Analysis Area 1 

Water Vapor % Wet 21 10 3200-3450 

Carbon Dioxide % Dry 14 7 2015-2215 

Carbon Monoxide ppm Dry 20 6 2005-2177 

Nitrous Oxide ppm Dry 6 5 2153-2207 

Nitric Oxide ppm Dry 12 24 1829-2020 

Nitrogen Dioxide ppm Dry 5 38 2800-3000 

Methane ppm Dry 6 14 2956-3203 

Ethylene ppm Dry 5 42 895-1134 

Sulfur Dioxide ppm Dry 6 23 1057-1259 

Oxygen % Sensor 
Table A23 Run Data for Source GRF2 

Test Parameters 

Date 6/9/2009 6/9/2009 

Stack Pressure (in. Hg) 29.74 29.69 

Stack Temperature (°F) 306 312 

Percent O2 (%) 8.3 7.4 

Percent CO2 (%) 12.8 13.6 

Percent H O 2 (%) 30.55 31.65 

Stack Velocity (ft/sec) 155.06 157.73 

Stack Flow Rate (acfm) 308726 314029 

Stack Flow Rate (dscfm) 146816 145521 

Run Number 1 2 3 4 5 

BLS Fired (lb/hr) 96600 98850 105900 106400 107

BLS Heat Input (MMBtu/hr) 541.0 553.6 593.0 595.8 599

CH4 Results 

Concentration (ppmvd) 0.53 ND[0.68] 0.47 0.37 0.4

Mass Emission (lb/hr) 0.19 ND[0.25] 0.17 0.14 0.

Production Based Emission (kg/MMBtu) 0.00016 ND[0.00020] 0.00013 0.00010 0.00

Number of Detects 3/30 0/30 14/30 7/30 12/

Spike Recovery (%) 93.8 

N O Results 2

Concentration (ppmvd) 0.30 0.40 0.12 0.16 0.2

Mass Emission (lb/hr) 0.30 0.40 0.12 0.16 0.2

Production Based Emission (kg/MMBtu) 0.00026 0.00033 0.000092 0.00012 0.00

Number of Detects 29/30 30/30 11/30 18/30 27/

Spike Recovery (%) 99.9 101.1 
Table A24 Analysis Method for Source GRF2 

Method: GHG Mill G RF2

Analyte List Unit Compensation References Interferences Analysis Area 1 

Water Vapor % Wet 21 10 3200-3450 

Carbon Dioxide % Dry 14 7 2015-2215 

Carbon Monoxide ppm Dry 20 6 2005-2177 

Nitrous Oxide ppm Dry 6 5 2138-2207 

Nitric Oxide ppm Dry 12 24 1829-2020 

Nitrogen Dioxide ppm Dry 5 38 2800-3000 

Methane ppm Dry 6 14 2956-3203 

Ethylene ppm Dry 5 42 895-1134 

Sulfur Dioxide ppm Dry 6 23 1057-1259 

Oxygen % Sensor 
Table A25 Run Data for Source GCB3 

Test Parameters 

Date 6/10/2009 6/10/2009 

Stack Pressure (in. Hg) 29.85 29.81 

Stack Temperature (°F) 146 147 

Percent O2 (%) 11.1 10.7 

Percent CO2 (%) 9.1 9.4 

Percent H O 2 (%) 30.01 26.16 

Stack Velocity (ft/sec) 73.29 72.75 

Stack Flow Rate (acfm) 207433 205919 

Stack Flow Rate (dscfm) 126259 131835 

Run Number 1 2 3 4 5 

Bark Fired (lb/hr) 61600 63333 67200 64800 640

Bark Heat Input (MMBtu/hr) 231.0 237.5 252.0 243.0 24

Oil Heat Input (MMBtu/hr) 0.0 1.5 2.0 6.0 1

Total Heat Input (MMBtu/hr) 231 239 254.0 249.0 24

CH4 Results 

Concentration (ppmvd) 1.59 1.09 1.27 0.94 1.

Mass Emission (lb/hr) 0.50 0.34 0.42 0.31 0.

Production Based Emission (kg/MMBtu) 0.00099 0.00065 0.00075 0.00056 0.00

Number of Detects 30/30 30/30 30/30 30/30 30

Spike Recovery (%) 101.3 99.0 

N O Results 2

Concentration (ppmvd) 1.20 1.48 2.22 2.25 2.

Mass Emission (lb/hr) 1.04 1.28 2.01 2.04 2.

Production Based Emission (kg/MMBtu) 0.0020 0.0024 0.0036 0.0037 0.0

Number of Detects 28/30 30/30 30/30 30/30 30

Spike Recovery (%) 101.1 109.3 
Table A26 Analysis Method for Source GCB3 

Method: GHG Mill G CB3

Analyte List Unit Compensation References Interferences Analysis Area 1 

Water Vapor % Wet 21 10 3200-3450 

Carbon Dioxide % Dry 14 7 2015-2215 

Carbon Monoxide ppm Dry 20 6 2005-2177 

Nitrous Oxide ppm Dry 6 5 2146-2200 

Nitric Oxide ppm Dry 12 24 1829-2020 

Nitrogen Dioxide ppm Dry 5 38 2800-3000 

Methane ppm Dry 6 14 2956-3203 

Ethylene ppm Dry 5 42 895-1134 

Sulfur Dioxide ppm Dry 6 23 1057-1259 

Oxygen % Sensor 
Table A27 Run Data for Source HCB1 

Test Parameters

Date 7/15/09 7/15/09 

Stack Flow Rate (dscfm) 86591 76897 

Run Number 1 2 

Bark (%) 88.8 88.8 

Resin Wood (%) 11.2 11.2 

Natural Gas (%) 0.0 0.0 

Total Heat Input (MMBtu/hr) 270.1 263.5 

CH4 Results

Concentration (ppmvd) ND[0.33] ND[0.34] 

Mass Emission (lb/hr) ND[0.072] ND[0.064] 

Production Based Emission (kg/MMBtu) ND[0.00012] ND[0.00011] 

Table A28 Run Data for Source ICB1 

Test Parameters

Date 7/14/09 7/15/09 

Stack Flow Rate (dscfm) 54929 55114 

Run Number 1 2 

Hog Fuel (%) 80.1 78.3 

Municipal Solid Waste (%) 19.8 20.6 

Natural Gas (%) 0.0 1.1 

Total Heat Input (MMBtu/hr) 207.6 204.5 

CH4 Results

Concentration (ppmvd) 6.0 5.2 

Mass Emission (lb/hr) 0.82 0.72 

Production Based Emission (kg/MMBtu) 0.0018 0.0016 
Table A29 Run Data for Source JCB2 

Test Parameters

Date 7/1/09 7/2/09 

Stack Flow Rate (dscfm) 160000 160000 

Run Number 1 2 

Bark (%) 81.5 81.5 

TDF (%) 18.0 18.0 

Fuel Oil (%) 0.6 0.6 

Total Heat Input (MMBtu/hr) 577.3 548.4 

CH4 Results

Concentration (ppmvd) 27.6 11.3 

Mass Emission (lb/hr) 11.03 4.52 

Production Based Emission (kg/MMBtu) 0.0087 0.0037 

Table A30 Run Data for Source KCB2 

Test Parameters

Date 8/4/09 8/4/09 

Stack Flow Rate (dscfm) 24393 24080 

Run Number 1 2 

Bark (MMBtu/hr) 100.0 100.0 

Total Heat Input (MMBtu/hr) 90.5 92.7 

CH4 Results

Concentration (ppmvd) 2.0 1.0 

Mass Emission (lb/hr) 0.12 0.060 

Production Based Emission (kg/MMBtu) 0.00061 0.00029 
Table A31 Run Data for Source LCB1 

Test Parameters

Date 8/13/09 8/13/09 

Stack Flow Rate (dscfm) 21242 23203 

Run Number 1 2 

Wood/Bark (%) 100.0 100.0 

Total Heat Input (MMBtu/hr) 77.7 72.2 

CH4 Results

Concentration (ppmvd) 2.96 1.03 

Mass Emission (lb/hr) 0.16 0.060 

Production Based Emission (kg/MMBtu) 0.00092 0.00037 

Table A32 Run Data for Source MCB3 

Test Parameters

Date 8/6/09 8/6/09 

Stack Flow Rate (dscfm) 11098 11213 

Run Number 1 2 

Wood Waste (%) 100.0 100.0 

Total Heat Input (MMBtu/hr) 47.17 46.10 

CH4 Results

Concentration (ppmvd) 0.82 0.92 

Mass Emission (lb/hr) 0.023 0.026 

Production Based Emission (kg/MMBtu) 0.00022 0.00025 
Table A33 Run Data for Source NCB1 

Test Parameters

Date 8/6/09 8/6/09 

Stack Flow Rate (dscfm) 80214 76785 

Run Number 1 2 

Bark (%) 100.0 100.0 

Total Heat Input (MMBtu/hr) 318.69 337.77 

CH4 Results

Concentration (ppmvd) 4.93 4.10 

Mass Emission (lb/hr) 0.99 0.79 

Production Based Emission (kg/MMBtu) 0.0014 0.0011 

Table A34 Run Data for Source OCB4 

Test Parameters

Date 8/11/09 8/11/09 

Stack Flow Rate (dscfm) 128000 127000 

Run Number 1 2 

Bark (%) 91.4 62.4 

Fuel Oil (%) 6.1 21.6 

Natural Gas (%) 2.5 16.0 

Total Heat Input (MMBtu/hr) 431.16 239.45 

CH4 Results

Concentration (ppmvd) 0.46 6.17 

Mass Emission (lb/hr) 0.15 1.96 

Production Based Emission (kg/MMBtu) 0.00015 0.00371 
Table A35 Run Data for Source PCB4 

Test Parameters

Date 8/5/09 8/5/09 

Stack Flow Rate (dscfm) 85489 80039 

Run Number 1 2 

Bark

WWT Sludge

TDF

Total Heat Input (MMBtu/hr) 337.1 351.0 

CH4 Results

Concentration (ppmvd) 0.60 0.61 

Mass Emission (lb/hr) 0.13 0.12 

Production Based Emission (kg/MMBtu) 0.00017 0.00016 

Table A36 Run Data for Source QCB8 

Test Parameters

Date 7/29/2009 7/29/2009 

Stack Flow Rate (dscfm) 53777 54131 

Run Number 1 2 

WWT Sludge (%) 62.0 62.0 

Wood/Bark (%) 38.0 38.0 

Total Heat Input (MMBtu/hr) 164.17 163.59 

CH4 Results

Concentration (ppmvd) 2.05 1.85 

Mass Emission (lb/hr) 0.28 0.25 

Production Based Emission (kg/MMBtu) 0.00076 0.00069 
Table A37 Run Data for Source RCB1 

Test Parameters

Date 9/2/2009 9/2/2009 

Stack Flow Rate (dscfm) 7226 7128 

Run Number 1 2 

Bark (%) 100.0 100.0 

Total Heat Input (MMBtu/hr) 27.92 26.47 

CH4 Results

Concentration (ppmvd) 12.2 2.2 

Mass Emission (lb/hr) 0.22 0.039 

Production Based Emission (kg/MMBtu) 0.00358 0.00067 

Table A38 Run Data for Source SCB1 

Test Parameters 

Date 8/14/2009 8/14/2009 

Stack Flow Rate (dscfm) 157931 159424 

Run Number 1 2 

Bark (%) 68.8 68.4 

Cross ties (%) 11.7 11.6 

Natural Gas (%) 9.4 9.3 

WWT Sludge (%) 5.9 6.2 

Total Heat Input (MMBtu/hr) 584.09 587.45 

CH4 Results

Concentration (ppmvd) 4.0 15.3 

Mass Emission (lb/hr) 1.58 6.09 

Production Based Emission (kg/MMBtu) 0.00123 0.00470 
Table A39 Run Data for Source TCB1 

Test Parameters

Date 8/11/2009 8/12/2009 

Stack Flow Rate (dscfm) 53484 48369 

Run Number 1 2 

Wood (%) 100.0 100.0 

Total Heat Input (MMBtu/hr) 182.02 139.73 

CH4 Results

Concentration (ppmvd) 1.59 4.24 

Mass Emission (lb/hr) 0.21 0.51 

Production Based Emission (kg/MMBtu) 0.00053 0.00166 

Table A40 Run Data for Source UCB2 

Test Parameters

Date 6/24/09 6/25/09 

Stack Flow Rate (dscfm) 191210 190684 

Run Number 1 2 

Wood/Bark (%) 77.2 78.2 

WWT Sludge (%) 5.0 9.1 

OCC Rejects (%) 17.0 11.9 

Natural Gas (%) 0.8 0.8 

Total Heat Input (MMBtu/hr) 725.32 765.32 

CH4 Results

Concentration (ppmvd) 16.7 8.0 

Mass Emission (lb/hr) 7.98 3.81 

Production Based Emission (kg/MMBtu) 0.00499 0.00226 
Table A41 Run Data for Source VCB2 

Test Parameters

Date 8/6/09 8/6/09 

Stack Flow Rate (dscfm) 132000 128000 

Run Number 1 2 

Bark (%) 61.6 61.6 

WWT Sludge (%) 19.3 19.3 

Cross Ties (%) 16.4 16.4 

Natural Gas (%) 2.7 2.7 

Total Heat Input (MMBtu/hr) 519.57 501.89 

CH4 Results

Concentration (ppmvd) 1.9 2.6 

Mass Emission (lb/hr) 0.63 0.83 

Production Based Emission (kg/MMBtu) 0.00055 0.00075 

Table A42 Run Data for Source WCB1 

Test Parameters

Date 7/30/2009 7/31/2009 

Stack Flow Rate (dscfm) 159000 157000 

Run Number 1 2 

Bark (%) 73.81 89.77 

OCC Rejects (%) 6.32 4.77 

Natural Gas (%) 10.88 0.6 

WWT Sludge (%) 8.99 3.85 

Total Heat Input (MMBtu/hr) 534.70 573.22 

CH4 Results

Concentration (ppmvd) 3.8 4.4 

Mass Emission (lb/hr) 1.51 1.73 

Production Based Emission (kg/MMBtu) 0.00128 0.00137 
Table A43 Run Data for Source XCB1 

Test Parameters

Date 8/13/2009 8/13/2009 

Stack Flow Rate (dscfm) 46530 44430 

Run Number 1 2 

Bark (%) 100.0 100.0 

Total Heat Input (MMBtu/hr) 168.87 175.30 

CH4 Results

Concentration (ppmvd) 17.9 13.1 

Mass Emission (lb/hr) 2.08 1.45 

Production Based Emission (kg/MMBtu) 0.0056 0.0038 

Table A44 Run Data for Source YCB1 

Test Parameters

Date 8/6/2009 8/7/2009 

Stack Flow Rate (dscfm) 84245 85641 

Run Number 1 2 

Bark (%) 92.9 94.4 

Natural Gas (%) 7.1 5.6 

Total Heat Input (MMBtu/hr) 373.68 353.90 

CH4 Results

Concentration (ppmvd) 189.54 205.80 

Mass Emission (lb/hr) 39.89 44.03 

Production Based Emission (kg/MMBtu) 0.048 0.056 
Table A45 Run Data for Source ZCB1 

Test Parameters

Date 10/8/2009 10/8/2009 

Stack Flow Rate (dscfm) 15438 15576 

Run Number

Bark (%) 100.0 100.0 

Total Heat Input (MMBtu/hr) 15.66 16.44 

CH4 Results

Concentration (ppmvd) 4.11 3.95 

Mass Emission (lb/hr) 0.16 0.15 

Production Based Emission (kg/MMBtu) 0.0046 0.0042 

Table A46 Run Data for Source AACB1 

Test Parameters

Date 7/29/2009 7/30/2009 

Stack Flow Rate (dscfm) 11900 11900 

Run Number

Wood/Bark (%) 100.0 100.0 

Total Heat Input (MMBtu/hr) 17.29 13.71 

CH4 Results

Concentration (ppmvd) 3.8 10.7 

Mass Emission (lb/hr) 0.11 0.32 

Production Based Emission (kg/MMBtu) 0.0030 0.0105 
Table A47 Run Data for Source ABCB1 

Test Parameters

Date 7/23/2009 7/23/2009 

Stack Flow Rate (dscfm) 13100 9680 

Run Number

Bark (%) 90.0 90.0 

Wood (%) 10.0 10.0 

Total Heat Input (MMBtu/hr) 22.95 22.75 

CH4 Results

Concentration (ppmvd) 1.3 1.3 

Mass Emission (lb/hr) 0.043 0.031 

Production Based Emission (kg/MMBtu) 0.00084 0.00063 

Table A48 Run Data for Source ACCB1 

Test Parameters

Date 7/29/2009 7/29/2009 

Stack Flow Rate (dscfm) 140489 141268 

Run Number

Bark (%) 100.0 100.0 

Total Heat Input (MMBtu/hr) 685.26 655.20 

CH4 Results

Concentration (ppmvd) 4.12 0.58 

Mass Emission (lb/hr) 1.45 0.21 

Production Based Emission (kg/MMBtu) 0.00096 0.00014 

B1 

APPENDIX B 

PRINCIPLES OF FTIR ANALYSIS 

Fourier transform infrared (FTIR) spectroscopy is a type of spectral analysis that pairs the 

fundamentals of infrared analysis with fast Fourier transform mathematics to achieve quick and 

reliable multi-gas analysis. The following is a basic explanation of FTIR analysis and technology 

(Smith 1996). 

1.0 INFRARED ANALYSIS 

A wavelength is the distance, usually measured in centimeters, between adjacent light wave peaks. 

The reciprocal of that wavelength is referred to as a wave number (cm-1). Within the electromagnetic 

spectrum, wave numbers between 4,000 and 400 cm-1 are referred to as the mid-infrared range. It is 

within this range of wave numbers that most FTIR spectrometers operate. 

Most chemical compounds absorb infrared radiation, with the exception being diatomic homogeneous 

molecules (N2, H2, O2, etc.). Chemical bonds absorb infrared energy causing the bonds to vibrate or 

rotate. Depending on the type of chemical bond and its placement within the molecule, specific 

wavelengths will be absorbed. The overall transmittance of the wavelengths’ intensity decreases as 

the wavelengths are absorbed by compounds. Plotting wave numbers versus transmittance results in a 

sample spectrum. Spectra also can be based on absorption, determined by the following equation. 

A = log (1/T) 

where A is absorption and T is percent transmittance. The number and placement of absorption peaks 

across the mid-IR range is unique and constant for every compound and can be considered a physical 

property of that compound. This allows for qualitative analysis of samples with IR spectroscopy. 

Based on Beer’s law, which states that concentration and absorbance are directly proportional, IR 

spectroscopy may be used for quantitative analysis as well. Beer’s law is summarized as 

A = lc 

where A is absorption measured in peak height, is the absorptivity constant for a particular 

compound, l is the path length of the analyzer’s sample cell, and c is the concentration of the 

compound. Since absorptivity is a constant for each compound, it can be seen that when the path 

length remains fixed, as concentrations increase so will the absorption peaks. This allows for the 

quantitative analysis over a wide range of concentrations. 

2.0 FTIR COMPONENTS 

All FTIR analyzers contain the same basic setup in terms of hardware. The five most critical 

components are the infrared source, interferometer, sample cell, detector, and signal/data processors 

(Figure B1).
B2 

Figure B1 FTIR Components 

IR Source: The purpose of the IR source is to produce light waves throughout the infrared range. 

Infrared radiation is sometimes referred to as heat radiation; therefore, the IR source is simply a 

heated element. For example, a ceramic element heated by passing electricity through it could be used 

as an IR source. 

Interferometer: The interferometer is an important and unique part of FTIR analyzers, and it is what 

makes IR analysis over a wide spectral range possible. The most commonly used are Michelson 

interferometers which consist of a beam splitter, a fixed mirror, and a moving mirror (Figure B2). 

Figure B2 Interferometer 

IR Radiation

Beamsplitter Fixed 

Mirror

Moving 

Mirror 

Sample 

Cell 

Interferometer

Detector

IR Source 

Sample 

Processor 

Sample

In 

Sample

Out

Data 

Cable to 

Computer
B3 

As infrared radiation from the source enters the interferometer, it encounters a beam splitter that 

allows half of the IR beam to continue forward while the other half is reflected. One half of the beam 

will go to a fixed mirror, and the other half travels to a moving mirror. The radiation is then reflected 

off the mirrors and recombines at the beam splitter, where it then exits the interferometer. The 

purpose of the interferometer is to make two beams of light travel different distances. When the 

moving mirror and fixed mirror are the same length from the beam splitter, the divided light waves 

will have traveled the same distance when they recombine. The wave amplitudes will be in phase. 

The waves will constructively interfere with each other, and the resulting wave leaving the 

interferometer will have an amplitude greater than the one that entered. As the moving mirror changes 

positions, the optical path length toward the moving mirror changes and wavelengths will go out of 

phase with each other. When they are completely out of phase, peaks and valleys cancel each other 

out and destructive interference occurs. The mirror continues until it reaches the maximum optical 

path difference and then returns to its original position, completing one scan. 

Sample Cell: The sample cell is a compartment that allows for the interaction of the gaseous sample 

with the infrared radiation. The compounds within the gas stream will absorb the radiation at this 

time. For continuous analyzers, the sample gas stream flows through the cell at a constant rate. With 

batch analyzers, the sample is introduced into the cell, sealed off, and analyzed. The cell is evacuated 

before the next sample is introduced. The distance that the IR beam travels through the sample cell is 

the path length. Some analyzers allow for adjustment of the path length while others are fixed. 

Detector: The modified IR beam travels from the interferometer, through the sample gas stream, and 

finally to the detector. The detector measures the infrared intensity of the incoming beam and 

converts it into an electrical signal. Within the interferometer, as the light waves move in and out of 

phase, the resulting combined light wave will increase and decrease in intensity. The output from the 

detector results in a plot of IR intensity, measured in voltage, versus optical path difference. This is 

known as an interferogram. 

Sample Processor: Before the interferogram is quantified, adjustments to the spectrum are performed 

to maximize analysis. The spectrum is converted from analog to digital, corrected for symmetry, and 

peak intensities are adjusted. 

3.0 SPECTRAL ANALYSIS 

The final interferogram is sent to the analyzer software, where it is transformed. A complex algorithm 

known as a fast Fourier transform is applied to the interferogram and converts it from intensity vs. 

optical path difference to absorption vs. wave number. 

The first step in analysis is to obtain a background spectrum, which is the detector’s response with no 

sample in the sample cell. This can be accomplished by continuously passing nitrogen though the cell. 

IR absorption at all wavelengths goes to zero. 

3.1 Single Component Analysis 

A sample gas stream enters the cell as IR radiation is passed through it. The radiation is absorbed at 

certain wavelengths depending on the compound present. The detector’s response to the sample is 

ratioed against the background response and the result is a spectrum of absorption peaks that are 

attributed to the sample. 

Reference spectra for the compound of interest are required for analysis. These are obtained by 

passing the single compound through the sample cell at a known concentration and storing the 

spectral results. A range of reference spectra should be produced to include all concentrations that the 

sample may fall within. Absorptivity is calculated from these reference spectra. The absorptivity, 
B4 

absorption peak height, and path length are now known. Referring back to Beer’s law, the software 

can now quantify the concentration of the unknown sample. 

3.2 Multiple Component Analysis 

The calculations are more involved for analysis of two or more components. The calculation to 

determine the single component concentration is still used; however, a separate calculation must be 

performed for every additional compound present in the gas stream. The situation is complicated even 

more by the fact that two compounds can have absorption peaks in or around the same wave number. 

The absorption due to each compound must be determined within this wave number. Using matrix 

algebra allows for the fast computation of multiple compound concentrations over a wide wave 

number range. One requirement when using this method is that all compounds within the sample 

stream must be accounted for in the analysis. Absorption peaks from any compound not present in the 

analysis will interfere with the accurate quantification of the other compounds. These peaks that are 

unaccounted for after analysis are referred to as residual peaks. Interfering residuals can be removed 

by including the compound responsible for these peaks in the analysis. It is important to have a large 

reference library with all compounds that may be present when testing unknown sample streams. 

Another cause of interference can arise from large concentrations of compounds absorbing near the 

target analytes. Large absorption peaks can dominate a wave number and, in extreme cases, can cause 

complete saturation of the wave number in which the maximum amount of radiation at that 

wavelength is being absorbed. If this occurs at or around the analysis area of the target analytes, it can 

make analysis difficult or even impossible in that area. Proper selection of the analysis area is 

important for this reason. 

REFERENCE 

Smith, B.C. 1996. Fundamentals of Fourier transform infrared spectroscopy. Boca Raton, FL: CRC 

Press. 
C1 

APPENDIX C 

METHOD DEVELOPMENT 

1.0 INTRODUCTION 

The two main methods for extractive FTIR analysis are EPA Method 320 and ASTM Method D 

6348-03. Both methods require a sampling setup that includes a filter, sample lines, sample pump, 

and analyzer, with all components heated to avoid condensation. An equipment setup similar to the 

one illustrated in Figure C1 is recommended. 

Figure C1 FTIR Sampling System 

Due to the nature of FTIR spectroscopy, poorly quantified peaks absorbing in the same analysis area 

as the target analytes are known as interferences. These interferences can compromise the accurate 

quantification of the target analytes. Initial testing of biomass boilers revealed large concentrations of 

water and carbon dioxide, with relatively low concentrations of CH4 and N2O. The testing showed 

that water peaks were interfering with CH4 analysis and increasing detection limit levels. Carbon 

dioxide was found to interfere with N2O analysis; however, it was found that careful selection of N2O 

analysis areas could avoid this problem. 

The EPA and ASTM methods allow for a sample conditioning system to be placed in-line to reduce 

interfering compound concentrations to an acceptable level. A condenser was proposed to reduce the 

moisture content of the gas stream before it enters the sample system. The condenser consisted of a 

chilled, empty Rotavis® impinger in front of the particulate filter. The modified setup was tested at a 

Laptop Analyte Spike

CTS Spike

Mass Flow

Controller

UHP Nitrogen

Pneumatic 

O2

Heated Sample

Pump

Heated 

Line

SS Heated Filter

Probe 

FTIR 

Vent

Heated 

Line
C2 

recovery furnace. Modified and standard setups were alternated for a total of five runs each. The 

results were used to evaluate the ability of the modified system to improve CH4 analysis. 

The results seen in Table C1 show a dramatic reduction in sample moisture content. The CH4

detection limits were lowered by 1.5 ppm as a result. The recovery furnace tested contained low 

concentrations of CH4, and this reduction in detection limit dramatically improved analysis. 

Table C1 Standard and Modified Setup 

Setup 

Moisture Content 

(%) 

Methane DL 

(ppm) 

Standard 26.22 2.45 

Modified 0.82 0.93 

The reduction in moisture could allow collection of source samples in Tedlar® bags for later analysis. 

This would be beneficial when direct sampling at a source is not practical. 

A laboratory study was performed to fully evaluate the sample conditioning system before it was 

incorporated into the equipment setup. The study was divided into three phases. The first phase 

determined which conditioning techniques were most efficient at removing moisture from the gas 

stream, while not affecting the N2O and CH4 concentrations. Phase 2 examined sample stability over 

time. Phase 3 of the study insured that analyte spiking could be accomplished from the Tedlar® bag. 

A gas manifold was constructed to create a synthetic boiler gas stream. N2, N2O, CH4, NO, SO2, and 

O2 from gas cylinders were combined with steam from a steam generator to produce the synthetic gas 

matrix. 

2.0 METHOD 

2.1 Phase 1 

Phase 1 evaluated methods for removal of water while preserving N2O and CH4 concentrations. The 

three conditioning systems evaluated were 

1. a chilled, empty Rotavis® impinger with a shorted stem to prevent bubbling of the sample 

gas through the collected water; 

2. a chilled impinger followed by a Nafion® dryer; and 

3. a chilled impinger followed by an impinger filled with silica gel. 

A dry mixture of gases was sent directly to the analyzer to determine CH4 and N2O concentrations. 

The gas stream was then sent through each of the three conditioning systems before going to the 

analyzer to determine if there was an effect on CH4 and N2O concentrations. Water vapor was added 

to the gas stream to bring the moisture content up to 30%. The wet gas stream was then sent through 

each of the three conditioning systems before going to the analyzer. 
C3 

2.2 Phase 2 

In Phase 2, gas samples were collected in Tedlar® bags after they passed through the most 

appropriate conditioning system determined in Phase 1. Samples were analyzed immediately after 

collection and then every hour for four hours to evaluate short-term stability. The bags were analyzed 

again after 48 and 72 hours to evaluate long-term stability. 

2.3 Phase 3 

Phase 3 was designed to ensure that dynamic spiking could be accomplished from the Tedlar® bags 

for quality assurance, as required by the FTIR methods. Two bags were filled with dry mixtures of 

gases that would result in CH4 and N2O concentrations of 6 ppm in the first bag and 2 ppm in the 

second. Bags were analyzed to determine the CH4 and N2O concentrations. Analyte spiking for both 

compounds was performed as it would be in the field, and the percent spike recovery was determined. 

3.0 RESULTS 

3.1 Phase 1 

There was no analyte reactivity through the condenser impinger alone; however, there was a slight 

negative bias for CH4 and N2O when the Nafion® dryer or silica gel was added. The bias for N2O was 

the same for both Nafion® dryer and silica gel, while the Nafion® dryer exhibited higher reactivity 

for CH4 than the silica gel. The percent differences in all cases was considered minor and within an 

acceptable range. Table C2 summarizes the results of the dry gas tests. 

Table C2 Phase 1 Results (dry gas stream) 

Concentration (ppmvd) 

Component FTIR Direct Analysis Impingers Only

Impingers

+ Nafion® Dryer

Impingers

+ Silica Gel 

H2O 0 0 0 0

N2O 6.6 6.6 6.5 6.5

NO 59 59 59 51

CH4 7.8 7.8 7.6 7.7

SO2 268 268 268 -1.4

O2 13.9 13.9 13.8 13.4

N2O Bias 0% -1.5% -1.5%

CH4 Bias 0% -2.6% -1.3%

All three setups were efficient at reducing the moisture content from 30% to an acceptable level. The 

impinger plus silica gel configuration was the most effective as it was able to remove all moisture 

from the gas stream. Reactivity of the target analytes was again measured with the wet gas stream. 

The impinger and impinger/Nafion® dryer setups showed no bias for N2O, while the impinger/silica 

gel showed a slight positive bias. All three configurations showed a negative bias for CH4 with the 

impinger/Nafion® dryer being the most pronounced. Table C3 summarizes the results of the moist 

gas tests. 
C4 

Table C3 Phase 1 Results (moist gas stream) 

Concentration (ppmvd) 

Component

Dry Gas

FTIR Direct 

Impingers

Only 

Impingers

+ Nafion® Dryer 

Impingers

+ Silica Gel 

H2O 0 0.7 0.4 0

N2O 6.6 6.6 6.6 6.8

NO 59 59 58 47.3

CH4 7.6 7.3 7.0 7.1

SO2 270 245 247 0

O2 13.7 13.7 13.8 13.4

N2O Bias 0% 0% 3.0%

CH4 Bias -4.0% -8.0% -6.6%

3.2 Phase 2 

A literature review was performed to investigate storage and stability of CH4 and N2O from 

combustion sources. An article written by Muzio et al. (1989) revealed that storing combustion gases 

containing SO2, NO, and H2O, even over a short period of time, can lead to the formation of N2O 

within the vessel. A study by Preto et al. (2004) investigated the mechanism for this formation and 

concluded that SO2, NO, H2O, and O2 can all play a role, with SO2 being a major factor. This effect 

was seen in the lab study when bag samples were collected and stored with only the condenser 

impinger used. Water was reduced but not eliminated, and NO, SO2, and O2 concentrations were 

unaffected. There were slight increases in N2O and CH4 over a four-hour period. Over a two-day 

period, there was no significant change in CH4 while N2O increased by 58%. Table C4 summarizes 

the results. Figure C2 illustrates the changes of N2O and CH4 over the 48-hour time period. 

It was discovered during this test that the Tedlar® bags are porous with respect to water vapor. The 

percent moisture, while starting out low, increased over time approaching ambient moisture content. 

Table C4 Sample Stability (no dryer) 

Time (hours) 0 2 4 48 

Component Concentration (ppmvd)

H2O 0.8 1.1 1.4 1.7

N2O 7.1 7.1 7.2 11.2

NO 48.8 20.5 13.0 6.1

NO2 9.8 53.6 36.7 23.4

CH4 7.3 8.1 8.2 7.2

SO2 247.0 247.1 245.5 198.0

O2 13.7 13.7 13.7 13.1
C5 

Figure C2 Stability over Time (no dryer) 

During the first phase of the study, it was noted that the impinger/silica gel combination not only 

eliminated all water vapor, but it also had the ability to scrub out SO2 from the gas stream. The 

removal of H2O and SO2 would greatly enhance the stability of N2O concentrations in the Tedlar® 

bags. Therefore, it was determined that a chilled impinger followed by a silica gel impinger was the 

most appropriate sample conditioning setup. 

While the silica gel is efficient at scrubbing SO2 from the gas stream, during long runs the silica gel 

can become saturated and SO2 will break through. This explains the presence of SO2 in the stability 

study bag, even though the impinger/silica gel combination was used. Over a four-hour period, CH4

and N2O concentrations remained stable, with only slight fluctuations from sample to sample. Over a 

48- and 72-hour period, CH4 concentrations decreased slightly and N2O concentrations increased. The 

increase in N2O can be explained by the small presence of SO2 in the samples. Table C5 summarizes 

the stability study results. Figure C3 illustrates the change in N2O and CH4 concentrations over time. 

Table C5 Sample Stability (silica gel dryer) 

Time (hrs) 0 0.5 1 2 3 4 48 72 

Component Concentration (ppmvd)

H2O 0 0.3 0.3 0.5 0.7 0.8 0.7 0.8

N2O 7.5 7.6 7.5 7.5 7.6 7.6 7.9 8.1

NO 53 30.1 25.5 19.0 13.9 12.5 1.1 0.5

NO2 0 23.9 31.5 42.0 47.9 50.8 44.1 38.6

CH4 8.1 7.9 7.9 8.1 8.0 7.9 7.8 7.7

SO2 69 72.6 71.9 73.1 72.1 72.6 62.6 61.2

O2 13.8 14.3 13.3 13.9 14.7 13.9 12.6 12.3

0.00

2.00

4.00

6.00

8.00

10.00

12.00

0 2 4 48

ppmvd

Hours

N2O

CH4
C6 

Figure C3 Stability over Time (silica gel dryer) 

3.3 Phase 3 

For both CH4 and N2O, the spike recovery from bag one was 101%. The percent spike recoveries 

from bag two were 97% for CH4 and 96% for N2O. All spike recoveries were well within acceptable 

ranges. Table C6 summarizes the spike recovery data. 

Table C6 Phase 3 Results 

Concentration (ppmvd) 

Component Unspiked 

Desired

Spike Level 

Expected 

Concentration 

Spiked

Concentration 

Percent 

Recovery 

Bag One

N2O 6.4 6.0 12.0 12.1 101

CH4 6.7 5.5 11.5 11.6 101

Bag Two

N2O 2.2 2.0 4.2 4.0 96

CH4 2.7 3.0 5.5 5.4 97

0

1

2

3

4

5

6

7

8

9

10

0 0.5 1 2 3 4 48 72

ppm

Hours

Covered

N2O

CH4
C7 

4.0 CONCLUSION 

The results from the lab study show that a chilled impinger followed by a silica gel impinger is an 

appropriate conditioning system for reducing water vapor and SO2 concentrations within a gas 

stream. The system was also shown to have little to no effect on CH4 and N2O concentrations. The 

experiment demonstrated the stability of a bag sample up to four hours and possibly longer if 

conditioned properly. Sample run times should be limited to avoid SO2 breakthrough. The ability to 

carry out accurate spiking while sampling from the Tedlar® bags was proven. 

REFERENCES 

Muzio, L.J., Teague, M.E., Kramlich, J.C., Cole, J.A., McCarthy, J.M., and Lyon, R.K. 1989. Errors 

in grab sample measurements of N2O from combustion sources. Journal of the Air Pollution 

Control Association 39:287-293. 

Preto, F., Wang, J., Jia, L., and Anthony, E.J. 2004. A study on mechanisms of nitrous oxide 

formation in post-combustion flue Gases. Atmospheric Environment 38:1123-1131. 

http://dx.doi.org/10.1016/j.atmosenv.2003.11.021
APPENDIX B 
ncasi 

NATIONAL COUNCIL FOR AIR AND STREAM IMPROVEMENT, INC. 

P.O. Box 13318, Research Triangle Park, NC 27709-3318 

Phone (919) 941-6400 || Fax (919) 941-6401 

Vipin K. Varma, PhD 

Vice President – Air Quality 

vvarma@ncasi.org 

November 8, 2012 

Mr. Paul Noe 

Vice President, Public Policy 

American Forest and Paper Association 

1111 19th Street, NW 

Suite 800 

Washington, D.C. 20036 

Dear Mr. Noe, 

This is a follow-up to the earlier NCASI communication, dated September 20, 2012, notifying you of 

the availability of NCASI Technical Bulletin No. 998, Methane and Nitrous Oxide Emissions from 

Biomass-Fired Boilers and Recovery Furnaces. This Technical Bulletin, released on September 18, 

2012, compiles data from an NCASI study to quantify methane (CH4) and nitrous oxide (N2O) 

emissions from biomass-fired boilers and kraft recovery furnaces. 

The above-mentioned study generated additional data on CH4 and N2O emissions associated with the 

burning of kraft pulping liquors in recovery furnaces. Five direct contact evaporator (DCE) recovery 

furnaces and three non-direct contact evaporator (NDCE) recovery furnaces were tested during the 

study. Given that multiple DCE and NDCE units were tested during the study, the Technical Bulletin 

maintained DCE and NDCE furnaces as distinct categories and developed unique CH4 and N2O 

emission factors for these categories. 

As discussed in Section 5.3 of NCASI Technical Bulletin No. 998, the CH4 and N2O emission factors 

compiled by the Intergovernmental Panel on Climate Change (IPCC) and the World Research Institute 

and The World Business Council for Sustainable Development (WRI/WBCSD) do not distinguish 

between DCE and NDCE recovery furnaces. Additionally, in Table AA-1 to Subpart AA in the 

Greenhouse Gas Reporting Rule (GHGRR), EPA mandates the use of a single emission factor (0.030 

kg/MMBtu for CH4 and 0.005 kg/MMBtu for N2O) for kraft pulping liquors without distinguishing 

between DCE and NDCE furnaces. When the data for DCE and NDCE furnaces from the NCASI study 

are grouped into a single category, average CH4 and N2O emissions for recovery furnaces are 0.0019 

and 0.00042 kg/MMBtu, respectively, as summarized in the Table below (modified from Tables 5.2 and 

5.3 of the Technical Bulletin with DCE and NDCE furnaces combined into a single category). 

 
CH4 and N2O Emission Factors for Kraft Pulping Liquors, kg/MMBtu 

GHG IPCC WRI/WBCSD 

GHG Protocol

EPA1 NCASI Study 

Mean (%RSD) 

NCASI Study 

Range 

Methane 

(CH4)

0.0030 0.0025 0.030 0.0019 

(190%) 

0.000042 – 0.010 

Nitrous Oxide 

(N2O) 

0.0020 0.0020 0.0050 0.00042 

(68%)

0.00015 – 0.00082 

1

 Emission factors mandated for use in GHG Inventories 

Please do not hesitate to contact me at 352- 331-1745 (ext. 260) or vvarma@ncasi.org, if you have 

additional questions on this topic or on the NCASI Technical Bulletin. 

Sincerely,

Vipin Varma 

cc: 

Derek Sain, Senior Research Associate, NCASI 

Brad Upton, Principal Research Engineer, NCASI 

Reid Miner, Vice President, Sustainable Manufacturing, NCASI 
ncasi 

NATIONAL COUNCIL FOR AIR AND STREAM IMPROVEMENT, INC. 

P.O. Box 13318, Research Triangle Park, NC 27709-3318 

Phone (919) 941-6400 || Fax (919) 941-6401 

Vipin K. Varma, PhD 

Vice President – Air Quality 

vvarma@ncasi.org 

November 8, 2012 

Mr. Robert Glowinski 

President and CEO 

American Wood Council 

803 Sycolin Road 

Suite 201 

Leesburg, VA 20175 

Dear Mr. Glowinski, 

This is a follow-up to the earlier NCASI communication, dated September 20, 2012, notifying you of 

the availability of NCASI Technical Bulletin No. 998, Methane and Nitrous Oxide Emissions from 

Biomass-Fired Boilers and Recovery Furnaces. This Technical Bulletin, released on September 18, 

2012, compiles data from an NCASI study to quantify methane (CH4) and nitrous oxide (N2O) 

emissions from biomass-fired boilers and kraft recovery furnaces. 

The above-mentioned study generated additional data on CH4 and N2O emissions associated with the 

burning of kraft pulping liquors in recovery furnaces. Five direct contact evaporator (DCE) recovery 

furnaces and three non-direct contact evaporator (NDCE) recovery furnaces were tested during the 

study. Given that multiple DCE and NDCE units were tested during the study, the Technical Bulletin 

maintained DCE and NDCE furnaces as distinct categories and developed unique CH4 and N2O 

emission factors for these categories. 

As discussed in Section 5.3 of NCASI Technical Bulletin No. 998, the CH4 and N2O emission factors 

compiled by the Intergovernmental Panel on Climate Change (IPCC) and the World Research Institute 

and The World Business Council for Sustainable Development (WRI/WBCSD) do not distinguish 

between DCE and NDCE recovery furnaces. Additionally, in Table AA-1 to Subpart AA in the 

Greenhouse Gas Reporting Rule (GHGRR), EPA mandates the use of a single emission factor (0.030 

kg/MMBtu for CH4 and 0.005 kg/MMBtu for N2O) for kraft pulping liquors without distinguishing 

between DCE and NDCE furnaces. When the data for DCE and NDCE furnaces from the NCASI study 

are grouped into a single category, average CH4 and N2O emissions for recovery furnaces are 0.0019 

and 0.00042 kg/MMBtu, respectively, as summarized in the Table below (modified from Tables 5.2 and 

5.3 of the Technical Bulletin with DCE and NDCE furnaces combined into a single category). 

 
CH4 and N2O Emission Factors for Kraft Pulping Liquors, kg/MMBtu 

GHG IPCC WRI/WBCSD 

GHG Protocol

EPA1 NCASI Study 

Mean (%RSD) 

NCASI Study 

Range 

Methane 

(CH4)

0.0030 0.0025 0.030 0.0019 

(190%) 

0.000042 – 0.010 

Nitrous Oxide 

(N2O) 

0.0020 0.0020 0.0050 0.00042 

(68%)

0.00015 – 0.00082 

1

 Emission factors mandated for use in GHG Inventories 

Please do not hesitate to contact me at 352- 331-1745 (ext. 260) or vvarma@ncasi.org, if you have 

additional questions on this topic or on the NCASI Technical Bulletin. 

Sincerely,

Vipin Varma 

cc: 

Derek Sain, Senior Research Associate, NCASI 

Brad Upton, Principal Research Engineer, NCASI 

Reid Miner, Vice President, Sustainable Manufacturing, NCASI 
APPENDIX C 
From: Hogan.Sean@epamail.epa.gov [mailto:Hogan.Sean@epamail.epa.gov] 

Sent: Thursday, June 16, 2011 4:43 PM 

To: Hale, Rhea 

Cc: Jacobson.David@epamail.epa.gov; Hanle.Lisa@epamail.epa.gov; 

Tunnessen.Walt@epamail.epa.gov

Subject: Re: MMR question regarding Black Liquor emission factor 

Hi Rhea - 

In response to your question, a range of emission factors for recovery furnaces combusting 

black liquor is provided in Appendix F (see App F, Table 8) of the WRI/WBCSD GHG 

Calculation Tool for Pulp and Paper Mills (developed by NCASI/ICFPA for WRI/WBCSD). 

 Given the limited data, the emission factors in Subpart AA, Table AA-1, were derived 

conservatively based on the maximum of the ranges provided in Appendix F, Table 8 (30 kg 

CH4/TJ and 5 kg N2O/TJ). When converted to CO2e and summed, this totals 2.2 kg/GJ. 

 The 0.67 kg/GJ indicated by AF&PA in their August 2009 supplemental comments is based 

on the median values in Appendix F, Table 8 (2.5 kg CH4/TJ and 2 kg N2O/TJ). 

- Sean 

Sean P. Hogan 

Program Integration Branch 

Climate Change Division 

EPA Office of Atmospheric Programs 

(202) 343-9233 

hogan.sean@epa.gov

NOTICE: Any communication on the mandatory GHG reporting rule is intended to provide 

general and administrative information about the Rule. This communication does not 

provide legal advice, and responses to questions received do not have legally binding effect 

or expressly or implicitly create, expand, or limit any legal rights, obligations, 

responsibilities, expectations, or benefits in regard to any person. Facility owners or 

operators and suppliers are responsible for determining how they would be affected by the 

requirements of the Rule. 

From: "Hale, Rhea" <Rhea_Hale@afandpa.org> 

To: Sean Hogan/DC/USEPA/US@EPA 

Date: 06/10/2011 04:56 PM 

Subject: MMR question regarding Black Liquor emission factor 
Sean, 

In AF&PA’s original comments on the reporting rule we noted that the CH4 and N2O factors 

for black liquor are quite a bit higher than what is typically used in the industry. For example 

factor for CH4 and N2O emissions for spent pulping liquor from the WRI/WBCSD GHG 

Calculation Tool for Pulp and Paper Mills – developed by NCASI/ICFPA for WRI/WBCSD 

– (expressed as CO2 equivalents) is .67 kg/GJ, the EPA factor is three times greater at 2.2 

kg/GJ. Because many of our mills combust a large amount of black liquor, this difference in 

the factor can add tens of thousands of CO2e to our emissions totals for a single company. 

 To our knowledge, we did not receive an EPA response on this issue when the rule came out 

and wondered if EPA could clarify for us where the EPA factors come from. As our mills 

continue to work on their GHG data collection, this issue has come up. 

 

Here’s what AF&PA submitted (on August 10, 2009) as a comment to EPA on the draft rule: 

 “EPA should provide background reference material regarding how factors in Table AA-1 

were developed. The values for biogenic CO2 in Table AA-1 are very close to, but not 

equivalent to, those provided in the WRI/WBCSD GHG Protocol Calculation Tools for the 

pulp and paper sector. The CH4 and N2O factors provided in Table AA-1 are quite a bit 

higher than those in the WRI/WBCSD Tools.” 

Thanks for any help you can provide and I look forward to seeing you in Memphis next 

week. 

 

Best regards, 

Rhea 

 

Rhea Hale 

Director, Climate & Air Programs

AMERICAN FOREST & PAPER ASSOCIATION

1111 19th Street, NW, Suite 800, Washington, D.C. 20036

Rhea_Hale@afandpa.org

202-463-2709 (phone)

202-463-2772 (fax)

www.afandpa.org