Date: November 17, 2011

Subject: Costs and Environmental and Energy Impacts for Subpart S Risk and 

Technology Review

EPA Contract No. EP-D-11-084; Work Assignment No. 0-03

From: Thomas Holloway

Katie Hanks

Corey Gooden

To: John Bradfield

Bill Schrock

U.S. Environmental Protection Agency

Research Triangle Park, NC 27711

I. Introduction

Section 112(f)(2) of the Clean Air Act (CAA) directs the U.S. Environmental Protection 

Agency (EPA) to conduct risk assessments on each source category subject to maximum 

achievable control technology (MACT) standards and determine if additional standards are 

needed to reduce residual risks from the remaining hazardous air pollutant (HAP) emissions 

from the category. Section 112(d)(6) of the CAA requires EPA to review and revise the MACT 

standards, as necessary, taking into account developments in practices, processes, and control 

technologies. The section 112(f)(2) residual risk review and section 112(d)(6) technology review 

are to be done 8 years after promulgation.

The national emission standards for hazardous air pollutants (NESHAP) for the pulp and 

paper industry (40 CFR part 63, subpart S) were promulgated in 1998 and are due for review 

under CAA sections 112(f)(2) and 112(d)(6). To address a lawsuit filed by Sierra Club, the 

subpart S risk and technology review (RTR) package will be proposed by December 15, 2011.

The purpose of this memorandum is to document the estimated costs and environmental 

and energy impacts associated with the regulatory options under consideration for the subpart S

RTR proposal. Section II discusses the derivation of the costs and impacts associated with the 

kraft condensates regulatory options. Section III presents the costs associated with the proposed 

repeat HAP emissions testing requirement. Finally, section IV summarizes the nationwide costs

and impacts.
2

II. Cost and Impacts Estimates for Kraft Condensates Regulatory Options

A. Kraft Condensates Regulatory Options

The kraft condensates standards in subpart S limit the HAP concentration in various 

process liquids (e.g., condensates from pulping equipment). Limiting emissions from these 

process liquids reduces emissions from the handling and reuse of these liquids and wastewater 

treatment. The condensates are treated by one of the following methods:

1. Route the condensates to equipment that meets the subpart S kraft pulping vent gas 

standards; or

2. Route the condensates to biological treatment/steam stripper or other control device that 

meets one of the following equivalent requirements: 

 Reduce total HAP by at least 92 weight-percent; or

 For mills without bleaching, either remove at least 6.6 pounds (lb) total HAP/ton 

oven-dried pulp (ODP), or meet 210 parts per million by weight (ppmw) total HAP at 

control device outlet; or

 For mills with bleaching, either remove at least 10.2 lb total HAP/ton ODP, or meet

330 ppmw total HAP at control device outlet.

Data from industry responses to Part I of the 2011 pulp and paper survey were reviewed 

to determine the performance level of mills subject to the kraft condensates standards. The Part I 

survey requested information on the control measures and compliance options used by mills to 

meet the kraft condensates standards. Mills typically use either steam stripping of contaminated 

condensates or hard piping of condensates to biological wastewater treatment. Some mills may

use a combination of treatment methods. A total of 97 mills are currently subject to the kraft 

condensates standards. Table 1 presents a summary of the predominant kraft condensate 

treatment methods used.

Table 1. Number of Mills Using Various Condensate Treatment Methods

Treatment Method No. of mills

Biotreatment 39

Recycle 5

Stripping or stripping/recycle 43

Stripping and biotreatment 9

Thermal incinerator 1

Total 97

The regulatory options considered for the subpart S RTR include tightening the kraft 

condensates standards to reflect the current performance of technology and further reduce 

emissions associated with kraft pulping and wastewater. A series of different emission limits

were considered, including increasing the requirement to reduce HAP emissions from 92 percent 

to a higher percent reduction (e.g., 93, 94, 95, 96, 97, or 98 percent). These incremental 

emissions reductions are already being achieved by some mills, but would require upgrade or 

replacement of existing equipment by other mills. A separate memo (EPA 2011a) describes the 
3

methodology used to determine current percent reduction performance. For each incremental 

emission limit increase in the emission limit, the subset of mills currently not meeting that limit

was identified and presented in Table 2 below.

Table 2. Number of Mills Requiring Equipment Upgrades for Each Incremental

Adjustment in the Kraft Condensate Emission Reduction Limit

Percent reduction (%)

No. of mills meeting % 

reduction limit

No. of mills affected by 

incremental adjustment of limit

92 97 0

93 93 4

94 82 15

95 69 28

96 56 41

97 43 54

98 31 66

Mills recycling condensates to equipment to meet the pulping vent gas limits are subject 

to the 98 percent pulping vent gas limit (or equivalent) and were assumed not to incur any costs 

associated with adjustments to the kraft condensate emission limits. The mill operating a thermal 

incinerator also achieved greater than 98 percent control and would not be affected. Mills using a 

combination of steam stripping and biotreatment were assigned costs based on steam stripping.

B. Cost of Biological Treatment System Upgrades

Wastewater treatment plant upgrade costs were developed for mills currently using 

biological treatment. (EPA 2011a) For costing purposes, it was assumed that the wastewater 

treatment system upgrade would require an increase in system capacity proportional to the 

increase in emission limit. For example, to meet a 95 percent limit, a 10 million gallon per day

(MM gal/d) plant would increase capacity by 0.33 MM gal/day ([10 x 95/92] – 10 ≈ 0.33).

(EPA 2011a) Wastewater treatment plant upgrade costs were based on the following cost 

equations (where MGD is millions of gallons per day).

Capital cost ($) = 5.9749 x MGD0.8228 x 1,000,000

O&M cost ($/yr) = 0.2546 x MGD0.6969 x 1,000,000

The cost equations were derived from CapdetWorks v2.5 model runs for a complete-mix 

activated sludge sludge system containing a bioreactor and secondary clarifier scaled to 2010 

dollars using Engineering News-Record (ENR) indices. CapdetWorks v2.5 is a commercially 

available software program for the preliminary design and costing of wastewater treatment 

systems. (Hydromantis 2007) The capital cost equation developed using CapdetWorks was found 

to compare reasonably well to a wastewater treatment plant cost equation from an EPA 

document (EPA 1980). No operation and maintenance (O&M) costs were included in EPA 1980. 

The O&M cost equation above was developed using CapdetWorks and includes labor, 

chemicals, materials, and energy. Total labor averaged 38 percent of the annual cost at an O&M

wage rate of $25/hr, and this information was used to calculate the annual labor hours per year
4

associated with biotreatment system upgrades. The CapdetWorks v2.5 default electricity cost of 

$0.10/kWh was used to calculate energy use (kWh) associated with the biological treatment 

system upgrades. Appendix A contains the results of the CapdetWorks v2.5 model runs for five 

facility sizes that were used to establish cost correlations. Appendix B1 presents the mill-by-mill 

costs for biological treatment system upgrades extrapolated from these model costs. 

The annualized capital costs were determined by applying a capital recovery factor of 

0.094 to the estimated capital cost. The capital recovery factor was estimated assuming a 20-year 

equipment life and 7 percent interest rate.

C. Cost of Steam Stripper Upgrades

Steam stripper costs were developed for mills currently using steam stripping to comply 

with the kraft condensates limit. (EPA 2011a) Mills needing to improve stripper performance by

2 percent or less were expected to upgrade their existing steam strippers, and mills needing to 

improve stripper performance by more than 2 percent were expected to replace their existing 

steam strippers. Steam stripper costs (in 1991 dollars) for a 1,000 ton per day (tpd) mill were 

provided in the 1993 background information document for the proposed subpart S standards.

(EPA 1993) The 1991 capital cost of $3.5 million was scaled to 2010 dollars using the Chemical 

Engineering Plant Cost Index (CEPCI) (index = 361.3 for 1991 and 550.8 for 2010), resulting in 

a 2010 capital cost of $5,335,732 for a new steam stripper. The capital cost for stripper upgrades 

was assumed to be one half of the capital cost for a new steam stripper ($2,667,866). Annualized 

capital costs were estimated based on a 20-year equipment life and 7 percent interest rate (i.e., 

capital recovery factor of 0.094).

Mills currently operating stripper systems are already incurring annual costs associated 

with stripper operation. Upgraded or replacement strippers are likely to be more energy efficient 

than their predecessors, such that energy efficiency improvements offset any increased operating 

costs due to incremental equipment sizing. Therefore, for costing purposes, it was assumed that 

there would be no increase in the stripper operating cost (including labor or energy costs) 

associated with incremental improvements in the kraft condensate control efficiency. Appendix 

B1 presents the mill-by-mill costs for steam stripper upgrades based on these assumptions.

D. Impacts of Kraft Condensates Regulatory Options

This section discusses the environmental and energy impacts of the kraft condensates 

regulatory options. The environmental impacts include HAP and non-HAP emissions reductions, 

secondary emissions, and wastewater impacts.

1. Emissions reductions. Appendix B2 contains the methodology used to develop millspecific HAP and non-HAP emissions reductions for the condensate regulatory options. The 

predominant HAPs from kraft condensates are methanol and acetaldehyde. The non-HAPs 

evaluated are volatile organic compounds (VOC) and total reduced sulfur (TRS) compounds.
5

Strippers were used as the basis for the kraft condensates emissions reduction 

calculations because emission factors are readily available for strippers (unlike for biological 

treatment systems, where modeling of emission rates is required). Biological treatment systems 

are expected to achieve an equivalent emissions reduction.

Uncontrolled HAP emissions were estimated using an emission factor of 11 lb HAP/air 

dried ton of unbleached pulp (ADTUBP), an approximate total HAP value associated with 

stripper off-gas (SOG) from Technical Bulletin 973 (Table 4.14) prepared by the National 

Council for Air and Stream Improvement (NCASI). (NCASI 2010) The amount of HAP in foul 

condensate stream was back-calculated as 11.96 lb HAP/ADTUBP using the current regulatory

limit of 92 percent stripper HAP removal (leaving 0.96 lb HAP/ADTUBP in the stripped 

condensate stream). The reduction in HAP per mill was calculated assuming a 1,000 ADTUBP 

model facility operating 360 days per year and 98 percent removal of HAP in the SOGs via 

incineration. This total was multiplied by the 97 mills currently subject to the kraft condensates 

standards to arrive at the potential emissions reduction that would be required by tightening the 

regulatory limits for kraft condensates.

Based on information in NCASI Technical Bulletin 973, uncontrolled VOC emissions 

were estimated to be essentially equal to uncontrolled HAP (11 lb/ADTUBP), and are expected 

to strip at the same rate as HAP, since VOC is predominantly composed of HAP. Uncontrolled 

TRS emissions were estimated using an emission factor of 3.29 lb TRS/ADTUBP, based on the 

emission factor for SOG from NCASI Technical Bulletin 973 (Table 4.14). For purposes of this 

incremental analysis, we assumed the stripping rate for TRS to be similar to that for HAP or 

VOC. While the combustion of TRS in SOG combustion devices will likely generate some sulfur 

dioxide (SO2), the additional amount of SOGs burned under the incremental standards for kraft 

condensates would be small compared to the other fuels burned in the combustion device (e.g., 

boiler, lime kiln), so any incremental SO2 emissions generated would also be relatively small.

2. Energy impacts. Appendix B3 contains the methodology used to develop mill-specific

estimates of energy impacts. The energy impacts were estimated based solely on the electricity

requirements associated with the biological treatment system upgrade needed to meet the kraft 

condensate incremental reductions. No additional electricity was expected to be required for 

steam stripper upgrades to meet the kraft condensate incremental reductions because the 

upgraded steam strippers are likely to be more energy efficient. (EPA 2001) Therefore, the only 

mills with energy impacts would be those conducting biological treatment system upgrades. We 

converted the electricity estimates (in kWh per year [yr]) to million British thermal units per year 

(MMBtu/yr) in order to estimate secondary emissions.

3. Secondary air emissions. Appendix B3 contains the methodology used to develop millspecific estimates of secondary air emissions. Secondary air emissions include the criteria 

pollutant emissions—particulate matter (PM), carbon monoxide (CO), nitrogen oxides (NOX), 

and SO2—that result from the generation of electricity to achieve the biological treatment system 

upgrades. The electricity was assumed to be purchased from offsite utilities, rather than 

generated onsite. We also developed secondary emissions estimates for greenhouse gases carbon 

dioxide (CO2), methane (CH4), and nitrous oxide (N2O) expected to be emitted from utilities.
6

We used a variety of information sources for the emission factors used to estimate the 

secondary emissions. For natural gas, we used emission factors (in pound per cubic foot [lb/ft3] 

of natural gas) from the AP-42 chapter on natural gas combustion to estimate the secondary

emissions for PM, CO, NOX, and SO2. (EPA 1998a) We used the AP-42 conversion factor of 

1,020 Btu/ft3of natural gas to convert the emission factors to lb/MMBtu to facilitate estimating

the secondary emissions for these pollutants from natural gas. We used natural gas emission 

factors (in kilograms [kg]/MMBtu) from the General Stationary Fuel Combustion Sources 

subpart (40 CFR part 98, subpart C) of the Greenhouse Gas Reporting Rule to estimate the 

secondary emissions for CO2, CH4, and N2O. Global warming potentials of 1 for CO2, 21 for 

CH4, and 310 for N2O (from Table A-1 to subpart A of part 98) were used to estimate CO2

equivalent emissions (CO2eq).

For solid fuel combustion, we used emission limits (in lb/MMBtu) from the new source 

performance standards (NSPS) for utility plants (40 CFR part 60, subpart Da) to estimate the 

secondary emissions for PM and SO2. We used emission factors (in lb/ton coal) from the AP-42 

chapter on coal combustion to estimate the secondary emissions for NOX and CO. (We 

specifically used the AP-42 emission factors for bituminuous/subbituminous coal 

combustion/spreader stokers. The NOX emission factor was based on an average of the AP-42 

emission factors for spreader stoker type boilers burning bituminous (11 lb/ton) and 

subbituminous (8.8 lb/ton) coal. We used the AP-42 conversion factor of 13,000 Btu/lb of coal to 

facilitate estimating the secondary emissions for NOX and CO from coal. We used emission 

factors (in kg/MMBtu) from 40 CFR part 98, subpart C to estimate the secondary emissions for 

CO2 (for units burning bituminous coal) and for CH4 and N2O (for units burning coal/coke). As 

before, we used the aforementioned global warming potentials for CO2, CH4, and N2O to 

estimate CO2eq.

To estimate the secondary emissions, we multiplied the emission factors for the 

aforementioned pollutants by the estimated energy impacts, assuming a specific mix of fuels 

would be used to generate the needed electricity for the biological treatment system upgrade. We 

used the projected fuel mix for 2015 (compliance deadline for subpart S RTR) from Version 3.0

of EPA’s Integrated Planning Model (IPM), which is a forecast model of the U.S. electric power 

sector. The projected fuel mix is 53 percent coal, 21 percent oil and natural gas, 17 percent 

nuclear, 6 percent hydroelectric, 2 percent renewable energy, and 1 percent other. We attributed 

no secondary air impacts to nuclear, hydroelectric, or renewable energy generation. The 

secondary air impacts for “other” were assumed to be equivalent to those for natural gas.

4. Wastewater impacts. Appendix B3 contains the methodology used to develop millspecific estimates of wastewater impacts. The wastewater impacts were estimated based solely 

on the biological treatment system upgrade needed to meet the kraft condensate incremental 

reductions. No additional wastewater was expected to be generated with the steam stripper 

upgrades because the upgraded steam strippers would be more efficient than current strippers. 

Therefore, the only mills with wastewater impacts would be those conducting biological 

treatment system upgrades. The additional wastewater generated under the biological treatment 

system upgrades was estimated by solving for “required upgrade (gal/d)” in the following 

equation (EPA 2011a):
7

Incremental reduction (e.g., 95%) = current system capacity (gal/d) + required upgrade (gal/d)

Current reduction (92%) current system capacity (gal/d)

We converted the daily wastewater estimates (gal/d) to annual wastewater estimates

(MM gal/yr), assuming an annual operating period of 360 days per year (d/yr) for each mill.

III.Cost Estimates for Repeat Air Emissions Testing

The EPA is considering repeat HAP emissions performance testing once every 5 years 

for facilities complying with the standards for kraft, soda, and semichemical pulping vent gases; 

sulfite processes; and bleaching systems. Under this testing option, repeat air emissions testing 

would be required for mills complying with the kraft condensate standards using a steam stripper 

(or other equipment serving the same function) since such equipment is, by definition, part of the 

low-volume, high-concentration (LVHC) gas collection system.

The EPA is not considering additional repeat testing for biological treatment systems to 

comply with the kraft pulping condensate standards, because more frequent quarterly sampling is 

already required for biological treatment systems. The EPA is also not considering additional

repeat testing for facilities complying with the clean condensate alternative (CCA) standards due 

to the complexity of this compliance approach.

The repeat emissions tests for chemical pulp mills (e.g., kraft, soda, and semichemical 

pulping vent gases, and sulfite processes) would involve testing for methanol using EPA Method 

308, 320, or 18. Facilities that perform bleaching using chlorinated compounds would be 

required to conduct repeat chlorine tests using EPA Method 26A. The subpart S supporting 

statement (which is revised every 3 years by EPA) indicated emissions testing costs of $14,000 

for Method 308 testing, and $10,000 for Methods 26A testing. These same testing costs were 

used in this analysis. For the purposes of this analysis, we assumed the costs for Method 308 

testing to be equivalent to the costs for Methods 320 and 18 testing.

Testing costs were treated as capital costs because mills will contract with a testing 

company to perform the testing. The capital costs were annualized at 7 percent interest over the 

5-year testing period, assuming that mills would obtain a 5-year loan to finance the testing.

Table 3 presents estimated emissions testing costs.

Table 3. Emissions Testing Costs by Mill Process

Mill type

Subpart S 

standard

Test 

method 

(surrogate 

pollutant)

Systems to be 

tested (typical 

number per mill)

No. 

tests 

per 

mill1

Cost 

per test

Capital 

cost per 

mill every 

5 years

Annualized 

capital cost 

per mill, 

$/yr

Kraft, soda, and 

semichemical 

mills

§63.443(a) Method 308 

(methanol)

LVHC (1), HVLC 

(1), and SOG (1)

3 $14,000 $42,000 $10,243

Kraft mills 

using 

biotreatment

§63.443(a) Method 308 

(methanol)

LVHC (1) and 

HVLC (1)

2 $14,000 $28,000 $6,829

Sulfite mills §63.444 Method 308 

(methanol)

Sulfite emissions 

release point (1)

1 $14,000 $14,000 $3,414
8

Mill type

Subpart S 

standard

Test 

method 

(surrogate 

pollutant)

Systems to be 

tested (typical 

number per mill)

No. 

tests 

per 

mill1

Cost 

per test

Capital 

cost per 

mill every 

5 years

Annualized 

capital cost 

per mill, 

$/yr

Mills bleaching 

with chlorinated 

compounds 

(e.g., ClO2)

§63.445 Method 26A 

(chlorine)

Bleaching system 

vents for chlorinated stages (2)

2 $10,000 $20,000 $4,878

1 Typical number of systems to be tested per mill is based on review of the Part I survey data. 

There are a number of variables that affect actual emissions testing cost per mill, 

including the numbers of equipment/systems to be tested and the subpart S compliance option 

used. In lieu of conducting a mill-by-mill and process-by-process analysis, we reviewed 

information submitted through Part I of the pulp and paper survey to determine typical numbers 

of equipment/systems that may require testing (notwithstanding use of subpart S compliance 

options that do not involve testing). The systems to be tested include LVHC and high-volume, 

low-concentration (HVLC) gas collection systems at kraft, soda, and semichemical mills subject 

to the emissions standards in §63.443(a) of subpart S. Stripper off-gases, though by definition 

part of the LVHC system, are often handled separately from LVHC and represent a separate 

emission point requiring compliance demonstration.

We estimated that the typical kraft, soda, or semichemical mill could be represented by 

one LVHC, one HVLC, and one stripper system that require testing. Kraft mills using 

biotreatment as their predominant kraft condensates control option would not have a SOG 

emission point. Sulfite mills typically route all process emissions through one emission point 

(e.g., a recovery system scrubber). Therefore, only one emissions point requiring testing was 

projected for sulfite mills. Major source mills performing bleaching using any chlorinated 

compounds are subject to the subpart S bleaching standards. The Part I survey data indicated that 

typically two bleaching emission points per mill would require testing.

Except for the unusual circumstance where a mill operates more than one LVHC, HVLC, 

and stripper system and uses compliance options that involve emissions testing, the testing costs 

presented in this memorandum are likely to be overestimated due to the following:

 The costing analysis does not account for mills that use compliance options that do not 

involve emissions testing (e.g., mills that introduce vent gas streams into the flame zone 

of a boiler, lime kiln, or recovery furnace or mills meeting the design criteria for a 

thermal oxidizer). Analysis of the Part I survey data indicates that roughly 85 percent of 

mills use compliance options that do not involve emissions testing for pulping vents. 

 Overall testing costs may be reduced at mills where testing for multiple systems is 

conducted through the same testing program (e.g., because fees for testing contractor 

travel and mobilization would be reduced).

IV. Summary of Nationwide Costs and Impacts

The nationwide costs and impacts associated with the subpart S regulatory options under 

consideration are summarized in Tables 4 and 5 below. Mill-specific estimates of the costs are 
9

presented in Appendix C1, and mill-specific estimates of the impacts are presented in Appendix 

C2. Only major sources of HAP emissions are affected (171 mills).

The number of mills impacted by the incremental efficiency increase in the kraft 

condensates standards ranges from 4 mills (93 percent reduction) to 66 mills (98 percent

reduction). Mills already meeting each incremental limit are not impacted (31 of 97 total kraft 

mills). The potential nationwide emissions reduction (based on emission factor calculations for 

97 mills subject to the revised standards) ranges from 2,046 to 12,275 tpy, with cost 

effectiveness values ranging from $485/ton to $2,700/ton. The nationwide energy impacts, 

secondary emissions, and wastewater impacts for these mills are small (see Table 5).

An estimated 114 mills are expected to be impacted by the repeat testing option, based on 

the number of chemical pulp mills and mills that bleach with chlorinated compounds. The 

nationwide capital and annual costs of repeat testing are estimated to be $5.4 million and $1.3

million, respectively. We could not quantify the specific emissions reduction associated with 

repeat emissions testing. However, it stands to reason that repeat testing would provide incentive 

for facilities to maintain their control systems and make periodic adjustments to ensure peak 

performance, thereby reducing emissions and the potential for periodic episodes of acute risk.

Table 6 presents a summary of the labor hours associated with initially implementing, 

and operating and maintaining the technologies and procedures that form the regulatory options.

Additional reporting and recordkeeping labor hours and costs were developed as part of the 

Paperwork Reduction Act supporting statement for 114 affected mills. The incremental reporting 

and recordkeeping costs resulting from the proposed amendments to subpart S are estimated to 

be $4,344 per mill ($0.50 million nationwide) as a one-time cost to revamp existing 

recordkeeping systems to be consistent with the proposed revisions to the startup and shutdown 

provisions, and $6,516/yr per mill ($0.74 million/yr nationwide) for two instances of affirmative 

defense. Details on these cost estimates, as well as an accounting for the labor hours involved, 

can be found in the supporting statement. (EPA 2011b)
10

Table 4. Summary of Nationwide Costs and Cost Effectiveness

Subpart S regulatory option

Costs

Cost effectiveness, 

$/ton No. of mills affected1 Capital cost, $million

Annualized cost, 

$million/yr

Kraft condensates

 92% → 93% $8.7 $0.99 $485 4

 92% → 94% $36 $4.1 $1,010 15

 92% → 95% $79 $9.0 $1,460 28

 92% → 96% $142 $16 $1,980 41

 92% → 97% $218 $25 $2,420 54

 92% → 98% $297 $34 $2,700 66

Repeat testing $5.4 $1.3 -- 114

Incremental reporting/recordkeeping $0.50 $0.74 -- 114

1 The number of affected major source mills out of a total of 171 major sources subject to subpart S.

Table 5. Summary of Nationwide Environmental and Energy Impacts

Subpart S 

regulatory option

Emissions 

reductions, tpy

Energy 

impacts, 

MMBtu/yr

Secondary emissions, tpy

Wastewater 

impacts, 

MM 

gal/yr

No. of 

mills 

affected1

HAP/ 

VOC1 TRS PM CO NOX SO2 CO2 CH4 N2O

Kraft condensates

 92% → 93% 2,046 612 1,024 0.008 0.06 0.1 0.3 69 0.007 0.001 157 4

 92% → 94% 4,092 1,224 4,809 0.04 0.3 0.5 1.5 324 0.03 0.005 741 15

 92% → 95% 6,138 1,836 11,339 0.09 0.7 1.3 3.6 765 0.08 0.01 1,755 28

 92% → 96% 8,183 2,448 22,003 0.2 1.3 2.5 7.0 1,484 0.1 0.02 3,418 41

 92% → 97% 10,229 3,059 35,478 0.3 2.1 4.0 11 2,392 0.2 0.03 5,533 54

 92% → 98% 12,275 3,671 51,670 0.4 3.1 5.8 16 3,484 0.3 0.05 8,085 66

1 Potential emissions reduction based on emission factor calculations for 97 mills subject to the kraft condensate standards (i.e., includes 

incremental emission reductions already achieved in practice for mills exceeding the current standard since these emission reductions would now 

be required through a change in the existing regulatory limit). VOC emissions reductions were assumed to be essentially equivalent to HAP 

emissions reductions.
11

Table 6. Labor Hour Summary

Subpart S regulatory option

Nationwide labor 

(initial hr)

Nationwide labor, 

hr/yr

Labor wage rate, 

$/hr Labor notes

Kraft condensates

 92% → 93% unknown 2,630 $25/hr = 38% of O&M cost / ($25/hr 

 92% → 94% 11,100 default in CapdetWorks)

 92% → 95% 24,000

 92% → 96% 43,100

 92% → 97% 64,100

 92% → 98% 87,640

Repeat testing unknown unknown unknown embedded in testing cost

Incremental reporting/recordkeeping 5,244 7,866 $97.78 technical,

$118.92 

managerial, 

$48.76 clerical

Labor rates are based on 

methodology customarily used in 

supporting statements. 85% of 

total presented is technical labor, 

5% is management labor, and 

10% percent is clerical labor.
12

V. References

EPA 1980 U.S. Environmental Protection Agency. Technical Report: Construction Costs for 

Municipal Wastewater Treatment Plants: 1973-1978. Document No. EPA/430/9-

80-03. Washington, DC. 1980.

EPA 1993 U.S. Environmental Protection Agency. Pulp, Paper, and Paperboard Industry –

Background Information for Proposed Air Emission Standards; Manufacturing 

Processes at Kraft, Sulfite, Soda, and Semi-Chemical Mills. Document No. EPA453/R-93-050a. Research Triangle Park, NC. October 1993.

EPA 1998a U.S. Environmental Protection Agency. Compilation of Air Pollution Emission 

Factors. 5th Edition. Research Triangle Park, NC. Volume I: Stationary Point and 

Area Sources. Section 1.4: Natural Gas Combustion. July 1998.

EPA 1998b U.S. Environmental Protection Agency. Compilation of Air Pollutant Emission 

Factors, AP-42. 5th Edition. Research Triangle Park, NC. Volume I: Stationary

Point and Area Sources. Section 1.1: Bituminous and Subbituminous Coal 

Combustion. September 1998.

EPA 2011a J. Bradfield and K. Spence, EPA. Memorandum to Docket EPA-HQ-OAR-2007-

0544. Summary of Kraft Condensate Control Technology Review. October 23, 

2011.

EPA 2011b U.S. Environmental Protection Agency. Supporting Statement: NESHAP for Pulp 

and Paper Production (40 CFR Part 63, Subpart S) (Proposed Amendments).

November 2011.

Hydromantis Hydromantis, Inc. CapdetWorks v2.5. Released December 10, 2007.

2007

NCASI 2010 A. Someshwar, NCASI. Compilation of ‘Air Toxic’ and Total Hydrocarbon 

Emissions Data for Pulp and Paper Mill Sources – A Second Update. Technical 

Bulletin No. 973. February 2010.
Appendix A

Summary of CapdetWorks v2.5 Outputs Used in Development of Biological Treatment 

System Upgrade Correlations
Appendix B

Calculations of Mill-Specific Costs and Impacts for Kraft Condensate Regulatory Options

Appendix B1. Kraft Condensate Standards Incremental Improvement Costs

Appendix B2. Kraft Condensate Standards Incremental Emissions Reductions

Appendix B3. Kraft Condensate Standards Energy and Environmental Impacts
B2-1

Appendix B2. Kraft Condensate Standards Incremental Emissions Reductions

Parameters

HAP/ 

VOC TRS Notes and equations

Baseline

SOG 11 3.29 lb/ADTUBP (approx. from NCASI TB 973 Table 4.14)

% condensate control 0.92 0.92

Pollutant in foul 

condensate

11.96 3.58 (lb/ADTUBP) - back-calculated based on 92% reduction

Pollutant in treated 

(stripped) condensate

0.96 0.29 lb/ADTUBP - calculated based on 92% reduction

Reduction in 

condensate

11.00 3.29 lb/ADTUBP = pollutant in foul – pollutant in treated

Tons reduced from 

condensate stream

1,980 592.2 Tons reduced from condensate stream for a 1000 ADTP/d mill 

operating 360 d/yr

Tons incinerated 1,940.4 580.356 Tons reduced from the condensate stream become SOG which are 

incinerated at 98% control

No. of mills 97 97

Nationwide reduction 188,219 56,295 Nationwide reduction (92% control) = 97 mills x reduction in 

incinerator

If change to 93% reduction

SOG 11 3.29 lb/ADTUBP (approx. from NCASI TB 973 Table 4.14)

% condensate control 0.93 0.93

Pollutant in foul 

condensate

11.96 3.58 (lb/ADTUBP) - back-calculated based on 92% reduction [see

above]

Pollutant in treated 

(stripped) condensate

0.84 0.25 lb/ADTUBP

Reduction in 

condensate

11.12 3.33 lb/ADTUBP = pollutant in foul – pollutant in treated

Tons reduced from 

condensate stream

2,002 599 Tons reduced from condensate stream for a 1000 ADTP/d mill 

operating 360 d/yr

Tons incinerated 1,961 587 Tons reduced from the condensate stream become SOG which are 

incinerated at 98% control

No. of mills 97 97 No. of mills 

Nationwide reduction 190,265 56,906 Nationwide reduction (93% control) = 97 mills x reduction in 

incinerator

Incremental reduction 2,046 612 Incremental reduction, tpy, from increasing above 92% control

If change to 94% reduction

SOG 11 3.29 lb/ADTUBP (approx. from NCASI TB 973 Table 4.14)

% condensate control 0.94 0.94

Pollutant in foul 

condensate

11.96 3.58 (lb/ADTUBP) - back-calculated based on 92% reduction [see 

above]

Pollutant in treated 

(stripped) condensate

0.72 0.21 lb/ADTUBP

Reduction in 

condensate

11.24 3.36 lb/ADTUBP = pollutant in foul – pollutant in treated

Tons reduced from 

condensate stream

2,023 605 Tons reduced from condensate stream for a 1000 ADTP/d mill 

operating 360 d/yr

Tons incinerated 1,983 593 Tons reduced from the condensate stream become SOG which are 

incinerated at 98% control

No. of mills 97 97 No. of mills

Nationwide reduction 192,311 57,518 Nationwide reduction (94% control) = 97 mills x reduction in 

incinerator

Incremental reduction 4,092 1,224 Incremental reduction, tpy, from increasing above 92% control
B2-2

Parameters

HAP/ 

VOC TRS Notes and equations

If change to 95% reduction

SOG 11 3.29 lb/ADTUBP (approx. from NCASI TB 973 Table 4.14)

% condensate control 0.95 0.95

Pollutant in foul 

condensate

11.96 3.58 (lb/ADTUBP) - back-calculated based on 92% reduction [see 

above]

Pollutant in treated 

(stripped) condensate

0.60 0.18 lb/ADTUBP

Reduction in 

condensate

11.36 3.40 lb/ADTUBP = pollutant in foul – pollutant in treated

Tons reduced from 

condensate stream

2,045 612 Tons reduced from condensate stream for a 1000 ADTP/d mill 

operating 360 d/yr

Tons incinerated 2,004 599 Tons reduced from the condensate stream become SOG which are 

incinerated at 98% control

No. of mills 97 97 No. of mills

Nationwide reduction 194,356 58,130 Nationwide reduction (95% control) = 97 mills x reduction in 

incinerator

Incremental reduction 6,138 1,836 Incremental reduction, tpy, from increasing above 92% control

If change to 96% reduction

SOG 11 3.29 lb/ADTUBP (approx. from NCASI TB 973 Table 4.14)

% condensate control 0.96 0.96

Pollutant in foul 

condensate

11.96 3.58 (lb/ADTUBP) - back-calculated based on 92% reduction [see 

above]

Pollutant in treated 

(stripped) condensate

0.48 0.14 lb/ADTUBP

Reduction in 

condensate

11.48 3.43 lb/ADTUBP = pollutant in foul – pollutant in treated

Tons reduced from 

condensate stream

2,066 618 Tons reduced from condensate stream for a 1000 ADTP/d mill 

operating 360 d/yr

Tons incinerated 2,025 606 Tons reduced from the condensate stream become SOG which are 

incinerated at 98% control

No. of mills 97 97 No. of mills

Nationwide reduction 198,402 58,742 Nationwide reduction (96% control) = 97 mills x reduction in 

incinerator

Incremental reduction 8,183 2,448 Incremental reduction, tpy, from increasing above 92% control

If change to 97% reduction

SOG 11 3.29 lb/ADTUBP (approx. from NCASI TB 973 Table 4.14)

% condensate control 0.97 0.97

Pollutant in foul 

condensate

11.96 3.58 (lb/ADTUBP) - back-calculated based on 92% reduction [see 

above]

Pollutant in treated 

(stripped) condensate

0.36 0.11 lb/ADTUBP

Reduction in 

condensate

11.60 3.47 lb/ADTUBP = pollutant in foul – pollutant in treated

Tons reduced from 

condensate stream

2,088 624 Tons reduced from condensate stream for a 1000 ADTP/d mill 

operating 360 d/yr

Tons incinerated 2,046 612 Tons reduced from the condensate stream become SOG which are 

incinerated at 98% control

No. of mills 97 97 No. of mills

Nationwide reduction 198,448 59,354 Nationwide reduction (97% control) = 97 mills x reduction in 

incinerator

Incremental reduction 10,229 3,059 Incremental reduction, tpy, from increasing above 92% control
B2-3

Parameters

HAP/ 

VOC TRS Notes and equations

If change to 98% reduction

SOG 11 3.29 lb/ADTUBP (approx. from NCASI TB 973 Table 4.14)

% condensate control 0.98 0.98

Pollutant in foul 

condensate

11.96 3.58 (lb/ADTUBP) - back-calculated based on 92% reduction [see 

above]

Pollutant in treated 

(stripped) condensate

0.24 0.07 lb/ADTUBP

Reduction in 

condensate

11.72 3.50 lb/ADTUBP = pollutant in foul – pollutant in treated

Tons reduced from 

condensate stream

2109 631 Tons reduced from condensate stream for a 1000 ADTP/d mill 

operating 360 d/yr

Tons incinerated 2067 618 Tons reduced from the condensate stream become SOG which are 

incinerated at 98% control

No. of mills 97 97 No. of mills

Nationwide reduction 200,494 59,966 Nationwide reduction (98% control) = 97 mills x reduction in 

incinerator

Incremental reduction 12,275 3,671 Incremental reduction, tpy, from increasing above 92% control
B3-1

Appendix B3. Kraft Condensate Standards Energy and Environmental Impacts

Parameters Value Notes, units, and equations

Energy impacts

Electricity requirements mill-specific kWh/yr = biological system upgrade annual energy O&M cost 

($/yr) / ($0.1/kWh)

Energy impacts mill-specific MMBtu/yr = (kWh/yr) x (3415.179 Btu/kWh) x (MMBtu/1E6

Btu)

Secondary emissions

Percent of generation

Coal 53% Used for solid fuel

Oil/natural gas 21% Used for natural gas

Nuclear 17% No secondary emissions estimated

Hydroelectric 6% No secondary emissions estimated

Renewable 2% No secondary emissions estimated

Other 1% Used for natural gas (assumed equivalent)

Particulate matter

Emission factor (natural gas) 1.9 lb/MM ft3natural gas

0.00186275 lb/MMBtu natural gas

Emission factor (solid fuel) 0.03 lb/MMBtu solid, liquid, gaseous fuel

Secondary emissions mill-specific lb/yr = ∑ (MMBtu/yr) x (lb/MMBtu) x (% of generation), for 

solid fuel and natural gas

Carbon monoxide

Emission factor (natural gas) 84 lb/MM ft3natural gas

0.0824 lb/MMBtu natural gas

Emission factor (solid fuel) 0.19 lb/MMBtu bituminous coal

Secondary emissions mill-specific lb/yr = ∑ (MMBtu/yr) x (lb/MMBtu) x (% of generation), for 

solid fuel and natural gas

Nitrogen oxides

Emission factor (natural gas) 100 lb/MM ft3natural gas

0.0980 lb/MMBtu natural gas

Emission factor (solid fuel) 0.38 lb/MMBtu solid fuel

Secondary emissions mill-specific lb/yr = ∑ (MMBtu/yr) x (lb/MMBtu) x (% of generation), for 

solid fuel and natural gas

Sulfur dioxide

Emission factor (natural gas) 0.6 lb/MM ft3natural gas

0.00059 lb/MMBtu natural gas

Emission factor (solid fuel) 1.2 lb/MMBtu solid fuel

Secondary emissions mill-specific lb/yr = ∑ (MMBtu/yr) x (lb/MMBtu) x (% of generation), for 

solid fuel and natural gas

Carbon dioxide

Emission factor (natural gas) 53.02 kg/MMBtu natural gas

Emission factor (solid fuel) 93.4 kg/MMBtu solid fuel

Secondary emissions mill-specific lb/yr = ∑ (MMBtu/yr) x (kg/MMBtu) x (2.204623 lb/kg) x (% of 

generation), for solid fuel and natural gas

Methane

Emission factor (natural gas) 0.001 kg/MMBtu natural gas

Emission factor (solid fuel) 0.011 kg/MMBtu solid fuel

Secondary emissions mill-specific lb/yr = ∑ (MMBtu/yr) x (kg/MMBtu) x (2.204623 lb/kg) x (% of 

generation), for solid fuel and natural gas

Nitrous oxide

Emission factor (natural gas) 0.0001 kg/MMBtu natural gas

Emission factor (solid fuel) 0.0016 kg/MMBtu solid fuel

Secondary emissions mill-specific lb/yr = ∑ (MMBtu/yr) x (kg/MMBtu) x (2.204623 lb/kg) x (% of 

generation), for solid fuel and natural gas
B3-2

Parameters Value Notes, units, and equations

Carbon dioxide equivalents

Global warming potential-CH4 21 Unitless

Global warming potential-N2O 310 Unitless

Secondary emissions mill-specific CO2eq, lb/yr = [CO2 (lb/yr)] + [21 x CH4 (lb/yr)] + [310 x N2O 

(lb/yr)]

Wastewater impacts

System upgrade mill-specific gal/d = (incremental reduction [e.g., 95%]) x (current system 

capacity [gal/d])/(current reduction [92%]) - current system 

capacity (gal/d)

Wastewater impacts mill-specific MM gal/yr = (gal/d) x (360 d/yr) x (MM gal/yr/1E6gal)

Notes:

1. Assume electricity generated using the mix listed in the table (from IPM Version 3.0 for the year 2015). IPM is 

EPA’s Integrated Planning Model, which is a forecast model of the U.S. electric power sector.

2. For natural gas combustion, used AP-42 emission factors for PM, CO, NOX, and SO2. (EPA 1998a) Assumed 

1,020 Btu/ft3of natural gas in estimating PM, CO, NOX, and SO2 secondary emissions. Used 40 CFR part 98, 

subpart C emission factors for CO2, CH4, and N2O.

3. For solid fuel combustion, used NSPS emission factors for PM and SO2 (40 CFR part 60, subpart Da, coal-fired 

utility plants), used AP-42 emission factors for NOx and CO (bituminuous/subbituminous coal combustion/spreader 

stoker). (EPA 1998b) The NOx emission factor was based on average of NOx emission factors for spreader stoker 

type boilers burning bituminous (11 lb/ton) and subbituminous (8.8 lb/ton) coal. Assumed 13,000 Btu/lb of coal in 

estimating NOX and CO secondary emissions. Used 40 CFR part 98, subpart C emission factors for CO2 (bituminous 

coal) and CH4 and N2O (coal/coke).
Appendix C

Mill-Specific Cost and Impacts Estimates for Regulatory Options under Consideration for 

Subpart S RTR Proposal

Appendix C1. Mill-Specific Cost Estimates for Regulatory Options under Consideration for 

Subpart S RTR Proposal

Appendix C2. Mill-Specific Impacts Estimates for Regulatory Options under Consideration for 

Subpart S RTR Proposal