Date: November 1 7 , 2011

Subject: Cost s 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 Schro ck 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 an d 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. Th e 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 b y 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 s ubpart S RTR proposal
. Section II discuss es the derivation of the costs and impacts associated with the kraft condensates regulatory options
. Section I II presents the costs associated with the proposed repeat HAP emissions testing requirem ent. Finally , s ection 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 b y one of the following meth ods: 1. Route the condensates to equipment that meets the s ubpart 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 tot al HAP by

at least 92 w eight -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 Iof 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 ty pically use either steam stripping of contaminated condensates or hard piping of c ondensates 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**  **M ills**  **U sing**  **V arious**  **C ondensate**  **T reatment**  **M ethods** 

**Treatment Method No. of mills**  Biotreatment 39 Recycle 5 Stripping or s tripping/r ecycle 43 Stripping and biotreatment 9 Thermal incinerator 1 **Total 97**  The regulatory

op tions considered for the s ubp art S RTR include tightening the kraft condensates standards to reflect the current p erformance of technology and further reduce emissions associated with kraft pulping and wastewater. A series of different emission limits were considered , including increasing the require ment 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 re quire upgrade or replacement of existing equipment by other mills. A separate memo (EPA 2011 a) describes the3

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 E**  **ach Incremental Adjustment in the Kraft Condensate Emission Reduction Limit**  **Percent r eduction (%)**  **No. of m ills meeting**  **% reduction**  **limit No. of mills affected by** 

**incremental adjustment of limit** 92 97 0 93 93 4 94 82 15 95 69 2 8 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 no t 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 biol ogical treatment. (EPA 2011 a) For costing purposes, it was assumed that the wastewater treatment s ys tem 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 m illi on gallon per day (MM gal/d) plant would increase capacity b y 0.33 MM gal/day ([10 x 95/92]

– 10 ≈ 0.33)
. (EPA 2011 a) Wastewater treatment plant upgrade costs were based on the following cost equations (where MGD is millions of gallons per day).

Capital cost ($) = 5.9749 x MGD 0.8228 x 1,000,000 O&M cost ($/yr) = 0.2546 x MGD 0.6969 x 1,000,000 The cost equations were derived from CapdetWorks v2.5 model runs for a c omplete

- m ix activated s ludge sludge sy stem containing a bioreactor and secondary c larifier scaled to 2010 dollars using Engineering News

- Record (ENR) indices
. CapdetWorks v2.5 is a comm erciall y available software program for the preliminary design and costing of wastewater treatment sy stems. (H ydromantis 2007) The capital cost equation developed using CapdetWorks was found to compare reasonabl y well to a wastewater treatment plant cost e quation 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 d eveloped using CapdetWorks and includes labor, chemicals, materials, and energy
. Total l abor averag ed 38 percent o f the annual cost at an O&M wage rate of $25/hr , and this information was used to calculate the annual labor hours per year4

associated with biotreatment sy stem upgrades
. The CapdetWorks v2.5 default electricity cost of $0.1 0/kWh was used to calculate energy use (kWh) associated with the biological treatment sy stem 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 B 1 presents the mill

- by

- mill costs for biological treatment system upgrades extrapolated from these model costs. The annualized c apital costs were determined by applying a capital recovery fac tor of 0.094 to the estimated capital cost. The capital recovery factor was estimated assuming a 20
- year equipment life and 7 percent interes t rate.
**C. Cost of**  **Steam Stripper Upgrades** S team stripper costs were developed for mills currently using steam stripping to compl y with the kraft condensates limit. (EPA 2011 a) Mills needing to improve stripper perfor mance by 2 percent or less were e xpected to upgrade their existing steam strippers, and mills needing to improve stripper performance b y more than 2 percent w ere 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 199 3) The 1991 capital cost of $3.5 million was scaled to 2010 dollars using the Chemical Engineering Plant Cost Index ( CEP CI) ( 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). Annual ize d capital costs were estimated base d 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 likel y 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 B 1 presents the mill

- by

- mill costs for steam stripper upgrades bas ed 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, seco ndary emissions, and wastewater impacts. 1. Emissions reductions
. Appendix B 2 contains the methodology used to develop mill

specific HAP and non

- HAP emission s reductions for the condensate regulatory options
. The predominant HAPs from kraft condensates are methanol and acetaldehyd e. 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 emission s reduction calculations because emission factors are re adily available for strippers (unlike for biological treatment s ys tems , where modeling of emission rates is required)
. Biological treatment systems are expected to achieve an equivalent emissions reduction. Uncontrolled HAP em issions 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 day s 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 NCASITechnical 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 emissi on factor of 3.29 lb TRS/ADTUBP, based on the emission factor for SOG from NCASITe chnical Bulletin 973 (Table 4.14). F or purposes of this incremental anal ys is , 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 ( SO 2 ), the additional amount of SOG s 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 SO 2 emissions generated would also be relativel y 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 sy stem u pgrade 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 likel y to be m ore energy efficient. (EPA 2001) Therefore, the onl y 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 th ermal units per year (MMBtu/y

r) in order to estimate secondary emissions
. 3. Secondary air emissions
. Appendix B3 contains the methodology used to develop mill

specific estimates of secondary air emissions. Secondary air emissions include the criteria pollutant emissions

—

particulate m atter (PM ) , carbon monoxide ( CO ) , nitrogen oxides (NO X ) , and SO 2—that result from the generation of electricity to achieve the biological treatment s ys tem upgrades. The electricity was assumed to be purchased from offsite utilities , rather than generated o nsite
. We also developed secondary emissions estimates for greenhouse gases carbon dioxide (CO 2 ), methane (CH 4 ), and nitrous oxide (N 2 O) expected to be emitted from utilities.6

We used a variety of information sources for the emission factors used to estim ate the secondary emissions. For natural gas, we used emission factors (in pound per cubic foot [ lb/ft 3 ] of natural gas) from the AP

- 42 chapter on natural gas combustion to estimate the secondary emissions for PM, CO, NO X , and SO 2 . (EPA 1998a) We used the AP
- 42 conversion factor of 1,020 Btu/ft 3 of 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 CO 2 , CH 4 , and N2 O. Global warming potentials of 1 for CO 2 , 21 for CH 4 , and 310 for N 2 O (from Tab le A

- 1 to subpart A of part 98) were used to estimate CO 2 equivalent emissions (CO 2 eq). 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 es timate the secondary emissions for PM and SO 2 . We used emis sion factors (in lb/ton coal) from the AP

- 42 chapter on coal combustion to estimate the secondary emissions for NO X and CO
. (We specificall y used the AP

- 42 emission factors for bituminuous/subbitum inous coal combustion/spreader stoker s. The NO X emission factor was based on an average of the AP

- 42 emission factors for spreader stoker typ e boilers burning bituminous ( 11 lb/ton) and subbituminous ( 8.8 lb/ton) coal. We used the AP

- 42 conversion factor o f 13,000 Btu/lb of coal to facilitate estimating the secondary emissions for NO X and CO from coal
. We used emission factors (in kg/MMBtu) from 40 CFR part 98, subpart C to estimate the secondary emissions for CO 2 ( for units burning bituminous coal) and for CH 4 and N 2 O ( for units burning coal/coke). As before, we used the aforementioned g lobal warming potentials for CO 2 , CH 4 , and N 2 O to estimate CO 2 eq . 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, o r 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 th e methodology used to develop mill

specific estimates of wastewater impacts. The wastewater impacts were estimated based solel y 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 onl y mills with wastewater impacts would be those conducting biological treatment s ys tem upgrades. The additional wastewater generated under the biological treatment sy stem upgrades was estimated by solving for “required upgrade (gal/d)” in the following equation (EPA 2011 a):7

In cremental reduction (e.g., 9 5 %) = current s ys tem capacity (gal/d) + re quired upgrade (gal/d) Current reduction (92%) current s ys tem capacity (gal/d) We converted the daily

wastewater estimate s (gal/d) to annual wastewater estimates (MM gal/yr), assuming an annual operating period of 360 days per ye ar (d/y r) for each mill
. **III. Cost Estimates for Repeat**  **Air Em** **issions 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 ble aching sy stems. 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, b y definition, part of the low

- volume, high

- concentration ( LVHC ) gas collection sy stem. The EPA is not considering additional repeat testing for biological treatment sy stems to comply with the kraft pulping condensate standards , because more frequent quarterl y sampling is already required for biological treatment s ys tems. 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 b e 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 sam e testing c osts were used in this analysis. For the purposes of this anal ysis, 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 contrac t with a testing company to perform the testing. The capital costs were annualized at 7 percent interest over the 5
- ye ar testing period , assuming that mills would obtain a 5
- year loan to finance the testing. Table 3 presents estimated emissions testing cos ts.

**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**  **mi ll**  **1 Cost**  **per test Capital** 

**cost per mi**  **ll every 5 years**  **Annualized**

**capital cos t**  **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 $3,4148

**Mill type Subpart S** 

**standard Test** 

**method (surrogate**  **pollutant) Systems to be** 

**tested (typical number per mill)**  **No.**

**tests per**  **mi ll**  **1 Cost**  **per test Capital** 

**cost per mi**  **ll every 5 years**  **Annualized**

**capital cos t**  **per mill, $/yr**  Mills bleaching with chlorinated compounds (e.g., ClO 2 ) §63.445 Method 26A (chlorine) Bleaching system

vents for chlori

nated stages (2) 2 $10,000 $ 20,000 $4,878

1 Ty pical 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 s ubpart 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 ty pical numbers of equipment/systems that may require te sting (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 ty

pical kraft, soda, or semichemical mill could be represented b y one LVHC, one HVL C, and one stripper s ys tem that require testing. Kraft mills using biotreatment as their predominant kraft condensates control option would not have a SOG emission point. Sulfite mills ty pically route all process emissions through one emission point (e.g., a recovery

s ys tem scrubber). Therefore, onl y one emissions point requiring testing was projected for sulfite mills. Major source mills performing bleaching using any chlorinated compound s are subject to the subpart S bleaching standards. The Part I survey data indicated that ty picall y two bleaching emission points per mill would require testing. Except for the unusual circumstance where a mill operates more than one LVHC, HVL C, and stripper s ys tem and uses compliance options that involve emissions testing , the testing costs presented in this memorandum are likel y to be overestimated due to the following:

 The costing anal ys is does not account for mills that use compliance options th at 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). Anal ysis of the Part I survey data indicates that roughl y 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 sy stems 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 s ubpart S regulatory options under consideration are summarized in Table s 4 and 5 below
. Mill

- specif ic estimates of the cost s are9

presented in Appendix C 1, and mill

- specific estimates of the impacts are presented in Appendix C 2
. Only major sources of HAP emissions are affected (1 7 1 mills)
. The number of mills impacted b y the incremental efficiency incre ase 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 9 7 mills subject to the revised standards ) range s from 2,0 46 to 12, 275 tpy , with cost effectiveness values ranging from $48 5 /ton to $2,700/ton. The nationwide energy impacts, secondary emissions, and wastewater imp acts 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 c osts of repeat testing are estimated to be $ 5.4 million and $1.3 million, respectively
. W e could not quantify the specific emissions reduction associated with repeat emissions testing. However, it stands to reason that repeat testing would provide incentiv e for facilities to maintain their control s ys tems and make periodic adjustments to ensure peak performance, thereb y 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 fo r 114 affected mills
. The incremental reporting and recordkeeping costs resulting from the proposed amendments to s ubpart S are estimated to be $4,344 per mill ($0.50 million nationwide) as a one - time cost to revamp existing recordkeeping s ys tems to be con sistent with the proposed revisions to the startup and shutdown provisions, and $6,516/y

r per mill ($0.74 million/y r nationwide) for two instances of affirmative defense. Details on these cost estimates, as well as an accounting for the labor hours involve d, can be found in the supporting stat ement. (EPA 2011b )10 **Table 4**  **. Summary of Nationwide Costs**  **and Cost Effectiveness Subpart S regulatory option**  **Costs Cost effectiveness,**  **$/ton No. of mills affected**  **1 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 1 71 maj or sources subject to subpart S.
**Table 5**  **. Summary of Nationwide Environmental and Energy Impacts**
**Subpart S regulatory option**  **Emissions**

**reductio ns, tpy**  **Energy**

**impacts, MMBtu/yr**  **Secondary emissions, tpy Waste**  **** **water impacts,**  **MM gal/yr**  **No. of**

**mills affected**  **1 HAP/**  **VOC 1**  **TRS PM**  **CO NO**  **X SO**  **2 CO**  **2 CH**  **4 N**  **2 O**  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 74 1 15 92% → 95% 6,138 1,836 11,339 0.09 0.7 1.3 3.6 765 0.08 0.01 1,7 55 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 calculatio ns 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 re ductions would now be required through a change in the ex isting 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 L**  **abor notes** Kraft condensates 92% → 93% unknown 2,630 $25/hr = 38% of O& M cost / ($25/hr default in CapdetWorks) 92% → 94% 11,100 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 W

astewater Treatment Plants: 1973

- 1978. Document No
. EPA/430/9

- 80
- 03. Washington , DC. 1 980
. 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 M ills. Document No. EPA
453/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
. 5 th 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 Prot ection Agency
. Supporting Statement: NESHAP for Pulp

and Paper Production (40 CFR Part 63, Subpart S) (Proposed Amendments)
. November 2011. Hydromantis Hydromantis, Inc. CapdetW orks v2.5 . Released December 10, 2007. 2007 NCASI201 0 A. Someshwar, NCASI. C ompilation 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

**Calculation s**  **of Mill**  **- Specific**  **Costs and Impacts**  **for Kraft Condensate Regulatory Options** 

Appendix B 1. Kraft Condensate Standards Incremental Improvement Costs Appendix B 2. Kraft Condensate Standards Incremental Emission s Reductions Appendix B3. Kraft Condensate Standards Energy and Environmental ImpactsB2
- 1

**Appendix B 2**  **. Kraft Condensate**  **Standards Incremental Em** **issions Reductions Param**  **eters HAP/** 

**VOC TRS**  **Notes and e quations**  **Baseline** SOG 11 3.29 lb/ADTUBP (approx. from NCA SI 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 T ons reduced from condensate stream 1 , 980 592.2 T ons reduced from condensate stream for a 1000 ADTP /d mill operating 360 d/yr Tons incinerated 1 , 940.4 580.356 T ons reduced from the condensate stream become SOG which are incinerated at 98% control No. of mills 97 97 Nationwide reduction 188,219 56,295 N ationwide reduction (92% control) = 9 7 mills x reduction in incinerator **If change to 93% reduction** SOG 11 3.29 lb/ADTUBP (app rox. from NCASI TB 973 Table 4.14) % condensate control 0.93 0.93 Pollutant in foul condensate 11.96 3.58 (lb/ADTUBP)

- back

- calc ulated 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 T ons reduced from condensate stream 2 , 002 599 T ons reduced from condensate stream for a 1000 ADTP /d mill operating 360 d/yr Tons incinerated 1 , 961 587 T ons 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 N ationwide reduction (93 % control) = 9 7 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 (app rox. from NCASI TB 973 Table 4.14) % condensate control 0.94 0.94 Pollutant in foul condensate 11.96 3.58 (lb/ADTUBP)

- back

- calc ulated 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 T ons reduced from condensate stream 2 , 023 605 T ons reduced from condensate stre am for a 1000 ADTP /d mill operating 360 d/yr Tons incinerated 1 , 983 593 T ons 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 N ationwide reduction (9 4 % control) = 9 7 mills x reduction in incinerator Incremental reduction 4,092 1,224 Incremental reduction, tpy, from increasing above 92% controlB2
- 2

**Param eters**  **HAP/**

**VOC TRS**  **Notes and e quations** 

**If change to 95% reduction** SOG 11 3.29 lb/ADTUBP (app rox. from NCASI TB 973 Table 4.14) % condensate control 0.95 0.95 Pollutant in foul condensate 11.96 3.58 (lb/ADTUBP)

- back

- calc ulated 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

– po llutant in treated T ons reduced from condensate stream 2 , 045 612 T ons reduced from condensate stream for a 1000 ADTP /d mill operating 360 d/yr Tons incinerated 2 , 004 599 T ons 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 N ationwide reduction (9 5 % control) = 9 7 mills x reduction in incinerator Incremental reduction 6,138 1,836 Incremental reduction, tpy, from increasing above 92% control **If chan ge to 96% reduction**  SOG 11 3.29 lb /ADTUBP (app rox. from NCASI TB 973 Table 4.14) % condensate control 0.96 0.96 Pollutant in foul condensate 11.96 3.58 (lb/ADTUBP)

- back

- calc ulated based on 92% reduction [see above] Pollutant in treated (stripped) co ndensate 0.48 0.14 lb /ADTUBP Reduction in condensate 11.48 3.43 lb/ADTUBP = pollutant in foul

– pollutant in treated T ons reduced from condensate stream 2 , 066 618 T ons reduced from condensate stream for a 1000 ADTP /d mill operating 360 d/yr Tons incinerated 2 , 025 606 T ons 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 N ationwide reduction (9 6 % control) = 9 7 mills x reduction in incinerator Increme ntal reduction 8,183 2,448 Incremental reduction, tpy, from increasing above 92% control **If change to 97% reduction** SOG 11 3.29 lb /ADTUBP (app rox. from NCASI TB 973 Table 4.14) % condensate control 0.97 0.97 Pollutant in foul condensate 11.96 3.58 ( lb /ADTUBP)

- back

- calc ulated 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 T ons reduced from condensate stream 2 , 088 624 T ons reduced from condensate stream for a 1000 ADTP /d mill operating 360 d/yr Tons incinerated 2 , 046 612 T ons 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 N ationwide reduction (97 % control) = 9 7 mills x reduction in incinerator Incremental reduction 10,229 3,059 Incremental reduction, tpy, from increasing above 92% controlB2
- 3

**Param eters**  **HAP/**

**VOC TRS**  **Notes and e quations** 

**If change to 98% reduction** SOG 11 3.29 lb /ADTUBP (app rox. from NCASI TB 973 Table 4.14) % condensate control 0.98 0.98 Pollutant in foul condensate 11.96 3.58 (lb /ADTUBP)

- back

- calc ulated 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 T ons reduced from condensate stream 2109 631 T ons reduced from condensate stream for a 1000 ADTP /d mill operating 360 d/yr Tons incinerated 2067 618 T ons reduced from the condensate stream beco me SOG which are incinerated at 98% control No. of mills 97 97 No. of mills Nationwide reduction 200,494 59,966 N ationwide reduction (9 8 % control) = 9 7 mills x reduction in incinerator Incremental reduction 12,275 3,671 Incremental reduction, tpy, fro m increasing above 92% controlB3
- 1

**Appendix B 3.**  **Kraft Condensate Standards Energy and Environmental**  **Impacts Param**  **eters Value**  **Notes, u nits**  **, and equations Energy impacts**  Electricity requirements mill

- specific kWh/yr = b iological 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/1E 6 Btu) **Secondary em issions**  Percent of generation Coal 53% Used for solid fuel Oil/natural gas 21% Used for natural gas Nuclear 17% No sec ondary 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 ft 3 natural ga s 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 Emissi on factor (natural gas) 84 lb/MM ft 3 natural 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 ft 3 natural 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 generati on), for solid fuel and natural gas Sulfur dioxide Emission factor (natural gas) 0.6 lb/MM ft 3 natural 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 = ∑ (MMBt u/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

- specif ic lb/yr = ∑ (MMBtu/yr) x (kg/MMBtu) x ( 2.204623 lb/kg) x (% of generation), for solid fuel and natural gasB3
- 2

**Param eters**  **Value Notes, u**  **nits , and equations**  Carbon dioxide equivalents Global warming potential

- CH 4 21 Unitless Global warming potential

-N 2 O 310 Unitless Secondary emissions mill

- specific C O 2 eq, lb/yr = [CO 2 (lb/yr)] + [21 x CH 4 (lb/yr)] + [ 310 x N 2 O (lb/yr)] **Wastewater impacts** Sy stem upgrade mill

- specific gal/d = (incremental reduction [ e.g., 9 5 % ] ) x ( current system capacity [ gal/d ])/(c urrent reduction [92%])

- current system capacity (g al/d) Wastewater im

pacts mill

- specific MM gal/yr = (gal/d) x (360 d/yr) x (MM gal/yr/1E 6 gal) 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 mo del of the U.S. electric power sector
. 2 . For natural gas combustion, used AP

- 42 emission factors for PM, CO, NO X , and SO 2 . (EPA 1998a) Assumed 1,020 Btu/ft 3 of natural gas in estimating PM, CO, NO X , and SO 2 secondary emissions. U sed 40 CF R part 98, subpart C emission factors for CO 2 , CH 4 , and N 2 O. 3 . For solid fuel combustion, used NSPS emission factors for PM and SO 2 (40 CFR part 60, subpart Da, coal

- fired utility plants), used AP

- 42 emission factors for NO x and CO (bituminuous/subbituminous coal combustion/spreader stoker). (EPA 1998b) The NO x emission fa ctor was based on average of NO x emission factors for spreader stoker ty pe boilers burning bituminous (11 lb/ton) and subbituminous (8.8 lb/ton) coal. Assumed 13,000 Btu/lb of coal in estimating NO X and CO secondary emissions. Used 40 CFR part 98, subpart C emission factors for CO 2 (bituminous coal) and CH 4 and N 2 O (coal/coke).

## Appendix **C**

**Mill -**  **Specific Cost**  **and Impacts Estimates**  **for Regulatory Options under Considerati on for**  **Subpart S RTR Proposal** Appendix C 1. 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 Propo sal