United States Environmental Protection Agency, Region 9 

Air Division 

Technical Support Document 

for 

EPA’s Notice of Proposed Rulemaking 

for the 

California State Implementation Plan 

San Joaquin Valley Unified Air Pollution Control District’s 

Rule 4352, Solid Fuel Fired Boilers, Steam Generators and Process Heaters 

Prepared by: Idalia Perez 

April 2012 
Page 2 of 15

San Joaquin Valley Unified Air Pollution Control District (SJVUAPCD) 

Submitted Rule 

SJVUAPCD Rule 4352, Solid Fuel Fired Boilers, Steam Generators and Process Heaters: 

§ Amended: December 15, 2011 

§ Submitted: February 23, 2012 

§ Determined complete: March 13, 2012 

Previous Rule Submittals 

There are no outstanding submittals of Rule 4352. 

SIP-Approved Rule 

On October 1, 2010 (75 FR 60623) we finalized a limited approval, limited disapproval 

of a previous version of Rule 4352. 

Rule Summary 

Rule 4352 limits NOx and CO emissions from solid fuel fired boilers, steam generators 

and process heaters. The facilities in SJVUAPCD that are subject to Rule 4352 can burn a 

variety of fuels including biomass, agricultural waste, wood waste, coal, tire derived fuel, 

petroleum coke and municipal solid waste (MSW). The submitted rule revisions include: 

• Additional definitions for “Flame Stabilization” and “Hot Standby” as well as 

expanded definitions for “Shutdown” and “Start-up”; 

• More stringent NOx emission limits for units firing biomass, MSW and other 

solid fuels in Section 5.1; 

• Deletion of provisions allowing alternate emission limits for units operating at 

less than 50% of their rated heat input; 

• Other minor clarifications. 

The more stringent NOx emission limits in the rule are (Section 5.1): 

§ 165 ppm at 12% CO2 for units fueled with municipal solid waste (MSW). 

§ 90 ppm at 3% O2 for units fueled with biomass. 

§ 65 ppm at 3% O2 for units fueled with other solid fuels. 

Effects on Emissions 

The District does not expect implementation of this revised rule to result in actual 

emission reductions compared to the SIP-approved rule, because all existing facilities 

subject to the rule are already subject to permits containing more stringent emission 

limits. 

Rule Evaluation Criteria 

We have evaluated Rule 4352 in accordance with the following criteria: 

1. Rule Stringency – The San Joaquin Valley (SJV) is designated as 

nonattainment for both the 1997 and 2006 fine particulate matter (PM2.5) 

National Ambient Air Quality Standards (NAAQS) and designated and 

classified as extreme nonattainment for both the 1-hour and 8-hour Ozone 
Page 3 of 15

NAAQS. 40 CFR 81.305. Accordingly, CAA section 172(c)(1) requires 

implementation of all reasonably available control measures (RACM) 

necessary for expeditious attainment of these NAAQS in the SJV.1In 

addition, the SJV is subject to the NOx RACT requirement in CAA § 

182(b)(2) and (f). See 40 CFR § 51.912(a). Because Rule 4352 regulates 

major NOx emission sources, we have evaluated the control requirements 

in the rule to determine whether they satisfy the NOx RACT requirement 

in CAA § 182(b)(2) and (f).

We are not evaluating the stringency of the CO emission limits in Rule 

4352 because the SJV is designated as attainment or 

unclassifiable/attainment for the CO NAAQS. 40 CFR 81.305. 

2. Enforceability – CAA section 110(a)(2)(A) requires that regulations 

submitted to EPA for approval into a State Implementation Plan (SIP) be 

clear and legally enforceable. 

3. SIP Revisions - CAA section 110(l) prohibits EPA from approving any 

SIP revision that would interfere with any applicable requirement 

concerning attainment and reasonable further progress (RFP) or any other 

applicable requirement of the CAA. In addition, CAA section 193 

prohibits the modification of any SIP-approved control requirement in 

effect before November 15, 1990, in a nonattainment area.

Guidance and policy documents that we used to evaluate Rule 4352 include the 

following: 

• Issues Relating to VOC Regulation, Cutpoints, Deficiencies, and Deviations (the 

“Blue Book”), US EPA, OAQPS (May 25, 1988). 

• Guidance Document for Correcting Common VOC and Other Rule Deficiencies, 

EPA Region IX (August 21, 2001, the “Little Bluebook”). 

• State Implementation Plans; General Preamble for the Implementation of Title I 

of the Clean Air Act Amendments of 1990, 57 FR 13498 (April 16, 1992); 57 FR 

18070 (April 28, 1992). 

• State Implementation Plans; Nitrogen Oxides Supplement to the General 

Preamble; Clean Air Act Amendments of 1990 Implementation of Title I; 

Proposed Rule, 57 FR 55620 (Nov. 25, 1992). 

• Preamble, Final Rule to Implement the 8-Hour Ozone National Ambient Air 

Quality Standard—Phase 2, 70 FR 71612 (November 29, 2005). 

 

1 By December 14, 2012, California must submit a revision to the State Implementation Plan (SIP) for the 

SJV that provides for, among other things, implementation of all RACM (including RACT) necessary for 

expeditious attainment of the 2006 24-hour PM2.5 standard in the SJV. See 74 FR 58689 (Nov. 13, 2009) 

(final air quality designations for 2006 24-hour PM2.5 NAAQS, effective December 14, 2009). In separate 

rulemakings, EPA will take action on the State’s RACM demonstration for this standard based on an 

evaluation of the control measures submitted as a whole and their overall potential to advance the 

applicable attainment date in the SJV. 
Page 4 of 15

• Determination of Reasonably Available Control Technology and Best Available 

Retrofit Control Technology for Industrial, Institutional, and Commercial Boilers, 

Steam Generators, and Process Heaters, CARB (July 18, 1991). 

http://www.arb.ca.gov/ractbarc/boilers.pdf

• Alternative Control Techniques Document-- NOx Emissions from 

Industrial/Commercial/Institutional (ICI) Boilers, US EPA 453/R-94-022 (March 

1994). http://www.epa.gov/ttn/catc/dir1/icboiler.pdf

• Alternative Control Techniques Document-- NOx Emissions from Utility Boilers, 

US EPA 452/R-93-008 (March 1994). 

http://www.epa.gov/ttn/catc/dir1/utboiler.pdf

• State Implementation Plans (SIPs): Policy Regarding Excess Emissions During 

Malfunctions, Startup and Shutdown from Steven A. Herman, Assistant 

Administrator for Enforcement and Compliance Assurance, and Robert 

Perciasepe, Assistant Administrator for Air and Radiation, September 20, 1999. 

Evaluation of Rule Stringency 

As noted above, submitted Rule 4352 must fulfill RACT requirements for NOx. See 

CAA § 182(b)(2) and (f); 40 CFR 51.912(a). On October 1, 2010 (75 FR 60623), we 

finalized a limited approval, limited disapproval of a previous version of Rule 4352 

because the SJVUAPCD had not adequately demonstrated that Rule 4352 satisfied the 

RACT requirement for this source category. In response, SJVUAPCD lowered all of the 

NOx emission limits in the rule and provided documentation to support its analyses. We 

evaluate below the NOx emission limits in the revised Rule 4352 for each fuel type. 

Municipal Solid Waste

The revised rule establishes a NOx emission limit of 165 ppm at 12% CO2 for sources 

fired with MSW, based on a block 24-hour average, effective January 1, 2013. See Rule 

4352, sections 5.1 and 5.2. There is currently only one facility in the SJV that is subject 

to the MSW limits of Rule 4352. This facility has two 400 ton/day municipal solid waste 

mass burn waterwall combustors equipped with ammonia injection (selective noncatalytic reduction, SNCR). See Proposed Title V Operating Permit, Covanta Stanislaus 

Inc., revised February 15, 2012. 

As part of our evaluation of Rule 4352, we reviewed the ACT Document for NOx 

emissions from Industrial/Commercial/Institutional Boilers (1994 ACT), which identifies 

NOx emission levels for MSW fueled boilers ranging from 44 ppm to 210 ppm at 3% O2, 

based on the use of SNCR controls with ammonia or urea injection. See 1994 ACT at 

Appendix B, pg. B–21. These limits are approximately equal to 35 to 167 ppm at 12% 

CO2

2

. In addition to reviewing the 1994 ACT, we obtained information about NOx

emission limits in permits for MSW-fueled boilers from the RACT/BACT/LAER 

Clearinghouse (RBLC, http://cfpub.epa.gov/RBLC/). We searched the RBLC for permits 

dated between 2002 and 2012 with process utility code 21.400 (Municipal Waste 

Combustion). The NOx emission limits in these permits range from 45 ppm (RBLC ID = 

 

2 Using equations available in EPA Method 3B along with F Factors obtained from Method 19, we 

calculated the O2 that should be obtained during combustion if there is 12% CO2 in the flue gas and 

corrected the NO2 values obtained from the ACT to this calculated value of O2 in the flue gas. 
Page 5 of 15

FL-0324) to 350 ppm (RBLC ID = NJ-0060), both corrected to 7% O2. These limits 

correspond to a range of approximately 47 to 332 ppm at 12% CO2. Table 1 below 

contains more information about these permits available in the RBLC3. 

Table 1 

RBLC ID Year 

issued 

Facility details Approximate 

limit (ppm at 

12% CO2)

4 

Averaging 

period 

FL-0324 2010 Peak heat rating for each unit of 458.3 

MMBtu/hour; Fuel throughput of 1000 

tons/day for each unit; selective 

catalytic reduction (SCR) as a control 

device. 

47

43

24 hour 

12 month 

VA-0297 2005 Two units with fuel throughput of 100 

tons/day each; flue gas recirculation 

(FGR), low NOx burners (LNB) and 

good combustion practices as emission 

control techniques. 

237 Not 

provided 

FL-0258 2003 Heat rating of 291.5 MMBtu/hour; Fuel 

capacity of 660 tons/day; SNCR as a 

control device. 

142 

104 

24 hour 

12 month 

NJ-0060 2003 Fuel throughput of 209875 tons/year 

for two units combined; SNCR as a 

control device. 

332 1 hour 

VA-0277 

(now 

VA0297) 

2003 Two units with fuel throughput of 100 

tons/day each. 

1525 Not 

provided 

As shown in Table 1, NOx emission levels from units equipped with SNCR (similar 

technology to what the facility in San Joaquin Valley has) range from 104 ppm at 12% 

CO2 averaged over 12 months to 332 ppm at 12% CO2 averaged over 1 hour. The only 

emission limit averaged over 24 hours (similar to Rule 4352’s averaging period) for a 

unit equipped with SNCR is 142 ppm, which is slightly lower than the limit in Rule 4352. 

The District’s staff report for Rule 4352 states that although lower NOx emissions could 

possibly be achieved with the existing technology by increasing the amount of ammonia 

injected, affected sources had expressed concern that this would lead to exceedances of 

other permit conditions such as ammonia slip, visible emissions (i.e. detached plume) and 

condensable particulate matter. See SJVUAPCD, Final Staff Report, “Revised Proposed 

Amendments to Rule 4352 (Solid Fuel Fired Boilers, Steam Generators and Process 

 

3 We have only identified entries that provided NOx limits in ppm, for ease of comparison with the limits in 

Rule 4352. 

4 We have converted permit limits at 3% O2 into approximate limits at 12% CO2in accordance with the 

calculation described in footnote 2 above. 

5 This permit limit is no longer effective. It was modified in 2005 to 250 ppm at 7% O2 (237 ppm at 12% 

CO2) and is now covered under RBLC ID VA-0297. See email from Janardan Pandey to Idalia Perez 

(attached). 
Page 6 of 15

Heaters),” December 15, 2011 (Final Staff Report) at p. 10. A detached plume is a visible 

plume that forms downstream of the stack tip and is caused by compounds which are in 

the gas phase at the exhaust temperature, but become solids or liquids as the exhaust 

gases cool to atmospheric temperatures. Excess ammonia emissions can cause detached 

plumes when it reacts with other gases in the flue gas. Although the 1994 ACT shows 

that a number of similar units with SNCR have achieved emission levels lower than 165 

ppm at 12% CO2, it is not clear that units operating within the SJV can achieve this 

emission level using SNCR given the possibility that increasing ammonia injection could 

lead to exceedances of other permit limits. 

The District states that achieving emission limits lower than the current rule limit without 

causing increases of other emissions would require installation of SCR equipment, 

similar to the Florida facility found in the RBLC (RBLC ID = FL-0324). See Final Staff 

Report at p. 6. The District obtained cost data for SCR equipment from a preconstruction 

approval issued by the Florida Department of Environmental Protection and estimated 

that the cost of retrofitting a 350 MMBtu/hour MSW-fired facility operating at a 100% 

capacity factor year-round with SCR would be $30,806/ton of NOx reduction, which 

exceeds the District’s cost-effectiveness threshold for BACT. The District therefore 

concluded that SCR retrofits are not reasonably available for existing MSW-fired boilers 

in the SJV at this time. See Final Staff Report at p. 10. 

In 2009, the one existing MSW facility in the San Joaquin Valley, which is equipped with 

SNCR, tested at an average NOx emission level of 146 ppm and 143 ppm at 12% CO2. 

[See attached tests results] A NOx emission limit of 165 ppm is stringent enough to 

ensure that the source will be obligated to continually operate its emission control system 

while leaving the facility a small compliance buffer to account for occasional short-term 

variabilities inherent in its process. 

Based on this information, we propose to approve the District’s NOx limit of 165 ppm at 

12% CO2 as satisfying NOx RACT requirements for MSW combustors in the San 

Joaquin Valley area for the 1-hour and 1997 8-hour ozone NAAQS. 

Biomass

The revised rule establishes a NOx emission limit of 90 ppm at 3% O2 averaged over 24 

hours for units fired with biomass, effective January 1, 2013. See Rule 4352, sections 5.1 

and 5.2. There are several facilities in the San Joaquin Valley that use biomass as fuel, 

including facilities that have circulating and bubbling fluidized bed boilers as well as 

stoker boilers. 

As part of our evaluation of the NOx emission limit for biomass-fueled boilers in Rule 

4352, we reviewed the 1994 ACT which identifies NOx emission levels for this category 

ranging from 24 ppm to 187 ppm at 3% O2, based on the use of SNCR controls with 

ammonia or urea injection. See 1994 ACT at Appendix B, pp. B20-B21. This wide range 

of emission levels reflects the broad technical diversity among the types of boilers that 

fire biomass as fuel, including stokers, circulating fluidized bed boilers and bubbling 

fluidized bed boilers. It also reflects the variety of fuels that the term “biomass” covers, 
Page 7 of 15

including various kinds of plant materials, wood materials and agricultural wastes. In 

addition to reviewing the 1994 ACT, we obtained information about NOx emission limits 

in permits for biomass-fueled boilers from the RBLC. We searched the RBLC for permits 

dated between 2008 and 2012 with process utility code 11.120 (Utility and Large 

Industrial Size Boilers/Furnaces (>250 MMBtu/hr), Biomass). The NOx emission limits 

in these permits range from 0.06 lb/MMBtu on a 24 block average for a unit with 

regenerative SCR (RSCR) (RBLC ID = CT-0156, issued 2010) to 0.3 lb/MMBtu over a 3 

hour average for a unit with low NOx burners (RBLC ID = AL-0250, issued 2010). 

These limits correspond to a range of approximately 47 to 233 ppm at 3% O2

6

. For units 

with SNCR, the limits found in the entries for the above search were approximately 

between 78 and 116 ppm at 3% O2 over a 30 day rolling average (RBLC ID = GA-0141 

issued 2010 and TX-0553 issued 2010). Table 2 below contains more information about 

these permits available in the RBLC. 

Table 2 

RBLC ID Year 

issued 

Facility details Approximate 

limit (ppm at 

3% O2)

7 

Averaging 

period 

GA-0141 2010 Bubbling fluidized bed boiler (BFBB); 

Heat rating of 1399 MMBtu/hour; 

SNCR as a control device. 

78 30 day 

NH-0018 2010 Heat rating of 1013 MMBtu/hour; SCR 

on the cold side of the bag house with 

ammonia injection as a control device. 

47 30 day 

CT-0156 2010 Stoker boiler; Heat rating of 600 

MMBtu/hour; RSCR as a control 

device 

47 24 hour 

AL-0250 2010 Heat rating of 435 MMBtu/hour; LNB 

as a control device. 

233 3 hour 

TX-0553 2010 Fuel throughput of 730 tons/hour; 

SNCR as a control device. 

116 30 day 

TX-0555 2009 Stoking grate boiler; Heat rating of 

692.6 MMBtu/hour; SCR as a control 

device. 

58 30 day 

NH-0016 2009 Fuel throughput of 40.75 tons/hour; 

SCR with staged combustion as control 

devices. 

50 30 day 

NH-0015 2009 Stoker boiler; Heat rating of 305 

MMBtu/hour; SCR as a control device. 

50 30 day 

GA-0132 2009 BFBB; Heat rating of 1529 

MMBtu/hour; 

78 30 day 

 

6 Using a conversion factor found in Table 19-1 and an F factor found in Table 19-2 of EPA Method 19, we 

converted the NOx emission levels expressed in lbs/MMBtu in these permits into approximate NOx 

emission levels in parts per million (ppm). 

7We have converted permit limits at 3% O2 into approximate limits at 12% CO2 in accordance with the 

calculation described in footnote 2 above. 
Page 8 of 15

As shown in Table 2, the lower limits found in the RBLC are for units equipped with 

SCR while the higher limits are for units equipped with SNCR and LNB. Also, although 

many of the limits found in the RBLC are lower than the limit in Rule 4352 for biomassfueled units, the averaging time for most of these limits is significantly longer than the 

averaging time in Rule 4352. The longer averaging time allows for lower limits by 

allowing facilities to average out short-term emission spikes that are common in biomassfueled facilities. For this reason, lower emission limits with a longer averaging period are 

not necessarily more stringent than a higher limit with a shorter averaging period. 

We have also reviewed rules from other air districts in California that regulate biomass 

boilers. Yolo-Solano Air Quality Management District’s Biomass Boiler Rule (Rule 2.43, 

adopted November 10, 2010) has a NOx emission limit for biomass boilers of 90 ppm at 

3% O2 on a 24-hour block average, the same as Rule 4352. EPA recently proposed to 

fully approve Yolo-Solano’s Rule 2.43 as satisfying RACT. See 77 FR 11990 (February 

28, 2012). Sacramento Metro Air Quality Management District’s (SMAQMD) Rule 411 

(adopted August 23, 2007) has a NOx limit of 70 ppm at 12% CO2, which is 

approximately 100 ppm at 3% O2. We are not aware of other RACT rules with limits 

lower than 90 ppm averaged over 24 hours for this source category. 

The District states that achieving emission limits lower than the current rule limit would 

require installation of SCR equipment. See Final Staff Report at p. 13. It also states that 

SCR for biomass boilers is usually installed at new installations, not during retrofits. 

According to the District, there is one facility with a smaller sized boiler in the San 

Joaquin Valley that was retrofitted with SCR for research purposes, but this retrofit did 

not lead to any reduction in permitted emissions compared to operation of SNCR. See id. 

The District obtained cost data for an SCR system from a preconstruction approval issued 

by the Florida Department of Environmental Protection for a MSW facility and estimated 

that the cost of retrofitting a 700 MMBtu/hour biomass-fired facility operating at a 100% 

capacity factor year-round with SCR would be $54,342/ton of NOx reduction, which 

exceeds the District’s cost-effectiveness threshold for BACT. The District therefore 

concluded that SCR retrofits are not reasonably available for existing biomass-fired 

boilers in the SJV. See Final Staff Report at pp. 13-15. The District also provided 

information on retrofitting biomass boilers with RSCR, a more likely choice than SCR, 

and stated that the cost-effectives of this retrofit would be $48,000/ton of NOx. 

The limit for units fired with biomass in Rule 4352 is consistent with the mid to low end 

of the range found in the 1994 ACT and is within the range of recent permit limits found 

in the RBLC, most of which have much longer averaging periods. Although the ACT 

shows emission values lower than the emission limit in Rule 4352 for units with an 

SNCR, the District’s assertion that lower emissions generally cannot be achieved without 

installing and operating an SCR system appears to be reasonable, especially given that 

many of the lower limits found in the RBLC are for units equipped with SCR and that the 

higher limits are for units equipped with SNCR. Based on this information, we propose to 

approve the District’s NOx limit of 90 ppm at 3% O2 averaged over 24 hours as 
Page 9 of 15

satisfying RACT for biomass-fueled boilers in the San Joaquin Valley area for the 1-hour 

and 1997 8-hour ozone NAAQS. 

Other

The revised rule establishes a NOx emission limit of 65 ppm at 3% O2 for units fired with 

all other solid fuels, which may include coal, petroleum coke and tire-derived fuel (TDF). 

As part of our evaluation of the NOx emission limit in Rule 4352 for boilers fueled with 

other solid fuels, we reviewed the 1994 ACT which identifies NOx emission levels for 

units fueled with coal ranging from 21 ppm to 300 ppm at 3% O2, based on the use of 

SNCR controls with ammonia or urea injection. See 1994 ACT at Appendix B, page B19. 

In addition to reviewing the 1994 ACT, we obtained information about NOx emission 

limits in permits for boilers fueled with coal and other solid fuels from the RBLC. We 

searched the RBLC for permits dated between 2008 and 2012 with process utility code 

11.110 (Utility and Large Industrial Size Boilers/Furnaces (>250 MMBtu/hr), Coal) and 

process utility code 11.190 (Utility and Large Industrial Size Boilers/Furnaces (>250 

MMBtu/hr), Other Solid Fuel & Solid Fuel Mixtures). Table 3 below contains more 

information about these permits available in the RBLC8. 

Table 3 

RBLC ID Year 

issued 

Facility details Approximate 

limit (ppm at 

3% O2)

9 

Averaging 

period 

ND-0026 2012 Unit 1: Heat rating of 3200 

MMBtu/hour; fueled on lignite; SNCR 

and over fire air (OFA) as control 

devices. 

Unit 2: Heat rating of 6300 

MMBtu/hour; fueled on lignite; SNCR 

and OFA as control device. 

262 

255 

30 day 

30 day 

TX-0599 2011 Heat rating of 3080 MMBtu/hour; 

CFB boiler; fueled on pet coke; SNCR 

as a control device. 

50 

71 

30 day 

1 hour 

TX-0585 2010 Heat rating of 8307 MMBtu/hour; 

fueled on coal; SCR as a control 

device. 

36 

43 

12 month 

30 day 

TX-0577 2010 Heat rating of 3300 MMBtu/hour at 

each of 4 CFB boilers; fueled on coal 

and pet coke; SNCR as a control 

device. 

50 

71 

30 day 

1 hour 

TX-0554 2010 Heat rating of 6670 MMBtu/hour; 44 30 day 

 

8 We have identified only entries providing information that we could convert into NOx emission levels in 

ppm, for ease of comparison with the limits in Rule 4352. 

9We have converted NOx permit limits expressed in lbs/MMBtu into approximate limits at 12% CO2in 

accordance with the calculation described in footnote 2 above. 
Page 10 of 15

fueled on Powder River Basin (PRB) 

coal; LNB, OFA and SCR as control 

devices. 

37 12 month 

KY-0100 2010 Heat rating of 3000 MMBtu/hour; 

CFB boiler; fueled on coal; SNCR as a 

control device. 50 30 day 

TX-0557 2010 Heat rating of 9061 MMBtu/hour; 

fueled on PRB coal, Texas lignite and 

up to 20% petroleum coke; LNB as a 

control device. 

182 30 day 

TX-0556 2010 Heat rating of 3630 MMBtu/hour; 

tangentially arranged boiler; LNB and 

OFA as control devices. 

284 Not 

provided 

MI-0389 2009 Heat rating of 8190 MMBtu/hour; 

fueled on PRB coal or a 50/50 blend; 

LNB, OFA and SCR as control 

devices. 

37 30 day 

OH-0310 2009 Heat rating of 5191 MMBtu/hour at 

each of two boilers; fueled on coal; 

SCR as a control device. 

71 24 hour 

OH-0325 2009 Heat rating of 535 MMBtu/hour; 

fueled on refuse derived fuel and 

MSW; RSCR as a control device. 

58 24 hour 

NE-0049 2009 Heat rating of 6300 MMBtu/hour; 

fueled on PRR coal; LNB and OFA as 

control devices. 

169 30 day 

AR-0094 2008 Heat rating of 6000 MMBtu/hour; 

fueled on PRB coal; SCR as a control 

device. 

49 

37 

24 hour 

12 month 

VA-0311 2008 Heat rating of 3132 MMBtu/hour at 

each of two CFB boilers; fueled on 

coal and coal refuse; SNCR as a 

control device. 

50 30 day 

VA-0309 2008 Heat rating of 87 MMBtu/hour; fueled 

on coal; good combustion practices as 

emission controls. 

426 Not 

provided 

MO-0077 2008 Heat rating of 3,762,420 tons/year; 

fueled on coal; LNB, OFA and SCR 

as control devices. 

46 

36 

30 day 

12 month 

LA-0223 2008 Heat rating of 2330 MMBtu/hour; 

CFB boiler; fueled on pet coke, coal 

and biomass; SNCR as a control 

device. 

213 1 hour 

As shown in Table 3, the NOx emission limits in these permits range from approximately 

36 to 426 ppm at 3% O2 with a wide range of averaging periods. For permit limits with 
Page 11 of 15

averaging periods of 24 hours, similar to Rule 4352, the emission limits range from 49 to 

71 ppm at 3% O2, all for units with SCR as a control device. Rule 4352’s limit of 65 ppm 

at 3% O2 falls within this range. 

The District states that achieving NOx emission levels lower than the current rule limit 

would require installation of additional controls such as SCR. See Final Staff Report at p. 

16. This statement is consistent with the RBLC information discussed above. The District 

obtained cost data for an SCR system from a preconstruction approval issued by the 

Florida Department of Environmental Protection for a MSW facility and estimated that 

the cost of retrofitting a 700 MMBtu/hour unit burning “other” solid fuels and operating 

at a 100% capacity factor year-round with SCR would be $59,769/ton of NOx reduction, 

which exceeds the District’s cost-effectiveness threshold for BACT. The District 

therefore concluded that SCR retrofits are not reasonably available for existing units 

burning “other” solid fuels in the SJV. See Final Staff Report at p. 18. 

The NOx emission limit for units fired with other solid fuels in Rule 4352 is consistent 

with the mid to low end of range found in the 1994 ACT for coal fired units with SNCR 

and is within the range of recent permit limits with comparable averaging periods found 

in the RBLC. Although the ACT shows emission values lower than the emission limit in 

Rule 4352 for units with an SNCR, the District’s assertion that lower emissions generally 

cannot be achieved without installing and operating an SCR system appears to be 

reasonable, especially given that many of the lower limits found in the RBLC are for 

units equipped with SCR. Based on this information, we propose to approve the District’s 

NOx limit of 65 ppm at 3% O2 averaged over 24 hours as satisfying RACT for units 

fueled with “other” solid fuels in the San Joaquin Valley area for the 1-hour and 1997 8-

hour ozone NAAQS. 

Evaluation of Enforceability and SIP Revision Criteria 

Recordkeeping and other compliance provisions in the revised version of Rule 4352 

ensure that the requirements are adequately enforceable. 

The submitted rule establishes more stringent NOx emission limits than the version of the 

rule that is currently in the SIP, thus strengthening the requirements of the SIP. 

Therefore, we propose to determine that our approval of the submittal would comply with 

CAA sections 110(l) and 193 because (1) the proposed SIP revision would not interfere 

with the on-going process for ensuring that requirements for RFP and attainment of the 

NAAQS are met, and (2) the NOx emission limits in the submitted rule are more 

stringent than the existing SIP-approved control requirements that they would replace. 

Suggested Rule Improvements 

Given the severity of PM2.5 pollution levels in the SJV, EPA recommends that the 

SJVUAPCD consider the economic and technical feasibility of additional control 

requirements for SOx and direct PM2.5 emissions (including the condensable fraction of 

PM2.5) from this source category. We recommend that the District revise Rule 4352 at its 

earliest opportunity to include such additional control requirements if such controls are 

reasonably available and would expedite attainment of the PM2.5 NAAQS in the SJV. 
Page 12 of 15

Given the severity of ozone pollution levels in the SJV, we also recommend that the 

District continue to evaluate additional control options for NOx that would expedite 

attainment of the ozone NAAQS. 

Recommendation 

EPA staff recommends a full approval of SJVUAPCD Rule 4352 under CAA section 

110(k)(3). 

Other References 

1. Proposed Title V Operating Permit, Covanta Stanislaus Inc., revised February 15, 

2012 

2. RBLC permit information for MSW (FL-0324, VA-0297, FL-0258, NJ-0060, 

VA-0277) 

3. RBLC permit information for biomass (GA-0141, NH-0018, CT-0156, AL-0250, 

TX-0553, TX-0555, NH-0016, NH-0015, GA-0132) 

4. RBLC permit information for other (ND-0026, TX-0599, TX-0585, TX-0577, 

TX-0554, KY-0100, TX-0557, TX-0556, MI-0389, OH-0310, OH-0325, NE0049, AR-0094, VA-0311, VA-0309, MO-0077, LA-0223) 

5. October 2009 TSD proposed limited approval, limited disapproval of Rule 4352 

6. SIP-approved Rule 4352 

7. Submitted Rule 4352 

8. Staff Report for Rule 4352 

9. EPA Method 19 

 
Page 13 of 15

Appendix 1: Sample calculations 

Table 19-2 from Method 19, F Factors for various fuels 

To convert from values corrected to 3% O2 to values corrected to 12% CO2 

Step 1 – Calculate the O2 that should be obtained during combustion in the flue if there is 

12% CO2 in the flue gas 

Equation 3B-5 from EPA Method 3B: Fo = 0.209 Fd / Fc 

Equation 3B-2 from EPA Method 3B: Fo = (20.9 – %O2) / %CO2 

Example for Municipal solid waste (using Table 19-2 from Method 19)

Fo = 0.209 * 2.5 x 10-7 / 0.488 x 10-7= 1.10 

% O2 ≈ 20.9 – (1.10 * 12) ≈ 7.69 

Step 2 – Correct the NO2 values from 3% O2 to7.69% O2 found in step 1. 

Example for 44 ppm at 3% O2

NO2 at 12% CO2 ≈ 44 ppm * 14.2% / (20.9% - 3%) ≈ 35 

To convert from values of lb/MMBtu to ppm corrected to 3% O2 

Values from Table 19-1 from Method 19 used in calculations: 

From To Multiply by 

ppm NOx lb/scf 1.194 x 10-7

Step 1 – Calculate the lb/scf from the F factor 
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Example for 0.06 lb/MMBtu of wood

lb/scf ≈ 0.06 / 9,240 ≈ 6.493 x 10-6

Step 2 – Calculate ppm at 0% O2 using conversion factor from Table 19-1 

Example for 0.06 lb/MMBtu of wood

ppm ≈ 6.493 x 10-6 /1.194 x 10-7 ≈ 54 

Step 2 – Correct ppm to 3% O2 

Example for 0.06 lb/MMBtu of wood

ppm ≈ 54 * (20.9-3)/20.9 ≈ 47 

 
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Appendix 2: Covanta Stanislaus source test