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Federal Register / Vol. 86, No. 53 / Monday, March 22, 2021 / Rules and Regulations
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day rolling average SO2 and NOX limits utilizing a continuous emissions monitor CEMS subject to 40 CFR part 60. Permit condition 38 identifies the source category type as being a boiler and the pollutants to be monitored by CEMS as SO2 and NOX. It is clear from the pollutant, fuel type, and the nature of the emission unit which of the tests would apply under 40 CFR 60 for demonstrating compliance. That is sufficient information to locate the performance specifications and quality assurance procedures for Power Boiler No. 2 to determine how to utilize CEMS
to determine compliance with the SO2
and NOX limits of the Arkansas Regional Haze Phase III SIP revision.
The State is being all-inclusive when referring to Part 60 to include all of the general provisions in Subpart A related to CEMS, such as 40 CFR 60.8 for performance tests, 40 CFR 60.13
pertaining to monitoring requirements, and Appendix B to Part 60, which includes performance specifications for CEMS. In addition, these permit conditions also implement APCEC Rule 19.703Continuous Emission Monitoring,78 which is already part of the approved SIP, and applies to this source.79 Specific condition 54 of the permit provides additional information regarding CEMS requirements for Power Boiler No 2. Specifically, it says, The permittee shall install, calibrate, maintain and operate continuous emissions monitoring systems for measuring SO2 emissions, NOX
78 Under APCEC Rule 19.703Continuous Emission Monitoring, any stationary source subject to this regulation shall, as required by federal law and upon request of the Department: A Install, calibrate, operate, and maintain equipment to continuously monitor or determine federally regulated air pollutant emissions in accordance with applicable performance specifications in 40
CFR part 60 Appendix B as of the effective date of the federal final rule published by EPA in the Federal Register on February 27, 2014 79 FR
11271, and quality assurance procedures in 40 CFR
part 60 Appendix F as of the effective date of the federal final rule published by EPA in the Federal Register on February 27, 2014 79 FR 11274, and other methods and conditions that the Department, with the concurrence of the EPA, shall prescribe.
Any source listed in a category in 40 CFR part 51
Appendix P as of the effective date of the federal final rule published by EPA in the Federal Register on November 7, 1986 51 FR 40675, or in 40 CFR
part 60 as of August 30, 1992, shall adhere to all continuous emissions monitoring or alternative continuous emission monitoring requirements stated therein, if applicable. B Report the data collected by the monitoring equipment to the Department at such intervals and on such forms as the Department shall prescribe, in accordance with 40 CFR part 51, Appendix P, Section 4.0 Minimum Data Requirements as of the effective date of the federal final rule published by EPA in the Federal Register on November 7, 1986 51 FR 40675, and any other applicable reporting requirements promulgated by the EPA.
79 See 52.170c table for EPA-approved regulations in the Arkansas SIP.

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emissions, and either oxygen or carbon dioxide. The CEMS shall have readouts which demonstrate compliance with any of the applicable limits for the pollutant in question. The permittee shall comply with the DEQ CEMS
conditions found in Appendix B. Reg.
19.703, 40 CFR 52, Subpart E, and Ark.
Code Ann. 84203 as referenced by Ark. Code Ann. 84304 and 84
311. Appendix B sections II through IV of the permit lay out specific guidelines for CEMS operating conditions.
The commenter also states that permit condition 40 fails to identify the specific AP42 emission factors. Condition 40
refers to the applicable natural gas AP
42 emission factors and provides an appropriate description because the applicable emission factors are based on the nature of the emissions unit, fuel, and pollutants in question. As explained in the proposed approval,80 if Power Boiler No. 2 switches to natural gas combustion, the applicable natural gas AP42 emission factors of 0.6 lb SO2/MMscf, 280 lb NOX/MMscf, and 7.6
lb PM10/MMscf in conjunction with natural gas fuel usage records shall be used to demonstrate compliance with the BART emission limits.81 Therefore, the boiler will operate under CEMs, and these AP42 emissions factors would only be used for estimation of emissions if Power Boiler No. 2 burns natural gas.
We note, just as we did in the FIP, for which these provisions are replacing,82 83 that burning only natural 80 See
85 FR 14847, 14862.
AP 42, Fifth Edition Compilation of Air Pollutant Emissions Factors, Volume 1: Stationary Point and Area Sources, section 1.4, Tables 1.41
and 2 pertaining to natural gas combustion.
82 See 40 CFR 52.173c8iv and v. However, the FIP regulations required burning only pipeline quality natural gas, and no such requirement to burn only pipeline quality natural gas can be located in the permit or the SIP for this unit.
Nonetheless, there is no indication nor has the commenter supplied any such information that burning other types of natural gas would result in SO2 emissions that would even approach the BART
alternative emission limit.
83 Table 1.42 from Fifth Edition Compilation of Air Pollutant Emissions Factors, Volume 1:
Stationary Point and Area Sources, section 1.4
indicates that the AP42 factor contemplates varying amounts of sulfur and the potential need to adjust the emission factor. The AP42 factor for sulfur from natural gas 0.6 lb/106 scf is based on 100% conversion of fuel sulfur to SO2. It assumes a sulfur content for natural gas of 2,000 grains/106
scf. The SO2 emission factor in this table can be converted to other natural gas sulfur contents by multiplying the SO2 emission factor by the ratio of the site-specific sulfur content grains/106 scf to 2,000 grains/106 scf. To convert the emission factors in the AP42 tables on a volume basis lb/106 scf to an energy basis lb/MMBtu divide by a heating value of 1,020 MMBtu/106 scf. Then, multiply the result by the heat input capacity of the boiler MMBtu/hr to get a mass flow rate lb/hr.
Accordingly, an AP factor of 0.6 lb SO2/MMscf 81 See
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gas would very likely be sufficient in itself to demonstrate that the boiler is complying with the SO2 emission limit.
SO2 emissions from combustion of natural gas are inherently very low and are virtually eliminated during the combustion process. Any SO2 emissions will be in trace amounts well below the BART alternative emission limit so there should be no concern that the alternative limit for SO2 will be met.
NOX and PM10 emissions are also expected to be lower than the BART
alternative emission limit for natural gas combustion.84 85 Using the most conservative NOX, SO2, and PM10 AP
42 factors highest factor for boiler combustion indicates that the BART
alternative emission limits will be met even when firing natural gas at full capacity. Based on this information, any ambiguity in the use of AP42 factors for compliance using only natural gas is not of concern because of the characteristically lower emissions during natural gas combustion. When natural gas is used, the limits in the BART alternative demonstration will be met. DEQ has the State authority to enforce these emission factors to document compliance and EPA will have federal authority once this approval takes effect.
The State made clear in its SIP
submittal that the BART alternative SIP
requirements for this source would be implemented in conjunction with preexisting SIP requirements for monitoring, reporting, and multiplied by Power Boiler No. 2 maximum heat input of 820 MMBtu/hr would result in 0.5 lb/hr SO2, showing that the sulfur emissions would be very low and almost negligible. It is also more conservative than the FIP pipeline quality natural gas would result in 1.2 lb/hr SO2 assuming pipeline natural gas contains 0.5 grains or less of total sulfur per 100 standard cubic feet. These results are well below the BART alternative limit for SO2 of 435 lb/hr.
84 From Table 1.41 of Fifth Edition Compilation of Air Pollutant Emissions Factors, Volume 1:
Stationary Point and Area Sources, section 1.4 we can also appropriately select the most conservative NOX emission factor based on the design heat input capacity for Power Boiler No. 2 of 820 MMBtu/hr.
From this, we can choose emission factors from the combustor type. The applicable AP42 emission factor 280 lb NOX/MMscf is consistent with what was used in the FIP for a large wall-fired boiler > 100 MMBtu/hr. This is the highest emission factor in the table for NOX and results in 225 lb/hr NOX
985 tpy NOX which can be calculated from the heat input capacity of the boiler 820 MMBtu/hr similarly as explained in previous footnote. The result is less than both the FIP NOX limit of 345
lb/hr 1,511 tpy and the BART alternative NOX rate of 293 lb/hr 1,283 tpy.
85 From Table 1.42 of Fifth Edition Compilation of Air Pollutant Emissions Factors, Volume 1:
Stationary Point and Area Sources, section 1.4 an AP factor of 7.6 lb PM10/MMscf represents total PM
and equates to 6.1 lb/hr PM applying a heat input capacity of 820 MMBtu/hr. This is less than the BART alternative rate of 81.6 lb/hr PM.

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