MEMORANDUM 

From: Christian Fellner 

To: Steam Generating Unit NSPS Docket (EPA-HQ-OAR-2005-0031) 

Date: December, 2010 

Subject: Redline of Proposed Amendments to the Boiler NSPS (40 CFR Part 60, Subparts 

D, Da, Db, & Dc). 

Introduction 

For references purposes, EPA prepared a redline of the proposed amendments against the 

existing regulatory text. The redline documents only include edited sections and are only 

intended to assist interested parties to understand the proposed amendments. The redline 

documents and are not intended to supersede the amendments included in the FR package. 
Subpart D—Standards of Performance for Fossil-Fuel-Fired Steam Generators for Which 

Construction Is Commenced After August 17, 1971 

§60.42 Standard for particulate matter (PM). 

(a) On and after the date on which the performance test required to be conducted by §60.8 is 

completed, no owner or operator subject to the provisions of this subpart shall cause to be discharged 

into the atmosphere from any affected facility any gases that: 

(1) Contain PM in excess of 43 nanograms per joule (ng/J) heat input (0.10 lb/MMBtu) derived from 

fossil fuel or fossil fuel and wood residue. 

(2) Exhibit greater than 20 percent opacity except for one six-minute period per hour of not more than 

27 percent opacity. 

(b)(1) On or after December 28, 1979, no owner or operator shall cause to be discharged into the 

atmosphere from the Southwestern Public Service Company's Harrington Station #1, in Amarillo, TX, 

any gases which exhibit greater than 35 percent opacity, except that a maximum or 42 percent opacity 

shall be permitted for not more than 6 minutes in any hour. 

(2) Interstate Power Company shall not cause to be discharged into the atmosphere from its Lansing 

Station Unit No. 4 in Lansing, IA, any gases which exhibit greater than 32 percent opacity, except that 

a maximum of 39 percent opacity shall be permitted for not more than six minutes in any hour. 

(c) As an alternate to meeting the requirements of paragraph (a) of this section, an owner or operator 

that elects to install, calibrate, maintain, and operate a continuous emissions monitoring systems 

(CEMS) for measuring PM emissions can petition the Administrator (in writing) to comply with 

§60.42Da(a) of subpart Da of this part. If the Administrator grants the petition, the source will from 

then on (unless the unit is modified or reconstructed in the future) have to comply with the 

requirements in §60.423Da(a) of subpart Da of this part. 

§60.45 Emissions and fuel monitoring. 

(a) Each owner or operator shall install, calibrate, maintain, and operate continuous opacity monitoring 

system (COMS) for measuring opacity and a CEMS for measuring SO2emissions, NOXemissions, and 

either oxygen (O2) or carbon dioxide (CO2) except as provided in paragraph (b) of this section. 

(b) Certain of the CEMS requirements under paragraph (a) of this section do not apply to owners or 

operators under the following conditions: 

(1) For a fossil-fuel-fired steam generator that burns only gaseous or liquid fossil fuel (excluding 

residual oil) with potential SO2emissions rates of 26 ng/J (0.060 lb/MMBtu) or less and that does not 

use post-combustion technology to reduce emissions of SO2or PM, CEMS for measuring the opacity of 

emissions and SO2 emissions are not required if the owner or operator monitors SO2emissions by fuel 

sampling and analysis or fuel receipts. 

(2) For a fossil-fuel-fired steam generator that does not use a flue gas desulfurization device, a CEMS 

for measuring SO2emissions is not required if the owner or operator monitors SO2emissions by fuel 

sampling and analysis. 

Comment [CF1]: Typo error in earlier

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(3) Notwithstanding §60.13(b), installation of a CEMS for NOXmay be delayed until after the initial 

performance tests under §60.8 have been conducted. If the owner or operator demonstrates during the 

performance test that emissions of NOXare less than 70 percent of the applicable standards in §60.44, a 

CEMS for measuring NOXemissions is not required. If the initial performance test results show that 

NOXemissions are greater than 70 percent of the applicable standard, the owner or operator shall install 

a CEMS for NOXwithin one year after the date of the initial performance tests under §60.8 and comply 

with all other applicable monitoring requirements under this part. 

(4) If an owner or operator does not install any CEMS for sulfur oxides and NOX, as provided under 

paragraphs (b)(1) and (b)(3) or paragraphs (b)(2) and (b)(3) of this section a CEMS for measuring 

either O2or CO2is not required. 

(5) An owner or operator may petition the Administrator (in writing) to install a PM CEMS as an 

alternative to the CEMS for monitoring opacity emissions. 

(6) A CEMS for measuring the opacity of emissions is not required for a fossil fuel-fired steam 

generator that does not use post-combustion technology (except a wet scrubber) for reducing PM, SO2, 

or carbon monoxide (CO) emissions, burns only gaseous fuels or fuel oils that contain less than or 

equal to 0.30 weight percent sulfur, and is operated such that emissions of CO to the atmosphere from 

the affected source are maintained at levels less than or equal to 0.15 lb/MMBtu on a boiler operating 

day average basis. Owners and operators of affected sources electing to comply with this paragraph 

must demonstrate compliance according to the procedures specified in paragraphs (b)(6)(i) through (iv) 

of this section. 

(i) You must monitor CO emissions using a CEMS according to the procedures specified in paragraphs 

(b)(6)(i)(A) through (D) of this section. 

(A) The CO CEMS must be installed, certified, maintained, and operated according to the provisions in 

§60.58b(i)(3) of subpart Eb of this part. 

(B) Each 1-hour CO emissions average is calculated using the data points generated by the CO CEMS 

expressed in parts per million by volume corrected to 3 percent oxygen (dry basis). 

(C) At a minimum, valid 1-hour CO emissions averages must be obtained for at least 90 percent of the 

operating hours on a 30-day rolling average basis. The 1-hour averages are calculated using the data 

points required in §60.13(h)(2). 

(D) Quarterly accuracy determinations and daily calibration drift tests for the CO CEMS must be 

performed in accordance with procedure 1 in appendix F of this part. 

(ii) You must calculate the 1-hour average CO emissions levels for each boiler operating day by 

multiplying the average hourly CO output concentration measured by the CO CEMS times the 

corresponding average hourly flue gas flow rate and divided by the corresponding average hourly heat 

input to the affected source. The 24-hour average CO emission level is determined by calculating the 

arithmetic average of the hourly CO emission levels computed for each boiler operating day. 

(iii) You must evaluate the preceding 24-hour average CO emission level each boiler operating day 

excluding periods of affected source startup, shutdown, or malfunction. If the 24-hour average CO 

emission level is greater than 0.15 lb/MMBtu, you must initiate investigation of the relevant equipment 

and control systems within 24 hours of the first discovery of the high emission incident and, take the 
appropriate corrective action as soon as practicable to adjust control settings or repair equipment to 

reduce the 24-hour average CO emission level to 0.15 lb/MMBtu or less. 

(iv) You must record the CO measurements and calculations performed according to paragraph (b)(6) 

of this section and any corrective actions taken. The record of corrective action taken must include the 

date and time during which the 24-hour average CO emission level was greater than 0.15 lb/MMBtu, 

and the date, time, and description of the corrective action. 

(7) TheAn owner or operator of an affected facility subject to an opacity standard under §60.42 and 

that elects to not install use a COMS because the affected facility burns only fuels as specified under 

paragraph (b)(1) of this section, monitors PM emissions as specified under paragraph (b)(5) of this 

section, or monitors CO emissions as specified under paragraph (b)(6) of this section, shall conduct a 

performance test using Method 9 of appendix A–4 of this part and the procedures in §60.11 to 

demonstrate compliance with the applicable limit in §60.42 by April 29, 2011 or within 45 days after 

stopping use of an existing COMS, whichever is later, and shall comply with either paragraphs

(b)(7)(i), (b)(7)(ii), or (b)(7)(iii) of this section. The observation period for Method 9 of appendix A-4 

of this part performance tests may be reduced from 3 hours to 60 minutes if all 6-minute averages are 

less than 10 percent and all individual 15-second observations are less than or equal to 20 percent 

during the initial 60 minutes of observationIf during the initial 60 minutes of observation all 6-minute 

averages are less than 10 percent and all individual 15-second observations are less than or equal to 20 

percent, the observation period may be reduced from 3 hours to 60 minutes. The permitting authority 

may exempt owners or operators of affected facilities burning only natural gas from the opacity 

monitoring requirements.

(i) Except as provided in paragraph (b)(7)(ii) or (b)(7)(iii) of this section, the owner or operator shall 

conduct subsequent Method 9 of appendix A–4 of this part performance tests using the procedures in 

paragraph (b)(7) of this section according to the applicable schedule in paragraphs (b)(7)(i)(A) through 

(b)(7)(i)(D) of this section, as determined by the most recent Method 9 of appendix A–4 of this part 

performance test results. 

(A) If no visible emissions are observed, a subsequent Method 9 of appendix A–4 of this part 

performance test must be completed within 12 calendar months from the date that the most recent 

performance test was conducted; 

(B) If visible emissions are observed but the maximum 6-minute average opacity is less than or equal 

to 5 percent, a subsequent Method 9 of appendix A–4 of this part performance test must be completed 

within 6 calendar months from the date that the most recent performance test was conducted; 

(C) If the maximum 6-minute average opacity is greater than 5 percent but less than or equal to 10 

percent, a subsequent Method 9 of appendix A–4 of this part performance test must be completed 

within 3 calendar months from the date that the most recent performance test was conducted; or 

(D) If the maximum 6-minute average opacity is greater than 10 percent, a subsequent Method 9 of 

appendix A–4 of this part performance test must be completed within 30 45 calendar days from the 

date that the most recent performance test was conducted. 

(ii) If the maximum 6-minute opacity is less than 10 percent during the most recent Method 9 of 

appendix A–4 of this part performance test, the owner or operator may, as an alternative to performing 

subsequent Method 9 of appendix A–4 of this part performance test, elect to perform subsequent 
monitoring using Method 22 of appendix A–7 of this part according to the procedures specified in 

paragraphs (b)(7)(ii)(A) and (B) of this section. 

(A) The owner or operator shall conduct 10 minute observations (during normal operation) each 

operating day the affected facility fires fuel for which an opacity standard is applicable using Method 

22 of appendix A–7 of this part and demonstrate that the sum of the occurrences of any visible 

emissions is not in excess of 5 percent of the observation period ( i.e. , 30 seconds per 10 minute 

period). If the sum of the occurrence of any visible emissions is greater than 30 seconds during the 

initial 10 minute observation, immediately conduct a 30 minute observation. If the sum of the 

occurrence of visible emissions is greater than 5 percent of the observation period ( i.e. , 90 seconds 

per 30 minute period), the owner or operator shall either document and adjust the operation of the 

facility and demonstrate within 24 hours that the sum of the occurrence of visible emissions is equal to 

or less than 5 percent during a 30 minute observation ( i.e. , 90 seconds) or conduct a new Method 9 of 

appendix A–4 of this part performance test using the procedures in paragraph (b)(7) of this section 

within 30 45 calendar days according to the requirements in §60.46(b)(3). 

(B) If no visible emissions are observed for 30 operating days during which an opacity standard is 

applicable, observations can be reduced to once every 7 operating days during which an opacity 

standard is applicable. If any visible emissions are observed, daily observations shall be resumed. 

(iii) If the maximum 6-minute opacity is less than 10 percent during the most recent Method 9 of 

appendix A–4 of this part performance test, the owner or operator may, as an alternative to performing 

subsequent Method 9 of appendix A–4 performance tests, elect to perform subsequent monitoring 

using a digital opacity compliance system according to a site-specific monitoring plan approved by the 

Administrator. The observations shall be similar, but not necessarily identical, to the requirements in 

paragraph (b)(7)(ii) of this section. For reference purposes in preparing the monitoring plan, see 

OAQPS “Determination of Visible Emission Opacity from Stationary Sources Using Computer-Based 

Photographic Analysis Systems.” This document is available from the U.S. Environmental Protection 

Agency (U.S. EPA); Office of Air Quality and Planning Standards; Sector Policies and Programs 

Division; Measurement Policy Group (D243–02), Research Triangle Park, NC 27711. This document 

is also available on the Technology Transfer Network (TTN) under Emission Measurement Center 

Preliminary Methods. 

(c) For performance evaluations under §60.13(c) and calibration checks under §60.13(d), the following 

procedures shall be used: 

(1) Methods 6, 7, and 3B of appendix A of this part, as applicable, shall be used for the performance 

evaluations of SO2and NOXcontinuous monitoring systems. Acceptable alternative methods for 

Methods 6, 7, and 3B of appendix A of this part are given in §60.46(d). 

(2) Sulfur dioxide or nitric oxide, as applicable, shall be used for preparing calibration gas mixtures 

under Performance Specification 2 of appendix B to this part. 

(3) For affected facilities burning fossil fuel(s), the span value for a continuous monitoring system 

measuring the opacity of emissions shall be 80, 90, or 100 percent. For a continuous monitoring 

system measuring sulfur oxides or NOXthe span value shall be determined using one of the following 

procedures: 

(i) Except as provided under paragraph (c)(3)(ii) of this section, SO2and NOXspan values shall be 

determined as follows: 
Fossil fuel 

In parts per million 

Span value for SO2 Span value for NOX

Gas (1) 500. 

Liquid 1,000 500. 

Solid 1,500 1,000. 

Combinations 1,000y + 1,500z 500 (x + y) + 1,000z. 

1

Not applicable. 

Where: 

x = Fraction of total heat input derived from gaseous fossil fuel; 

y = Fraction of total heat input derived from liquid fossil fuel; and 

z = Fraction of total heat input derived from solid fossil fuel. 

(ii) As an alternative to meeting the requirements of paragraph (c)(3)(i) of this section, the owner or 

operator of an affected facility may elect to use the SO2and NOXspan values determined according to 

sections 2.1.1 and 2.1.2 in appendix A to part 75 of this chapter. 

(4) All span values computed under paragraph (c)(3)(i) of this section for burning combinations of 

fossil fuels shall be rounded to the nearest 500 ppm. Span values that are computed under paragraph 

(c)(3)(ii) of this section shall be rounded off according to the applicable procedures in section 2 of 

appendix A to part 75 of this chapter. 

(5) For a fossil-fuel-fired steam generator that simultaneously burns fossil fuel and nonfossil fuel, the 

span value of all CEMS shall be subject to the Administrator's approval. 

(d) [Reserved] 

(e) For any CEMS installed under paragraph (a) of this section, the following conversion procedures 

shall be used to convert the continuous monitoring data into units of the applicable standards (ng/J, 

lb/MMBtu): 

(1) When a CEMS for measuring O2is selected, the measurement of the pollutant concentration and 

O2concentration shall each be on a consistent basis (wet or dry). Alternative procedures approved by 

the Administrator shall be used when measurements are on a wet basis. When measurements are on a 

dry basis, the following conversion procedure shall be used: 

Where E, C, F, and %O2are determined under paragraph (f) of this section. 

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(2) When a CEMS for measuring CO2is selected, the measurement of the pollutant concentration and 

CO2concentration shall each be on a consistent basis (wet or dry) and the following conversion 

procedure shall be used: 

Where E, C, Fcand %CO2are determined under paragraph (f) of this section. 

(f) The values used in the equations under paragraphs (e)(1) and (2) of this section are derived as 

follows: 

(1) E = pollutant emissions, ng/J (lb/MMBtu). 

(2) C = pollutant concentration, ng/dscm (lb/dscf), determined by multiplying the average 

concentration (ppm) for each one-hour period by 4.15 × 104

 M ng/dscm per ppm (2.59 × 10−9M lb/dscf 

per ppm) where M = pollutant molecular weight, g/g-mole (lb/lb-mole). M = 64.07 for SO2and 46.01 

for NOX. 

(3) %O2, %CO2= O2or CO2volume (expressed as percent), determined with equipment specified under 

paragraph (a) of this section. 

(4) F, Fc= a factor representing a ratio of the volume of dry flue gases generated to the calorific value 

of the fuel combusted (F), and a factor representing a ratio of the volume of CO2generated to the 

calorific value of the fuel combusted (Fc), respectively. Values of F and Fcare given as follows: 

(i) For anthracite coal as classified according to ASTM D388 (incorporated by reference, see §60.17), 

F = 2,723 × 10−17dscm/J (10,140 dscf/MMBtu) and Fc= 0.532 × 10−17scm CO2/J (1,980 scf 

CO2/MMBtu). 

(ii) For subbituminous and bituminous coal as classified according to ASTM D388 (incorporated by 

reference, see §60.17), F = 2.637 × 10−7

dscm/J (9,820 dscf/MMBtu) and Fc= 0.486 × 10−7scm CO2/J 

(1,810 scf CO2/MMBtu). 

(iii) For liquid fossil fuels including crude, residual, and distillate oils, F = 2.476 × 10−7

dscm/J (9,220 

dscf/MMBtu) and Fc= 0.384 × 10−7

scm CO2/J (1,430 scf CO2/MMBtu). 

(iv) For gaseous fossil fuels, F = 2.347 × 10−7

dscm/J (8,740 dscf/MMBtu). For natural gas, propane, 

and butane fuels, Fc= 0.279 × 10−7

scm CO2/J (1,040 scf CO2/MMBtu) for natural gas, 0.322 × 10−7scm 

CO2/J (1,200 scf CO2/MMBtu) for propane, and 0.338 × 10−7

scm CO2/J (1,260 scf CO2/MMBtu) for 

butane. 

(v) For bark F = 2.589 × 10−7

dscm/J (9,640 dscf/MMBtu) and Fc= 0.500 × 10−7scm CO2/J (1,840 scf 

CO2/MMBtu). For wood residue other than bark F = 2.492 × 10−7

dscm/J (9,280 dscf/MMBtu) and Fc= 

0.494 × 10−7

scm CO2/J (1,860 scf CO2/MMBtu). 

(vi) For lignite coal as classified according to ASTM D388 (incorporated by reference, see §60.17), F 

= 2.659 × 10−7

dscm/J (9,900 dscf/MMBtu) and Fc= 0.516 × 10−7scm CO2/J (1,920 scf CO2/MMBtu). 

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it again.
(5) The owner or operator may use the following equation to determine an F factor (dscm/J or 

dscf/MMBtu) on a dry basis (if it is desired to calculate F on a wet basis, consult the Administrator) or 

Fc factor (scm CO2/J, or scf CO2/MMBtu) on either basis in lieu of the F or Fcfactors specified in 

paragraph (f)(4) of this section: 

(i) %H, %C, %S, %N, and %O are content by weight of hydrogen, carbon, sulfur, nitrogen, and 

O2(expressed as percent), respectively, as determined on the same basis as GCV by ultimate analysis 

of the fuel fired, using ASTM D3178 or D3176 (solid fuels), or computed from results using ASTM 

D1137, D1945, or D1946 (gaseous fuels) as applicable. (These five methods are incorporated by 

reference, see §60.17.) 

(ii) GVC is the gross calorific value (kJ/kg, Btu/lb) of the fuel combusted determined by the ASTM 

test methods D2015 or D5865 for solid fuels and D1826 for gaseous fuels as applicable. (These three 

methods are incorporated by reference, see §60.17.) 

(iii) For affected facilities which fire both fossil fuels and nonfossil fuels, the F or Fc value shall be 

subject to the Administrator's approval. 

(6) For affected facilities firing combinations of fossil fuels or fossil fuels and wood residue, the F or 

Fc factors determined by paragraphs (f)(4) or (f)(5) of this section shall be prorated in accordance with 

the applicable formula as follows: 

Where: 

Xi= Fraction of total heat input derived from each type of fuel (e.g. natural gas, bituminous coal, wood 

residue, etc.); 

Fior (Fc)i= Applicable F or Fcfactor for each fuel type determined in accordance with paragraphs (f)(4) 

and (f)(5) of this section; and 

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n = Number of fuels being burned in combination. 

(g) Excess emission and monitoring system performance reports shall be submitted to the 

Administrator semiannually for each six-month period in the calendar year. All semiannual reports 

shall be postmarked by the 30th day following the end of each six-month period. Each excess emission 

and MSP report shall include the information required in §60.7(c). Periods of excess emissions and 

monitoring systems (MS) downtime that shall be reported are defined as follows: 

(1) Opacity . Excess emissions are defined as any six-minute period during which the average opacity 

of emissions exceeds 20 percent opacity, except that one six-minute average per hour of up to 27 

percent opacity need not be reported. 

(i) For sources subject to the opacity standard of §60.42(b)(1), excess emissions are defined as any sixminute period during which the average opacity of emissions exceeds 35 percent opacity, except that 

one six-minute average per hour of up to 42 percent opacity need not be reported. 

(ii) For sources subject to the opacity standard of §60.42(b)(2), excess emissions are defined as any 

six-minute period during which the average opacity of emissions exceeds 32 percent opacity, except 

that one six-minute average per hour of up to 39 percent opacity need not be reported. 

(2) Sulfur dioxide. Excess emissions for affected facilities are defined as: 

(i) For affected facilities electing not to comply with §60.43(d), any three-hour period during which the 

average emissions (arithmetic average of three contiguous one-hour periods) of SO2as measured by a 

CEMS exceed the applicable standard in §60.43; or 

(ii) For affected facilities electing to comply with §60.43(d), any 30 operating day period during which 

the average emissions (arithmetic average of all one-hour periods during the 30 operating days) of 

SO2as measured by a CEMS exceed the applicable standard in §60.43. Facilities complying with the 

30-day SO2standard shall use the most current associated SO2compliance and monitoring requirements 

in §§60.48Da and 60.49Da of subpart Da of this part or §§60.45b and 60.47b of subpart Db of this 

part, as applicable. 

(3) Nitrogen oxides. Excess emissions for affected facilities using a CEMS for measuring NOXare 

defined as: 

(i) For affected facilities electing not to comply with §60.44(e), any three-hour period during which the 

average emissions (arithmetic average of three contiguous one-hour periods) exceed the applicable 

standards in §60.44; or 

(ii) For affected facilities electing to comply with §60.44(e), any 30 operating day period during which 

the average emissions (arithmetic average of all one-hour periods during the 30 operating days) of 

NOXas measured by a CEMS exceed the applicable standard in §60.44. Facilities complying with the 

30-day NOXstandard shall use the most current associated NOXcompliance and monitoring 

requirements in §§60.48Da and 60.49Da of subpart Da of this part. 

(4) Particulate matter. Excess emissions for affected facilities using a CEMS for measuring PM are 

defined as any boiler operating day period during which the average emissions (arithmetic average of 

all operating one-hour periods) exceed the applicable standards in §60.42. Affected facilities using PM 

CEMS must follow the most current applicable compliance and monitoring provisions in §§60.48Da 

and 60.49Da of subpart Da of this part. 
(h) The owner or operator of an affected facility subject to the opacity limits in §60.42 that elects to 

monitor emissions according to the requirements in §60.45(b)(7) shall maintain records according to 

the requirements specified in paragraphs (h)(1) through (3) of this section, as applicable to the visible 

emissions monitoring method used. 

(1) For each performance test conducted using Method 9 of appendix A–4 of this part, the owner or 

operator shall keep the records including the information specified in paragraphs (h)(1)(i) through (iii) 

of this section. 

(i) Dates and time intervals of all opacity observation periods; 

(ii) Name, affiliation, and copy of current visible emission reading certification for each visible 

emission observer participating in the performance test; and 

(iii) Copies of all visible emission observer opacity field data sheets; 

(2) For each performance test conducted using Method 22 of appendix A–4 of this part, the owner or 

operator shall keep the records including the information specified in paragraphs (h)(2)(i) through (iv) 

of this section. 

(i) Dates and time intervals of all visible emissions observation periods; 

(ii) Name and affiliation for each visible emission observer participating in the performance test; 

(iii) Copies of all visible emission observer opacity field data sheets; and 

(iv) Documentation of any adjustments made and the time the adjustments were completed to the 

affected facility operation by the owner or operator to demonstrate compliance with the applicable 

monitoring requirements. 

(3) For each digital opacity compliance system, the owner or operator shall maintain records and 

submit reports according to the requirements specified in the site-specific monitoring plan approved by 

the Administrator. 
Subpart Da—Standards of Performance for Electric Utility Steam Generating Units for Which 

Construction is Commenced After September 18, 1978 

§60.48Da Compliance provisions. 

(a) Compliance with the PM emission limitation under §60.42Da(a)(1) constitutes compliance with the 

percent reduction requirements for PM under §60.42Da(a)(2) and (3). 

(b) Compliance with the NOXemission limitation under §60.44Da(a)(1) constitutes compliance with 

the percent reduction requirements under §60.44Da(a)(2). 

(c) The PM emission standards under §60.42Da, and the NOX emission standards under §60.44Da, 

and the Hg emission standards under §60.45Da apply at all times except during periods of startup, 

shutdown, or malfunction. The sulfur dioxide emission standards under §60.43Da apply at all times 

except during periods of startup, shutdown, or when both emergency conditions exist and the 

procedures under paragraph (d) of this section are implemented.

(d) During emergency conditions in the principal company, an affected facility with a malfunctioning 

flue gas desulfurization system may be operated if SO2emissions are minimized by: 

(1) Operating all operable flue gas desulfurization system modules, and bringing back into operation 

any malfunctioned module as soon as repairs are completed, 

(2) Bypassing flue gases around only those flue gas desulfurization system modules that have been 

taken out of operation because they were incapable of any SO2emission reduction or which would have 

suffered significant physical damage if they had remained in operation, and 

(3) Designing, constructing, and operating a spare flue gas desulfurization system module for an 

affected facility larger than 365 MW (1,250 MMBtu/hr) heat input (approximately 125 MW electrical 

output capacity). The Administrator may at his discretion require the owner or operator within 60 days 

of notification to demonstrate spare module capability. To demonstrate this capability, the owner or 

operator must demonstrate compliance with the appropriate requirements under paragraph under 

§60.43Da(a), (b), (d), (e), and (h) for any period of operation lasting from 24 hours to 30 days when: 

(i) Any one flue gas desulfurization module is not operated, 

(ii) The affected facility is operating at the maximum heat input rate, 

(iii) The fuel fired during the 24-hour to 30-day period is representative of the type and average sulfur 

content of fuel used over a typical 30-day period, and 

(iv) The owner or operator has given the Administrator at least 30 days notice of the date and period of 

time over which the demonstration will be performed. 

(e) After the initial performance test required under §60.8, compliance with the SO2emission 

limitations and percentage reduction requirements under §60.43Da and the NOXemission limitations 

under §60.44Da is based on the average emission rate for 30 successive boiler operating days. A 

separate performance test is completed at the end of each boiler operating day after the initial 

performance test, and a new 30 day average emission rate for both SO2and NOXand a new percent 

reduction for SO2are calculated to show compliance with the standards. 

(f) For the initial performance test required under §60.8, compliance with the SO2emission limitations 

and percent reduction requirements under §60.43Da and the NOXemission limitation under §60.44Da 

is based on the average emission rates for SO2, NOX, and percent reduction for SO2for the first 30 

Comment [CF1]: Correct FR error ‐ Never

intended to drop the last sentence.  The Clean Air

Mercury Rule (CAMR) was vacated so the Hg

provision is no longer relevant.
successive boiler operating days. The initial performance test is the only test in which at least 30 days 

prior notice is required unless otherwise specified by the Administrator. The initial performance test is 

to be scheduled so that the first boiler operating day of the 30 successive boiler operating days is 

completed within 60 days after achieving the maximum production rate at which the affected facility 

will be operated, but not later than 180 days after initial startup of the facility. 

(g) The owner or operator of an affected facility subject to emission limitations in this subpart shall 

determine compliance as follows: 

(1) Compliance with applicable 30-day rolling average SO2and NOXemission limitations is determined 

by calculating the arithmetic average of all hourly emission rates for SO2and NOXfor the 30 successive 

boiler operating days, except for data obtained during startup, shutdown, malfunction (NOXonly), or 

emergency conditions (SO2only). 

(2) Compliance with applicable SO2percentage reduction requirements is determined based on the 

average inlet and outlet SO2emission rates for the 30 successive boiler operating days. 

(3) Compliance with applicable daily average PM emission limitations is determined by calculating the 

arithmetic average of all hourly emission rates for PM each boiler operating day, except for data 

obtained during startup, shutdown, and malfunction. Averages are only calculated for boiler operating 

days that have valid data for at least 18 hours of unit operation during which the standard applies. 

Instead, all of the valid hourly emission rates of the operating day(s) not meeting the minimum 18 

hours valid data daily average requirement are averaged with all of the valid hourly emission rates of 

the next boiler operating day with 18 hours or more of valid PM CEMS data to determine compliance. 

(h) If an owner or operator has not obtained the minimum quantity of emission data as required under 

§60.49Da of this subpart, compliance of the affected facility with the emission requirements under 

§§60.43Da and 60.44Da of this subpart for the day on which the 30-day period ends may be 

determined by the Administrator by following the applicable procedures in section 7 of Method 19 of 

appendix A of this part. 

(i) Compliance provisions for sources subject to §60.44Da(d)(1), (e)(1), (e)(2)(i), (e)(3)(i), or (f) . The 

owner or operator of an affected facility subject to §60.44Da(d)(1), (e)(1), (e)(2)(i), (e)(3)(i), or (f) 

shall calculate NOXemissions as 1.194 × 10−7

 lb/scf-ppm times the average hourly NOXoutput 

concentration in ppm (measured according to the provisions of §60.49Da(c)), times the average hourly 

flow rate (measured in scfh, according to the provisions of §60.49Da(l) or §60.49Da(m)), divided by 

the average hourly gross energy output (measured according to the provisions of §60.49Da(k)). 

Alternatively, for oil-fired and gas-fired units, NOXemissions may be calculated by multiplying the 

hourly NOXemission rate in lb/MMBtu (measured by the CEMS required under §§60.49Da(c) and (d)), 

by the hourly heat input rate (measured according to the provisions of §60.49Da(n)), and dividing the 

result by the average gross energy output (measured according to the provisions of §60.49Da(k)). 

(j) Compliance provisions for duct burners subject to §60.44Da(a)(1) . To determine compliance with 

the emissions limits for NOXrequired by §60.44Da(a) for duct burners used in combined cycle systems, 

either of the procedures described in paragraph (j)(1) or (2) of this section may be used: 

(1) The owner or operator of an affected duct burner shall conduct the performance test required under 

§60.8 using the appropriate methods in appendix A of this part. Compliance with the emissions limits 

under §60.44Da(a)(1) is determined on the average of three (nominal 1-hour) runs for the initial and 

subsequent performance tests. During the performance test, one sampling site shall be located in the 

exhaust of the turbine prior to the duct burner. A second sampling site shall be located at the outlet 
from the heat recovery steam generating unit. Measurements shall be taken at both sampling sites 

during the performance test; or 

(2) The owner or operator of an affected duct burner may elect to determine compliance by using the 

CEMS specified under §60.49Da for measuring NOXand oxygen (O2) (or carbon dioxide (CO2)) and 

meet the requirements of §60.49Da. Alternatively, data from a NOXemission rate ( i.e. , NOX-diluent) 

CEMS certified according to the provisions of §75.20(c) of this chapter and appendix A to part 75 of 

this chapter, and meeting the quality assurance requirements of §75.21 of this chapter and appendix B 

to part 75 of this chapter, may be used, with the following caveats. Data used to meet the requirements 

of §60.51Da shall not include substitute data values derived from the missing data procedures in 

subpart D of part 75 of this chapter, nor shall the data have been bias adjusted according to the 

procedures of part 75 of this chapter. The sampling site shall be located at the outlet from the steam 

generating unit. The NOXemission rate at the outlet from the steam generating unit shall constitute the 

NOXemission rate from the duct burner of the combined cycle system. 

(k) Compliance provisions for duct burners subject to §60.44Da(d)(1) or (e)(1) . To determine 

compliance with the emission limitation for NOXrequired by §60.44Da(d)(1) or (e)(1) for duct burners 

used in combined cycle systems, either of the procedures described in paragraphs (k)(1) and (2) of this 

section may be used: 

(1) The owner or operator of an affected duct burner used in combined cycle systems shall determine 

compliance with the applicable NOXemission limitation in §60.44Da(d)(1) or (e)(1) as follows: 

(i) The emission rate (E) of NOXshall be computed using Equation 2 in this section: 

Where: 

E = Emission rate of NOXfrom the duct burner, ng/J (lb/MWh) gross output; 

Csg= Average hourly concentration of NOXexiting the steam generating unit, ng/dscm (lb/dscf); 

Cte= Average hourly concentration of NOXin the turbine exhaust upstream from duct burner, ng/dscm 

(lb/dscf); 

Qsg= Average hourly volumetric flow rate of exhaust gas from steam generating unit, dscm/hr 

(dscf/hr); 

Qte= Average hourly volumetric flow rate of exhaust gas from combustion turbine, dscm/hr (dscf/hr); 

Osg= Average hourly gross energy output from steam generating unit, J (MWh); and 

h = Average hourly fraction of the total heat input to the steam generating unit derived from the 

combustion of fuel in the affected duct burner. 

(ii) Method 7E of appendix A of this part shall be used to determine the NOXconcentrations (Csgand 

Cte). Method 2, 2F or 2G of appendix A of this part, as appropriate, shall be used to determine the 

volumetric flow rates (Qsgand Qte) of the exhaust gases. The volumetric flow rate measurements shall 

be taken at the same time as the concentration measurements. 

(iii) The owner or operator shall develop, demonstrate, and provide information satisfactory to the 

Administrator to determine the average hourly gross energy output from the steam generating unit, and 

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the average hourly percentage of the total heat input to the steam generating unit derived from the 

combustion of fuel in the affected duct burner. 

(iv) Compliance with the applicable NOXemission limitation in §60.44Da(d)(1) or (e)(1) is determined 

by the three-run average (nominal 1-hour runs) for the initial and subsequent performance tests. 

(2) The owner or operator of an affected duct burner used in a combined cycle system may elect to 

determine compliance with the applicable NOXemission limitation in §60.44Da(d)(1) or (e)(1) on a 30-

day rolling average basis as indicated in paragraphs (k)(2)(i) through (iv) of this section. 

(i) The emission rate (E) of NOXshall be computed using Equation 3 in this section: 

Where: 

E = Emission rate of NOXfrom the duct burner, ng/J (lb/MWh) gross output; 

Csg= Average hourly concentration of NOXexiting the steam generating unit, ng/dscm (lb/dscf); 

Qsg= Average hourly volumetric flow rate of exhaust gas from steam generating unit, dscm/hr 

(dscf/hr); and 

Occ= Average hourly gross energy output from entire combined cycle unit, J (MWh). 

(ii) The CEMS specified under §60.49Da for measuring NOXand O2(or CO2) shall be used to 

determine the average hourly NOXconcentrations (Csg). The continuous flow monitoring system 

specified in §60.49Da(l) or §60.49Da(m) shall be used to determine the volumetric flow rate (Qsg) of 

the exhaust gas. If the option to use the flow monitoring system in §60.49Da(m) is selected, the flow 

rate data used to meet the requirements of §60.51Da shall not include substitute data values derived 

from the missing data procedures in subpart D of part 75 of this chapter, nor shall the data have been 

bias adjusted according to the procedures of part 75 of this chapter. The sampling site shall be located 

at the outlet from the steam generating unit. 

(iii) The continuous monitoring system specified under §60.49Da(k) for measuring and determining 

gross energy output shall be used to determine the average hourly gross energy output from the entire 

combined cycle unit (Occ), which is the combined output from the combustion turbine and the steam 

generating unit. 

(iv) The owner or operator may, in lieu of installing, operating, and recording data from the continuous 

flow monitoring system specified in §60.49Da(l), determine the mass rate (lb/hr) of NOXemissions by 

installing, operating, and maintaining continuous fuel flowmeters following the appropriate 

measurements procedures specified in appendix D of part 75 of this chapter. If this compliance option 

is selected, the emission rate (E) of NOXshall be computed using Equation 4 in this section: 

Where: 

E = Emission rate of NOXfrom the duct burner, ng/J (lb/MWh) gross output; 

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The image cannot be displayed. Your computer may not have enough memory to open the image, or the image may have been corrupted. Restart your computer, and then open the file again. If the red x still appears, you may have to delete the image and then insert it again.
ERsg= Average hourly emission rate of NOXexiting the steam generating unit heat input calculated 

using appropriate F factor as described in Method 19 of appendix A of this part, ng/J (lb/MMBtu); 

Hcc= Average hourly heat input rate of entire combined cycle unit, J/hr (MMBtu/hr); and 

Occ= Average hourly gross energy output from entire combined cycle unit, J (MWh). 

(3) When an affected duct burner steam generating unit utilizes a common steam turbine with one or 

more affected duct burner steam generating units, the owner or operator shall either: 

(i) Determine compliance with the applicable NOXemissions limits by measuring the emissions 

combined with the emissions from the other unit(s) utilizing the common steam turbine; or 

(ii) Develop, demonstrate, and provide information satisfactory to the Administrator on methods for 

apportioning the combined gross energy output from the steam turbine for each of the affected duct 

burners. The Administrator may approve such demonstrated substitute methods for apportioning the 

combined gross energy output measured at the steam turbine whenever the demonstration ensures 

accurate estimation of emissions regulated under this part. 

(l) Compliance provisions for sources subject to §60.45Da. The owner or operator of an affected 

facility subject to §60.45Da (new sources constructed or reconstructed after January 30, 2004) shall 

calculate the Hg emission rate (lb/MWh) for each calendar month of the year, using hourly Hg 

concentrations measured according to the provisions of §60.49Da(p) in conjunction with hourly stack 

gas volumetric flow rates measured according to the provisions of §60.49Da(l) or (m), and hourly 

gross electrical outputs, determined according to the provisions in §60.49Da(k). Compliance with the 

applicable standard under §60.45Da is determined on a 12-month rolling average basis. 

(m) Compliance provisions for sources subject to §60.43Da(i)(1)(i), (i)(2)(i), (i)(3)(i), (j)(1)(i), 

(j)(2)(i), or (j)(3)(i). The owner or operator of an affected facility subject to §60.43Da(i)(1)(i), (i)(2)(i), 

(i)(3)(i), (j)(1)(i), (j)(2)(i), or (j)(3)(i) shall calculate SO2emissions as 1.660 × 10–7lb/scf-ppm times the 

average hourly SO2output concentration in ppm (measured according to the provisions of 

§60.49Da(b)), times the average hourly flow rate (measured according to the provisions of §60.49Da(l) 

or §60.49Da(m)), divided by the average hourly gross energy output (measured according to the 

provisions of §60.49Da(k)). Alternatively, for oil-fired and gas-fired units, SO2emissions may be 

calculated by multiplying the hourly SO2emission rate (in lb/MMBtu), measured by the CEMS 

required under §60.49Da, by the hourly heat input rate (measured according to the provisions of 

§60.49Da(n)), and dividing the result by the average gross energy output (measured according to the 

provisions of §60.49Da(k)). 

(n) Compliance provisions for sources subject to §60.42Da(c)(1) . The owner or operator of an 

affected facility subject to §60.42Da(c)(1) shall calculate PM emissions by multiplying the average 

hourly PM output concentration (measured according to the provisions of §60.49Da(t)), by the average 

hourly flow rate (measured according to the provisions of §60.49Da(l) or §60.49Da(m)), and divided 

by the average hourly gross energy output (measured according to the provisions of §60.49Da(k)). 

Compliance with the emission limit is determined by calculating the arithmetic average of the hourly 

emission rates computed for each boiler operating day. 

(o) Compliance provisions for sources subject to §60.42Da(c)(2) or (d) . Except as provided for in 

paragraph (p) of this section, the owner or operator of an affected facility for which construction, 

reconstruction, or modification commenced after February 28, 2005, shall demonstrate compliance 

with each applicable emission limit according to the requirements in paragraphs (o)(1) through (o)(5) 

of this section. 
(1) You must conduct a performance test to demonstrate initial compliance with the applicable PM 

emissions limit in §60.42Da(c)(2) or (d) by the applicable date specified in §60.8(a). Thereafter, you 

must conduct each subsequent performance test within 12 calendar months following the date the 

previous performance test was required to be conducted. You must conduct each performance test 

according to the requirements in §60.8 using the test methods and procedures in §60.50Da. The owner 

or operator of an affected facility that has not operated for 60 consecutive calendar days prior to the 

date that the subsequent performance test would have been required had the unit been operating is not 

required to perform the subsequent performance test until 30 calendar days after the next boiler 

operating day. Requests for additional 30 day extensions shall be granted by the relevant air division or 

office director of the appropriate Regional Office of the U.S. EPA. 

(2) You must monitor the performance of each electrostatic precipitator or fabric filter (baghouse) 

operated to comply with the applicable PM emissions limit in §60.42Da(c)(2) or (d) using a continuous 

opacity monitoring system (COMS) according to the requirements in paragraphs (o)(2)(i) through (vi) 

unless you elect to comply with one of the alternatives provided in paragraphs (o)(3) and (o)(4) of this 

section, as applicable to your control device. 

(i) Each COMS must meet Performance Specification 1 in 40 CFR part 60, appendix B. 

(ii) You must comply with the quality assurance requirements in paragraphs (o)(2)(ii)(A) through (E) 

of this section. 

(A) You must automatically (intrinsic to the opacity monitor) check the zero and upscale (span) 

calibration drifts at least once daily. For a particular COMS, the acceptable range of zero and upscale 

calibration materials is as defined in the applicable version of Performance Specification 1 in 40 CFR 

part 60, appendix B. 

(B) You must adjust the zero and span whenever the 24-hour zero drift or 24-hour span drift exceeds 4 

percent opacity. The COMS must allow for the amount of excess zero and span drift measured at the 

24-hour interval checks to be recorded and quantified. The optical surfaces exposed to the effluent 

gases must be cleaned prior to performing the zero and span drift adjustments, except for systems 

using automatic zero adjustments. For systems using automatic zero adjustments, the optical surfaces 

must be cleaned when the cumulative automatic zero compensation exceeds 4 percent opacity. 

(C) You must apply a method for producing a simulated zero opacity condition and an upscale (span) 

opacity condition using a certified neutral density filter or other related technique to produce a known 

obscuration of the light beam. All procedures applied must provide a system check of the analyzer 

internal optical surfaces and all electronic circuitry including the lamp and photodetector assembly. 

(D) Except during periods of system breakdowns, repairs, calibration checks, and zero and span 

adjustments, the COMS must be in continuous operation and must complete a minimum of one cycle 

of sampling and analyzing for each successive 10 second period and one cycle of data recording for 

each successive 6-minute period. 

(E) You must reduce all data from the COMS to 6-minute averages. Six-minute opacity averages must 

be calculated from 36 or more data points equally spaced over each 6-minute period. Data recorded 

during periods of system breakdowns, repairs, calibration checks, and zero and span adjustments must 

not be included in the data averages. An arithmetic or integrated average of all data may be used. 

(iii) During each performance test conducted according to paragraph (o)(1) of this section, you must 

establish an opacity baseline level. The value of the opacity baseline level is determined by averaging 

all of the 6-minute average opacity values (reported to the nearest 0.1 percent opacity) from the COMS 

measurements recorded during each of the test run intervals conducted for the performance test, and 
then adding 2.5 percent opacity to your calculated average opacity value for all of the test runs. If your 

opacity baseline level is less than 5.0 percent, then the opacity baseline level is set at 5.0 percent. 

(iv) You must evaluate the preceding 24-hour average opacity level measured by the COMS each 

boiler operating day excluding periods of affected facility startup, shutdown, or malfunction. If the 

measured 24-hour average opacity emission level is greater than the baseline opacity level determined 

in paragraph (o)(2)(iii) of this section, you must initiate investigation of the relevant equipment and 

control systems within 24 hours of the first discovery of the high opacity incident and take the 

appropriate corrective action as soon as practicable to adjust control settings or repair equipment to 

reduce the measured 24-hour average opacity to a level below the baseline opacity level. In cases when 

a wet scrubber is used in combination with another PM control device that serves as the primary PM 

control device, the wet scrubber must be maintained and operated. 

(v) You must record the opacity measurements, calculations performed, and any corrective actions 

taken. The record of corrective action taken must include the date and time during which the measured 

24-hour average opacity was greater than baseline opacity level, and the date, time, and description of 

the corrective action. 

(vi) If the measured 24-hour average opacity for your affected facility remains at a level greater than 

the opacity baseline level after 7 boiler operating days, then you must conduct a new PM performance 

test according to paragraph (o)(1) of this section and establish a new opacity baseline value according 

to paragraph (o)(2) of this section. This new performance test must be conducted within 60 days of the 

date that the measured 24-hour average opacity was first determined to exceed the baseline opacity 

level unless a waiver is granted by the permitting authority. 

(3) As an alternative to complying with the requirements of paragraph (o)(2) of this section, an owner 

or operator may elect to monitor the performance of an electrostatic precipitator (ESP) operated to 

comply with the applicable PM emissions limit in §60.42Da(c)(2) or (d) using an ESP predictive 

model developed in accordance with the requirements in paragraphs (o)(3)(i) through (v) of this 

section. 

(i) You must calibrate the ESP predictive model with each PM control device used to comply with the 

applicable PM emissions limit in §60.42Da(c)(2) or (d) operating under normal conditions. In cases 

when a wet scrubber is used in combination with an ESP to comply with the PM emissions limit, the 

wet scrubber must be maintained and operated. 

(ii) You must develop a site-specific monitoring plan that includes a description of the ESP predictive 

model used, the model input parameters, and the procedures and criteria for establishing monitoring 

parameter baseline levels indicative of compliance with the PM emissions limit. You must submit the 

site-specific monitoring plan for approval by the permitting authority. For reference purposes in 

preparing the monitoring plan, see the OAQPS “Compliance Assurance Monitoring (CAM) Protocol 

for an Electrostatic Precipitator (ESP) Controlling Particulate Matter (PM) Emissions from a CoalFired Boiler.” This document is available from the U.S. Environmental Protection Agency (U.S. EPA); 

Office of Air Quality Planning and Standards; Sector Policies and Programs Division; Measurement 

Policy Group (D243–02), Research Triangle Park, NC 27711. This document is also available on the 

Technology Transfer Network (TTN) under Emission Measurement Center Continuous Emission 

Monitoring. 

(iii) You must run the ESP predictive model using the applicable input data each boiler operating day 

and evaluate the model output for the preceding boiler operating day excluding periods of affected 

facility startup, shutdown, or malfunction. If the values for one or more of the model parameters 
exceed the applicable baseline levels determined according to your approved site-specific monitoring 

plan, you must initiate investigation of the relevant equipment and control systems within 24 hours of 

the first discovery of a model parameter deviation and, take the appropriate corrective action as soon as 

practicable to adjust control settings or repair equipment to return the model output to within the 

applicable baseline levels. 

(iv) You must record the ESP predictive model inputs and outputs and any corrective actions taken. 

The record of corrective action taken must include the date and time during which the model output 

values exceeded the applicable baseline levels, and the date, time, and description of the corrective 

action. 

(v) If after 7 consecutive days a model parameter continues to exceed the applicable baseline level, 

then you must conduct a new PM performance test according to paragraph (o)(1) of this section. This 

new performance test must be conducted within 60 calendar days of the date that the model parameter 

was first determined to exceed its baseline level unless a waiver is granted by the permitting authority. 

(4) As an alternative to complying with the requirements of paragraph (o)(2) of this section, an owner 

or operator may elect to monitor the performance of a fabric filter (baghouse) operated to comply with 

the applicable PM emissions limit in §60.42Da(c)(2) or (d) by using a bag leak detection system 

according to the requirements in paragraphs (o)(4)(i) through (v) of this section. 

(i) Each bag leak detection system must meet the specifications and requirements in paragraphs 

(o)(4)(i)(A) through (H) of this section. 

(A) The bag leak detection system must be certified by the manufacturer to be capable of detecting PM 

emissions at concentrations of 1 milligram per actual cubic meter (0.00044 grains per actual cubic 

foot) or less. 

(B) The bag leak detection system sensor must provide output of relative PM loadings. The owner or 

operator must continuously record the output from the bag leak detection system using electronic or 

other means ( e.g. , using a strip chart recorder or a data logger.) 

(C) The bag leak detection system must be equipped with an alarm system that will react when the 

system detects an increase in relative particulate loading over the alarm set point established according 

to paragraph (o)(4)(i)(D) of this section, and the alarm must be located such that it can be noticed by 

the appropriate plant personnel. 

(D) In the initial adjustment of the bag leak detection system, you must establish, at a minimum, the 

baseline output by adjusting the sensitivity (range) and the averaging period of the device, the alarm 

set points, and the alarm delay time. 

(E) Following initial adjustment, you must not adjust the averaging period, alarm set point, or alarm 

delay time without approval from the permitting authority except as provided in paragraph (d)(1)(vi) of 

this section. 

(F) Once per quarter, you may adjust the sensitivity of the bag leak detection system to account for 

seasonal effects, including temperature and humidity, according to the procedures identified in the sitespecific monitoring plan required by paragraph (o)(4)(ii) of this section. 

(G) You must install the bag leak detection sensor downstream of the fabric filter and upstream of any 

wet scrubber. 

(H) Where multiple detectors are required, the system's instrumentation and alarm may be shared 

among detectors. 
(ii) You must develop and submit to the permitting authority for approval a site-specific monitoring 

plan for each bag leak detection system. You must operate and maintain the bag leak detection system 

according to the site-specific monitoring plan at all times. Each monitoring plan must describe the 

items in paragraphs (o)(4)(ii)(A) through (F) of this section. 

(A) Installation of the bag leak detection system; 

(B) Initial and periodic adjustment of the bag leak detection system, including how the alarm set-point 

will be established; 

(C) Operation of the bag leak detection system, including quality assurance procedures; 

(D) How the bag leak detection system will be maintained, including a routine maintenance schedule 

and spare parts inventory list; 

(E) How the bag leak detection system output will be recorded and stored; and 

(F) Corrective action procedures as specified in paragraph (o)(4)(iii) of this section. In approving the 

site-specific monitoring plan, the permitting authority may allow owners and operators more than 3 

hours to alleviate a specific condition that causes an alarm if the owner or operator identifies in the 

monitoring plan this specific condition as one that could lead to an alarm, adequately explains why it is 

not feasible to alleviate this condition within 3 hours of the time the alarm occurs, and demonstrates 

that the requested time will ensure alleviation of this condition as expeditiously as practicable. 

(iii) For each bag leak detection system, you must initiate procedures to determine the cause of every 

alarm within 1 hour of the alarm. Except as provided in paragraph (o)(4)(ii)(F) of this section, you 

must alleviate the cause of the alarm within 3 hours of the alarm by taking whatever corrective 

action(s) are necessary. Corrective actions may include, but are not limited to the following: 

(A) Inspecting the fabric filter for air leaks, torn or broken bags or filter media, or any other condition 

that may cause an increase in particulate emissions; 

(B) Sealing off defective bags or filter media; 

(C) Replacing defective bags or filter media or otherwise repairing the control device; 

(D) Sealing off a defective fabric filter compartment; 

(E) Cleaning the bag leak detection system probe or otherwise repairing the bag leak detection system; 

or 

(F) Shutting down the process producing the particulate emissions. 

(iv) You must maintain records of the information specified in paragraphs (o)(4)(iv)(A) through (C) of 

this section for each bag leak detection system. 

(A) Records of the bag leak detection system output; 

(B) Records of bag leak detection system adjustments, including the date and time of the adjustment, 

the initial bag leak detection system settings, and the final bag leak detection system settings; and 

(C) The date and time of all bag leak detection system alarms, the time that procedures to determine 

the cause of the alarm were initiated, if procedures were initiated within 1 hour of the alarm, the cause 

of the alarm, an explanation of the actions taken, the date and time the cause of the alarm was 

alleviated, and if the alarm was alleviated within 3 hours of the alarm. 

(v) If after any period composed of 30 boiler operating days during which the alarm rate exceeds 5 

percent of the process operating time (excluding control device or process startup, shutdown, and 
malfunction), then you must conduct a new PM performance test according to paragraph (o)(1) of this 

section. This new performance test must be conducted within 60 calendar days of the date that the 

alarm rate was first determined to exceed 5 percent limit unless a waiver is granted by the permitting 

authority. 

(5) An owner or operator of a modified affected facility electing to meet the emission limitations in 

§60.42Da(d) shall determine the percent reduction in PM by using the emission rate for PM 

determined by the performance test conducted according to the requirements in paragraph (o)(1) of this 

section and the ash content on a mass basis of the fuel burned during each performance test run as 

determined by analysis of the fuel as fired. 

(p) As an alternative to meeting the compliance provisions specified in paragraph (o) of this section, an 

owner or operator may elect to install, evaluate, maintain, and operate a CEMS measuring PM 

emissions discharged from the affected facility to the atmosphere and record the output of the system 

as specified in paragraphs (p)(1) through (p)(8) of this section. 

(1) The owner or operator shall submit a written notification to the Administrator of intent to 

demonstrate compliance with this subpart by using a CEMS measuring PM. This notification shall be 

sent at least 30 calendar days before the initial startup of the monitor for compliance determination 

purposes. The owner or operator may discontinue operation of the monitor and instead return to 

demonstration of compliance with this subpart according to the requirements in paragraph (o) of this 

section by submitting written notification to the Administrator of such intent at least 30 calendar days 

before shutdown of the monitor for compliance determination purposes. 

(2) Each CEMS shall be installed, evaluated, operated, and maintained according to the requirements 

in §60.49Da(v). 

(3) The initial performance evaluation shall be completed no later than 180 days after the date of initial 

startup of the affected facility, as specified under §60.8 of subpart A of this part or within 180 days of 

the date of notification to the Administrator required under paragraph (p)(1) of this section, whichever 

is later. 

(4) Compliance with the applicable emissions limit shall be determined based on the 24-hour daily 

(block) average of the hourly arithmetic average emissions concentrations using the continuous 

monitoring system outlet data. The 24-hour block arithmetic average emission concentration shall be 

calculated using EPA Reference Method 19 of appendix A of this part, section 4.1. 

(5) At a minimum, valid CEMS hourly averages shall be obtained for 75 percent of all operating hours 

on a 30-day rolling average basis. Beginning on January 1, 2012, valid CEMS hourly averages shall be 

obtained for 90 percent of all operating hours on a 30-day rolling average basis. 

(i) At least two data points per hour shall be used to calculate each 1-hour arithmetic average. 

(ii) [Reserved] 

(6) The 1-hour arithmetic averages required shall be expressed in ng/J, MMBtu/hr, or lb/MWh and 

shall be used to calculate the boiler operating day daily arithmetic average emission concentrations. 

The 1-hour arithmetic averages shall be calculated using the data points required under §60.13(e)(2) of 

subpart A of this part. 

(7) All valid CEMS data shall be used in calculating average emission concentrations even if the 

minimum CEMS data requirements of paragraph (j)(5) of this section are not met. 
(8) When PM emissions data are not obtained because of CEMS breakdowns, repairs, calibration 

checks, and zero and span adjustments, emissions data shall be obtained by using other monitoring 

systems as approved by the Administrator or EPA Reference Method 19 of appendix A of this part to 

provide, as necessary, valid emissions data for a minimum of 90 percent (only 75 percent is required 

prior to January 1, 2012) of all operating hours per 30-day rolling average. 

(q) Compliance provisions for sources subject to §60.42Da(b) . An owner or operator of an affected 

facility subject to the opacity standard in §60.42Da(b) shall monitor the opacity of emissions 

discharged from the affected facility to the atmosphere according to the requirements in §60.49Da(a), 

as applicable to the affected facility. 

§60.49Da Emission monitoring. 

(a) An owner or operator of an affected facility subject to the opacity standard in §60.42Da(b) shall 

monitor the opacity of emissions discharged from the affected facility to the atmosphere according to 

the applicable requirements in paragraphs (a)(1) through (3) of this section. 

(1) Except as provided for in paragraph (a)(2) of this section, the owner or operator of an affected 

facility, shall install, calibrate, maintain, and operate a COMS, and record the output of the system, for 

measuring the opacity of emissions discharged to the atmosphere. If opacity interference due to water 

droplets exists in the stack (for example, from the use of an FGD system), the opacity is monitored 

upstream of the interference (at the inlet to the FGD system). If opacity interference is experienced at 

all locations (both at the inlet and outlet of the SO2control system), alternate parameters indicative of 

the PM control system's performance and/or good combustion are monitored (subject to the approval 

of the Administrator). 

(2) As an alternative to the monitoring requirements in paragraph (a)(1) of this section, an owner or 

operator of an affected facility that meets the conditions in either paragraph (a)(2)(i), (ii), or (iii) of this 

section may elect to monitor opacity as specified in paragraph (a)(3) of this section. 

(i) The affected facility uses a fabric filter (baghouse) to meet the standards in §60.42Da and a bag leak 

detection system is installed and operated according to the requirements in paragraphs 

§60.48Da(o)(4)(i) through (v); 

(ii) The affected facility burns only gaseous or liquid fuels (excluding residual oil) with potential 

SO2emissions rates of 26 ng/J (0.060 lb/MMBtu) or less, and does not use a post-combustion 

technology to reduce emissions of SO2or PM; or 

(iii) The affected facility meets all of the conditions specified in paragraphs (a)(2)(iii)(A) through (C) 

of this section. 

(A) No post-combustion technology (except a wet scrubber) is used for reducing PM, SO2, or carbon 

monoxide (CO) emissions; 

(B) Only natural gas, gaseous fuels, or fuel oils that contain less than or equal to 0.30 weight percent 

sulfur are burned; and 

(C) Emissions of CO discharged to the atmosphere are maintained at levels less than or equal to 1.4 

lb/MWh on a boiler operating day average basis as demonstrated by the use of a CEMS measuring CO 

emissions according to the procedures specified in paragraph (u) of this section. 

(3) The owner or operators of an affected facility that meets the conditions in paragraph (a)(2) of this 

section may, as an alternative to using a COMS, elect to monitor visible emissions using the applicable 

procedures specified in paragraphs (a)(3)(i) through (iv) of this section. The opacity performance test 
requirement in paragraph (a)(3)(i) must be conducted by April 29, 2011, within 45 days after stopping 

use of an existing COMS, or within 180 days after initial startup of the facility, whichever is later. The 

permitting authority may exempt owners or operators of affected facilities burning only natural gas 

from the opacity monitoring requirements.

(i) The owner or operator shall conduct a performance test using Method 9 of appendix A–4 of this 

part and the procedures in §60.11. If during the initial 60 minutes of the observation all the 6-minute 

averages are less than 10 percent and all the individual 15-second observations are less than or equal to 

20 percent, then the observation period may be reduced from 3 hours to 60 minutes. 

(ii) Except as provided in paragraph (a)(3)(iii) or (iv) of this section, the owner or operator shall 

conduct subsequent Method 9 of appendix A–4 of this part performance tests using the procedures in 

paragraph (a)(3)(i) of this section according to the applicable schedule in paragraphs (a)(3)(ii)(A) 

through (a)(3)(ii)(D) of this section, as determined by the most recent Method 9 of appendix A–4 of 

this part performance test results. 

(A) If no visible emissions are observed, a subsequent Method 9 of appendix A–4 of this part 

performance test must be completed within 12 calendar months from the date that the most recent 

performance test was conducted; 

(B) If visible emissions are observed but the maximum 6-minute average opacity is less than or equal 

to 5 percent, a subsequent Method 9 of appendix A–4 of this part performance test must be completed 

within 6 calendar months from the date that the most recent performance test was conducted; 

(C) If the maximum 6-minute average opacity is greater than 5 percent but less than or equal to 10 

percent, a subsequent Method 9 of appendix A–4 of this part performance test must be completed 

within 3 calendar months from the date that the most recent performance test was conducted; or 

(D) If the maximum 6-minute average opacity is greater than 10 percent, a subsequent Method 9 of 

appendix A–4 of this part performance test must be completed within 30 45 calendar days from the 

date that the most recent performance test was conducted. 

(iii) If the maximum 6-minute opacity is less than 10 percent during the most recent Method 9 of 

appendix A–4 of this part performance test, the owner or operator may, as an alternative to performing 

subsequent Method 9 of appendix A–4 of this part performance tests, elect to perform subsequent 

monitoring using Method 22 of appendix A–7 of this part according to the procedures specified in 

paragraphs (a)(3)(iii)(A) and (B) of this section. 

(A) The owner or operator shall conduct 10 minute observations (during normal operation) each 

operating day the affected facility fires fuel for which an opacity standard is applicable using Method 

22 of appendix A–7 of this part and demonstrate that the sum of the occurrences of any visible 

emissions is not in excess of 5 percent of the observation period ( i.e. , 30 seconds per 10 minute 

period). If the sum of the occurrence of any visible emissions is greater than 30 seconds during the 

initial 10 minute observation, immediately conduct a 30 minute observation. If the sum of the 

occurrence of visible emissions is greater than 5 percent of the observation period ( i.e. , 90 seconds 

per 30 minute period) the owner or operator shall either document and adjust the operation of the 

facility and demonstrate within 24 hours that the sum of the occurrence of visible emissions is equal to 

or less than 5 percent during a 30 minute observation ( i.e. , 90 seconds) or conduct a new Method 9 of 

appendix A–4 of this part performance test using the procedures in paragraph (a)(3)(i) of this section 

within 30 45 calendar days according to the requirements in §60.50Da(b)(3). 
(B) If no visible emissions are observed for 30 operating days during which an opacity standard is 

applicable, observations can be reduced to once every 7 operating days during which an opacity 

standard is applicable. If any visible emissions are observed, daily observations shall be resumed. 

(iv) If the maximum 6-minute opacity is less than 10 percent during the most recent Method 9 of 

appendix A–4 of this part performance test, the owner or operator may, as an alternative to performing 

subsequent Method 9 of appendix A–4 performance tests, elect to perform subsequent monitoring 

using a digital opacity compliance system according to a site-specific monitoring plan approved by the 

Administrator. The observations shall be similar, but not necessarily identical, to the requirements in 

paragraph (a)(3)(iii) of this section. For reference purposes in preparing the monitoring plan, see 

OAQPS “Determination of Visible Emission Opacity from Stationary Sources Using Computer-Based 

Photographic Analysis Systems.” This document is available from the U.S. Environmental Protection 

Agency (U.S. EPA); Office of Air Quality and Planning Standards; Sector Policies and Programs 

Division; Measurement Policy Group (D243–02), Research Triangle Park, NC 27711. This document 

is also available on the Technology Transfer Network (TTN) under Emission Measurement Center 

Preliminary Methods. 

(b) The owner or operator of an affected facility shall install, calibrate, maintain, and operate a CEMS, 

and record the output of the system, for measuring SO2emissions, except where natural gas is the only 

fuel combusted, as follows: 

(1) Sulfur dioxide emissions are monitored at both the inlet and outlet of the SO2control device. 

(2) For a facility that qualifies under the numerical limit provisions of §60.43Da(d), (i), (j), or (k) 

SO2emissions are only monitored as discharged to the atmosphere. 

(3) An “as fired” fuel monitoring system (upstream of coal pulverizers) meeting the requirements of 

Method 19 of appendix A of this part may be used to determine potential SO2emissions in place of a 

continuous SO2emission monitor at the inlet to the SO2control device as required under paragraph 

(b)(1) of this section. 

(4) If the owner or operator has installed and certified a SO2CEMS according to the requirements of 

§75.20(c)(1) of this chapter and appendix A to part 75 of this chapter, and is continuing to meet the 

ongoing quality assurance requirements of §75.21 of this chapter and appendix B to part 75 of this 

chapter, that CEMS may be used to meet the requirements of this section, provided that: 

(i) A CO2or O2continuous monitoring system is installed, calibrated, maintained and operated at the 

same location, according to paragraph (d) of this section; and 

(ii) For sources subject to an SO2emission limit in lb/MMBtu under §60.43Da: 

(A) When relative accuracy testing is conducted, SO2concentration data and CO2(or O2) data are 

collected simultaneously; and 

(B) In addition to meeting the applicable SO2and CO2(or O2) relative accuracy specifications in Figure 

2 of appendix B to part 75 of this chapter, the relative accuracy (RA) standard in section 13.2 of 

Performance Specification 2 in appendix B to this part is met when the RA is calculated on a 

lb/MMBtu basis; and 

(iii) The reporting requirements of §60.51Da are met. The SO2and, if required, CO2(or O2) data 

reported to meet the requirements of §60.51Da shall not include substitute data values derived from the 

missing data procedures in subpart D of part 75 of this chapter, nor shall the SO2data have been bias 

adjusted according to the procedures of part 75 of this chapter. 
(c)(1) The owner or operator of an affected facility shall install, calibrate, maintain, and operate a 

CEMS, and record the output of the system, for measuring NOXemissions discharged to the 

atmosphere; or 

(2) If the owner or operator has installed a NOXemission rate CEMS to meet the requirements of part 

75 of this chapter and is continuing to meet the ongoing requirements of part 75 of this chapter, that 

CEMS may be used to meet the requirements of this section, except that the owner or operator shall 

also meet the requirements of §60.51Da. Data reported to meet the requirements of §60.51Da shall not 

include data substituted using the missing data procedures in subpart D of part 75 of this chapter, nor 

shall the data have been bias adjusted according to the procedures of part 75 of this chapter. 

(d) The owner or operator of an affected facility not complying with an output based limit shall install, 

calibrate, maintain, and operate a CEMS, and record the output of the system, for measuring the O2or 

carbon dioxide (CO2) content of the flue gases at each location where SO2or NOXemissions are 

monitored. For affected facilities subject to a lb/MMBtu SO2emission limit under §60.43Da, if the 

owner or operator has installed and certified a CO2or O2monitoring system according to §75.20(c) of 

this chapter and appendix A to part 75 of this chapter and the monitoring system continues to meet the 

applicable quality-assurance provisions of §75.21 of this chapter and appendix B to part 75 of this 

chapter, that CEMS may be used together with the part 75 SO2concentration monitoring system 

described in paragraph (b) of this section, to determine the SO2emission rate in lb/MMBtu. SO2data 

used to meet the requirements of §60.51Da shall not include substitute data values derived from the 

missing data procedures in subpart D of part 75 of this chapter, nor shall the data have been bias 

adjusted according to the procedures of part 75 of this chapter. 

(e) The CEMS under paragraphs (b), (c), and (d) of this section are operated and data recorded during 

all periods of operation of the affected facility including periods of startup, shutdown, malfunction or 

emergency conditions, except for CEMS breakdowns, repairs, calibration checks, and zero and span 

adjustments. 

(f)(1) For units that began construction, reconstruction, or modification on or before February 28, 

2005, the owner or operator shall obtain emission data for at least 18 hours in at least 22 out of 30 

successive boiler operating days. If this minimum data requirement cannot be met with CEMS, the 

owner or operator shall supplement emission data with other monitoring systems approved by the 

Administrator or the reference methods and procedures as described in paragraph (h) of this section. 

(2) For units that began construction, reconstruction, or modification after February 28, 2005, the 

owner or operator shall obtain emission data for at least 90 percent of all operating hours for each 30 

successive boiler operating days. If this minimum data requirement cannot be met with a CEMS, the 

owner or operator shall supplement emission data with other monitoring systems approved by the 

Administrator or the reference methods and procedures as described in paragraph (h) of this section. 

(g) The 1-hour averages required under paragraph §60.13(h) are expressed in ng/J (lb/MMBtu) heat 

input and used to calculate the average emission rates under §60.48Da. The 1-hour averages are 

calculated using the data points required under §60.13(h)(2). 

(h) When it becomes necessary to supplement CEMS data to meet the minimum data requirements in 

paragraph (f) of this section, the owner or operator shall use the reference methods and procedures as 

specified in this paragraph. Acceptable alternative methods and procedures are given in paragraph (j) 

of this section. 

(1) Method 6 of appendix A of this part shall be used to determine the SO2concentration at the same 

location as the SO2monitor. Samples shall be taken at 60-minute intervals. The sampling time and 
sample volume for each sample shall be at least 20 minutes and 0.020 dscm (0.71 dscf). Each sample 

represents a 1-hour average. 

(2) Method 7 of appendix A of this part shall be used to determine the NOXconcentration at the same 

location as the NOXmonitor. Samples shall be taken at 30-minute intervals. The arithmetic average of 

two consecutive samples represents a 1-hour average. 

(3) The emission rate correction factor, integrated bag sampling and analysis procedure of Method 3B 

of appendix A of this part shall be used to determine the O2or CO2concentration at the same location as 

the O2or CO2monitor. Samples shall be taken for at least 30 minutes in each hour. Each sample 

represents a 1-hour average. 

(4) The procedures in Method 19 of appendix A of this part shall be used to compute each 1-hour 

average concentration in ng/J (lb/MMBtu) heat input. 

(i) The owner or operator shall use methods and procedures in this paragraph to conduct monitoring 

system performance evaluations under §60.13(c) and calibration checks under §60.13(d). Acceptable 

alternative methods and procedures are given in paragraph (j) of this section. 

(1) Methods 3B, 6, and 7 of appendix A of this part shall be used to determine O2, SO2, and 

NOXconcentrations, respectively. 

(2) SO2or NOX(NO), as applicable, shall be used for preparing the calibration gas mixtures (in N2, as 

applicable) under Performance Specification 2 of appendix B of this part. 

(3) For affected facilities burning only fossil fuel, the span value for a COMS is between 60 and 80 

percent. Span values for a CEMS measuring NOXshall be determined using one of the following 

procedures: 

(i) Except as provided under paragraph (i)(3)(ii) of this section, NOXspan values shall be determined as 

follows: 

Fossil fuel Span values for NOX

(ppm) 

Gas 500. 

Liquid 500. 

Solid 1,000. 

Combination 500 (x + y) + 1,000z. 

Where: 

x = Fraction of total heat input derived from gaseous fossil fuel, 

y = Fraction of total heat input derived from liquid fossil fuel, and 

z = Fraction of total heat input derived from solid fossil fuel. 

(ii) As an alternative to meeting the requirements of paragraph (i)(3)(i) of this section, the owner or 

operator of an affected facility may elect to use the NOXspan values determined according to section 

2.1.2 in appendix A to part 75 of this chapter. 
(4) All span values computed under paragraph (i)(3)(i) of this section for burning combinations of 

fossil fuels are rounded to the nearest 500 ppm. Span values computed under paragraph (i)(3)(ii) of this 

section shall be rounded off according to section 2.1.2 in appendix A to part 75 of this chapter. 

(5) For affected facilities burning fossil fuel, alone or in combination with non-fossil fuel and 

determining span values under paragraph (i)(3)(i) of this section, the span value of the SO2CEMS at 

the inlet to the SO2control device is 125 percent of the maximum estimated hourly potential emissions 

of the fuel fired, and the outlet of the SO2control device is 50 percent of maximum estimated hourly 

potential emissions of the fuel fired. For affected facilities determining span values under paragraph 

(i)(3)(ii) of this section, SO2span values shall be determined according to section 2.1.1 in appendix A 

to part 75 of this chapter. 

(j) The owner or operator may use the following as alternatives to the reference methods and 

procedures specified in this section: 

(1) For Method 6 of appendix A of this part, Method 6A or 6B (whenever Methods 6 and 3 or 3B of 

appendix A of this part data are used) or 6C of appendix A of this part may be used. Each Method 6B 

of appendix A of this part sample obtained over 24 hours represents 24 1-hour averages. If Method 6A 

or 6B of appendix A of this part is used under paragraph (i) of this section, the conditions under 

§60.48Da(d)(1) apply; these conditions do not apply under paragraph (h) of this section. 

(2) For Method 7 of appendix A of this part, Method 7A, 7C, 7D, or 7E of appendix A of this part may 

be used. If Method 7C, 7D, or 7E of appendix A of this part is used, the sampling time for each run 

shall be 1 hour. 

(3) For Method 3 of appendix A of this part, Method 3A or 3B of appendix A of this part may be used 

if the sampling time is 1 hour. 

(4) For Method 3B of appendix A of this part, Method 3A of appendix A of this part may be used. 

(k) The procedures specified in paragraphs (k)(1) through (3) of this section shall be used to determine 

gross output for sources demonstrating compliance with the output-based standard under 

§§60.42Da(c), 60.43Da(i), 60.43Da(j), 60.44Da(d)(1), and 60.44Da(e). 

(1) The owner or operator of an affected facility with electricity generation shall install, calibrate, 

maintain, and operate a wattmeter; measure gross electrical output in MWh on a continuous basis; and 

record the output of the monitor. 

(2) The owner or operator of an affected facility with process steam generation shall install, calibrate, 

maintain, and operate meters for steam flow, temperature, and pressure; measure gross process steam 

output in joules per hour (or Btu per hour) on a continuous basis; and record the output of the monitor. 

(3) For affected facilities generating process steam in combination with electrical generation, the gross 

energy output is determined from the gross electrical output measured in accordance with paragraph 

(k)(1) of this section plus 75 percent of the gross thermal output (measured relative to ISO conditions) 

of the process steam measured in accordance with paragraph (k)(2) of this section. 

(l) The owner or operator of an affected facility demonstrating compliance with an output-based 

standard under §60.42Da, §60.43Da, §60.44Da, or §60.45Da shall install, certify, operate, and 

maintain a continuous flow monitoring system meeting the requirements of Performance Specification 

6 of appendix B of this part and the CD assessment, RATA and reporting provisions of procedure 1 of 

appendix F of this part, and record the output of the system, for measuring the volumetric flow rate of 

exhaust gases discharged to the atmosphere; or 
(m) Alternatively, data from a continuous flow monitoring system certified according to the 

requirements of §75.20(c) of this chapter and appendix A to part 75 of this chapter, and continuing to 

meet the applicable quality control and quality assurance requirements of §75.21 of this chapter and 

appendix B to part 75 of this chapter, may be used. Flow rate data reported to meet the requirements of 

§60.51Da shall not include substitute data values derived from the missing data procedures in subpart 

D of part 75 of this chapter, nor shall the data have been bias adjusted according to the procedures of 

part 75 of this chapter. 

(n) Gas-fired and oil-fired units. The owner or operator of an affected unit that qualifies as a gas-fired 

or oil-fired unit, as defined in 40 CFR 72.2, may use, as an alternative to the requirements specified in 

either paragraph (l) or (m) of this section, a fuel flow monitoring system certified and operated 

according to the requirements of appendix D of part 75 of this chapter. 

(o) The owner or operator of a duct burner, as described in §60.41Da, which is subject to the 

NOXstandards of §60.44Da(a)(1), (d)(1), or (e)(1) is not required to install or operate a CEMS to 

measure NOXemissions; a wattmeter to measure gross electrical output; meters to measure steam flow, 

temperature, and pressure; and a continuous flow monitoring system to measure the flow of exhaust 

gases discharged to the atmosphere. 

(p) The owner or operator of an affected facility demonstrating compliance with an Hg limit in 

§60.45Da shall install and operate a CEMS to measure and record the concentration of Hg in the 

exhaust gases from each stack according to the requirements in paragraphs (p)(1) through (p)(3) of this 

section. Alternatively, for an affected facility that is also subject to the requirements of subpart I of part 

75 of this chapter, the owner or operator may install, certify, maintain, operate and quality-assure the 

data from a Hg CEMS according to §75.10 of this chapter and appendices A and B to part 75 of this 

chapter, in lieu of following the procedures in paragraphs (p)(1) through (p)(3) of this section. 

(1) The owner or operator must install, operate, and maintain each CEMS according to Performance 

Specification 12A in appendix B to this part. 

(2) The owner or operator must conduct a performance evaluation of each CEMS according to the 

requirements of §60.13 and Performance Specification 12A in appendix B to this part. 

(3) The owner or operator must operate each CEMS according to the requirements in paragraphs 

(p)(3)(i) through (iv) of this section. 

(i) As specified in §60.13(e)(2), each CEMS must complete a minimum of one cycle of operation 

(sampling, analyzing, and data recording) for each successive 15-minute period. 

(ii) The owner or operator must reduce CEMS data as specified in §60.13(h). 

(iii) The owner or operator shall use all valid data points collected during the hour to calculate the 

hourly average Hg concentration. 

(iv) The owner or operator must record the results of each required certification and quality assurance 

test of the CEMS. 

(4) Mercury CEMS data collection must conform to paragraphs (p)(4)(i) through (iv) of this section. 

(i) For each calendar month in which the affected unit operates, valid hourly Hg concentration data, 

stack gas volumetric flow rate data, moisture data (if required), and electrical output data (i.e., valid 

data for all of these parameters) shall be obtained for at least 75 percent of the unit operating hours in 

the month. 
(ii) Data reported to meet the requirements of this subpart shall not include hours of unit startup, 

shutdown, or malfunction. In addition, for an affected facility that is also subject to subpart I of part 75 

of this chapter, data reported to meet the requirements of this subpart shall not include data substituted 

using the missing data procedures in subpart D of part 75 of this chapter, nor shall the data have been 

bias adjusted according to the procedures of part 75 of this chapter. 

(iii) If valid data are obtained for less than 75 percent of the unit operating hours in a month, you must 

discard the data collected in that month and replace the data with the mean of the individual monthly 

emission rate values determined in the last 12 months. In the 12-month rolling average calculation, this 

substitute Hg emission rate shall be weighted according to the number of unit operating hours in the 

month for which the data capture requirement of §60.49Da(p)(4)(i) was not met. 

(iv) Notwithstanding the requirements of paragraph (p)(4)(iii) of this section, if valid data are obtained 

for less than 75 percent of the unit operating hours in another month in that same 12-month rolling 

average cycle, discard the data collected in that month and replace the data with the highest individual 

monthly emission rate determined in the last 12 months. In the 12-month rolling average calculation, 

this substitute Hg emission rate shall be weighted according to the number of unit operating hours in 

the month for which the data capture requirement of §60.49Da(p)(4)(i) was not met. 

(q) As an alternative to the CEMS required in paragraph (p) of this section, the owner or operator may 

use a sorbent trap monitoring system (as defined in §72.2 of this chapter) to monitor Hg concentration, 

according to the procedures described in §75.15 of this chapter and appendix K to part 75 of this 

chapter. 

(r) For Hg CEMS that measure Hg concentration on a dry basis or for sorbent trap monitoring systems, 

the emissions data must be corrected for the stack gas moisture content. A certified continuous 

moisture monitoring system that meets the requirements of §75.11(b) of this chapter is acceptable for 

this purpose. Alternatively, the appropriate default moisture value, as specified in §75.11(b) or 

§75.12(b) of this chapter, may be used. 

(s) The owner or operator shall prepare and submit to the Administrator for approval a unit-specific 

monitoring plan for each monitoring system, at least 45 days before commencing certification testing 

of the monitoring systems. The owner or operator shall comply with the requirements in your plan. The 

plan must address the requirements in paragraphs (s)(1) through (6) of this section. 

(1) Installation of the CEMS sampling probe or other interface at a measurement location relative to 

each affected process unit such that the measurement is representative of the exhaust emissions ( e.g. , 

on or downstream of the last control device); 

(2) Performance and equipment specifications for the sample interface, the pollutant concentration or 

parametric signal analyzer, and the data collection and reduction systems; 

(3) Performance evaluation procedures and acceptance criteria ( e.g., calibrations, relative accuracy test 

audits (RATA), etc.); 

(4) Ongoing operation and maintenance procedures in accordance with the general requirements of 

§60.13(d) or part 75 of this chapter (as applicable); 

(5) Ongoing data quality assurance procedures in accordance with the general requirements of §60.13 

or part 75 of this chapter (as applicable); and 

(6) Ongoing recordkeeping and reporting procedures in accordance with the requirements of this 

subpart. 
(t) The owner or operator of an affected facility demonstrating compliance with the output-based 

emissions limitation under §60.42Da(c)(1) shall install, certify, operate, and maintain a CEMS for 

measuring PM emissions according to the requirements of paragraph (v) of this section. An owner or 

operator of an affected facility demonstrating compliance with the input-based emission limitation in 

§60.42Da(a)(1) or §60.42Da(c)(2) may install, certify, operate, and maintain a CEMS for measuring 

PM emissions according to the requirements of paragraph (v) of this section. 

(u) The owner or operator of an affected facility using a CEMS measuring CO emissions to meet 

requirements of this subpart shall meet the requirements specified in paragraphs (u)(1) through (4) of 

this section. 

(1) You must monitor CO emissions using a CEMS according to the procedures specified in 

paragraphs (u)(1)(i) through (iv) of this section. 

(i) The CO CEMS must be installed, certified, maintained, and operated according to the provisions in 

§60.58b(i)(3) of subpart Eb of this part. 

(ii) Each 1-hour CO emissions average is calculated using the data points generated by the CO CEMS 

expressed in parts per million by volume corrected to 3 percent oxygen (dry basis). 

(iii) At a minimum, valid 1-hour CO emissions averages must be obtained for at least 90 percent of the 

operating hours on a 30-day rolling average basis. The 1-hour averages are calculated using the data 

points required in §60.13(h)(2). 

(iv) Quarterly accuracy determinations and daily calibration drift tests for the CO CEMS must be 

performed in accordance with procedure 1 in appendix F of this part. 

(2) You must calculate the 1-hour average CO emissions levels for each boiler operating day by 

multiplying the average hourly CO output concentration measured by the CO CEMS times the 

corresponding average hourly flue gas flow rate and divided by the corresponding average hourly 

useful energy output from the affected facility. The 24-hour average CO emission level is determined 

by calculating the arithmetic average of the hourly CO emission levels computed for each boiler 

operating day. 

(3) You must evaluate the preceding 24-hour average CO emission level each boiler operating day 

excluding periods of affected facility startup, shutdown, or malfunction. If the 24-hour average CO 

emission level is greater than 1.4 lb/MWh, you must initiate investigation of the relevant equipment 

and control systems within 24 hours of the first discovery of the high emission incident and, take the 

appropriate corrective action as soon as practicable to adjust control settings or repair equipment to 

reduce the 24-hour average CO emission level to 1.4 lb/MWh or less. 

(4) You must record the CO measurements and calculations performed according to paragraph (u)(3) 

of this section and any corrective actions taken. The record of corrective action taken must include the 

date and time during which the 24-hour average CO emission level was greater than 1.4 lb/MWh, and 

the date, time, and description of the corrective action. 

(v) The owner or operator of an affected facility using a CEMS measuring PM emissions to meet 

requirements of this subpart shall install, certify, operate, and maintain the CEMS as specified in 

paragraphs (v)(1) through (v)(4) of this section. 

(1) The owner or operator shall conduct a performance evaluation of the CEMS according to the 

applicable requirements of §60.13, Performance Specification 11 in appendix B of this part, and 

procedure 2 in appendix F of this part. 
(2) During each PM correlation testing run of the CEMS required by Performance Specification 11 in 

appendix B of this part, PM and O2(or CO2) data shall be collected concurrently (or within a 30- to 60-

minute period) by both the CEMS and performance tests conducted using the following test methods. 

(i) For PM, Method 5 or 5B of appendix A–3 of this part or Method 17 of appendix A–6 of this part 

shall be used; and 

(ii) After July 1, 2010 or after Method 202 of appendix M of part 51 has been revised to minimize 

artifact measurement and notice of that change has been published in theFederal Register,whichever is 

later, for condensable PM emissions, Method 202 of appendix M of part 51 shall be used; and

(iii) For O2(or CO2), Method 3A or 3B of appendix A–2 of this part, as applicable shall be used. 

(3) Quarterly accuracy determinations and daily calibration drift tests shall be performed in accordance 

with procedure 2 in appendix F of this part. Relative Response Audit's must be performed annually and 

Response Correlation Audits must be performed every 3 years. 

(4) After July 1, 2011, within 90 days after the date of completing each performance evaluation 

required by paragraph (v) of this section, the owner or operator of the affected facility must either 

submit the test data to EPA by successfully entering the data electronically into EPA's WebFIRE data 

base available at http://cfpub.epa.gov/oarweb/index.cfm?action=fire.main or mail a copy to: United 

States Environmental Protection Agency; Energy Strategies Group; 109 TW Alexander DR; Mail 

Code: D243–01; RTP, NC 27711. 

(w) The owner or operator using a SO2, NOX, CO2, and O2CEMS to meet the requirements of this 

subpart shall install, certify, operate, and maintain the CEMS as specified in paragraphs (w)(1) through 

(w)(5) of this section. 

(1) Except as provided for under paragraphs (w)(2), (w)(3), and (w)(4) of this section, each SO2, NOX, 

CO2, and O2CEMS required under paragraphs (b) through (d) of this section shall be installed, 

certified, and operated in accordance with the applicable procedures in Performance Specification 2 or 

3 in appendix B to this part or according to the procedures in appendices A and B to part 75 of this 

chapter. Daily calibration drift assessments and quarterly accuracy determinations shall be done in 

accordance with Procedure 1 in appendix F to this part, and a data assessment report (DAR), prepared 

according to section 7 of Procedure 1 in appendix F to this part, shall be submitted with each 

compliance report required under §60.51Da. 

(2) As an alternative to meeting the requirements of paragraph (w)(1) of this section, an owner or 

operator may elect to implement the following alternative data accuracy assessment procedures. For all 

required CO2and O2CEMS and for SO2and NOXCEMS with span values greater than or equal to 100 

ppm, the daily calibration error test and calibration adjustment procedures described in sections 2.1.1 

and 2.1.3 of appendix B to part 75 of this chapter may be followed instead of the CD assessment 

procedures in Procedure 1, section 4.1 of appendix F of this part. If this option is selected, the data 

validation and out-of-control provisions in sections 2.1.4 and 2.1.5 of appendix B to part 75 of this 

chapter shall be followed instead of the excessive CD and out-of-control criteria in Procedure 1, 

section 4.3 of appendix F to this part. For the purposes of data validation under this subpart, the 

excessive CD and out-of-control criteria in Procedure 1, section 4.3 of appendix F to this part shall 

apply to SO2and NOXspan values less than 100 ppm; 

(3) As an alternative to meeting the requirements of paragraph (w)(1) of this section, an owner or 

operator may elect to may elect to implement the following alternative data accuracy assessment 

procedures. For all required CO2and O2CEMS and for SO2and NOXCEMS with span values greater 

than 30 ppm, quarterly linearity checks may be performed in accordance with section 2.2.1 of appendix 

Comment [CF2]: Condensable PM testing no

longer required since will gather significant data

from the EGU MACT ICR
B to part 75 of this chapter, instead of performing the cylinder gas audits (CGAs) described in 

Procedure 1, section 5.1.2 of appendix F to this part. If this option is selected: The frequency of the 

linearity checks shall be as specified in section 2.2.1 of appendix B to part 75 of this chapter; the 

applicable linearity specifications in section 3.2 of appendix A to part 75 of this chapter shall be met; 

the data validation and out-of-control criteria in section 2.2.3 of appendix B to part 75 of this chapter 

shall be followed instead of the excessive audit inaccuracy and out-of-control criteria in Procedure 1, 

section 5.2 of appendix F to this part; and the grace period provisions in section 2.2.4 of appendix B to 

part 75 of this chapter shall apply. For the purposes of data validation under this subpart, the cylinder 

gas audits described in Procedure 1, section 5.1.2 of appendix F to this part shall be performed for 

SO2and NOXspan values less than or equal to 30 ppm; 

(4) As an alternative to meeting the requirements of paragraph (w)(1) of this section, an owner or 

operator may elect to may elect to implement the following alternative data accuracy assessment 

procedures. For SO2, CO2, and O2CEMS and for NOXCEMS, RATAs may be performed in accordance 

with section 2.3 of appendix B to part 75 of this chapter instead of following the procedures described 

in Procedure 1, section 5.1.1 of appendix F to this part. If this option is selected: The frequency of each 

RATA shall be as specified in section 2.3.1 of appendix B to part 75 of this chapter; the applicable 

relative accuracy specifications shown in Figure 2 in appendix B to part 75 of this chapter shall be met; 

the data validation and out-of-control criteria in section 2.3.2 of appendix B to part 75 of this chapter 

shall be followed instead of the excessive audit inaccuracy and out-of-control criteria in Procedure 1, 

section 5.2 of appendix F to this part; and the grace period provisions in section 2.3.3 of appendix B to 

part 75 of this chapter shall apply. For the purposes of data validation under this subpart, the relative 

accuracy specification in section 13.2 of Performance Specification 2 in appendix B to this part shall 

be met on a lb/MMBtu basis for SO2(regardless of the SO2emission level during the RATA), and for 

NOXwhen the average NOXemission rate measured by the reference method during the RATA is less 

than 0.100 lb/MMBtu; 

(5) If the owner or operator elects to implement the alternative data assessment procedures described in 

paragraphs (w)(2) through (w)(4) of this section, each data assessment report shall include a summary 

of the results of all of the RATAs, linearity checks, CGAs, and calibration error or drift assessments 

required by paragraphs (w)(2) through (w)(4) of this section. 
Subpart Db—Standards of Performance for Industrial-Commercial-Institutional Steam 

Generating Units 

§60.42b Standard for sulfur dioxide (SO2). 

(a) Except as provided in paragraphs (b), (c), (d), or (j) of this section, on and after the date on 

which the performance test is completed or required to be completed under §60.8, whichever 

comes first, no owner or operator of an affected facility that commenced construction, 

reconstruction, or modification on or before February 28, 2005, that combusts coal or oil shall 

cause to be discharged into the atmosphere any gases that contain SO2in excess of 87 ng/J (0.20 

lb/MMBtu) or 10 percent (0.10) of the potential SO2emission rate (90 percent reduction) and the 

emission limit determined according to the following formula: 

Where: 

Es= SO2emission limit, in ng/J or lb/MMBtu heat input; 

Ka= 520 ng/J (or 1.2 lb/MMBtu); 

Kb= 340 ng/J (or 0.80 lb/MMBtu); 

Ha= Heat input from the combustion of coal, in J (MMBtu); and 

Hb= Heat input from the combustion of oil, in J (MMBtu). 

For facilities complying with the percent reduction standard, only the heat input supplied to the 

affected facility from the combustion of coal and oil is counted in this paragraph. No credit is 

provided for the heat input to the affected facility from the combustion of natural gas, wood, 

municipal-type solid waste, or other fuels or heat derived from exhaust gases from other sources, 

such as gas turbines, internal combustion engines, kilns, etc. 

(b) On and after the date on which the performance test is completed or required to be completed 

under §60.8, whichever date comes first, no owner or operator of an affected facility that 

commenced construction, reconstruction, or modification on or before February 28, 2005, that 

combusts coal refuse alone in a fluidized bed combustion steam generating unit shall cause to be 

discharged into the atmosphere any gases that contain SO2in excess of 87 ng/J (0.20 lb/MMBtu) 

or 20 percent (0.20) of the potential SO2emission rate (80 percent reduction) and 520 ng/J (1.2 

lb/MMBtu) heat input. If coal or oil is fired with coal refuse, the affected facility is subject to 

paragraph (a) or (d) of this section, as applicable. For facilities complying with the percent 

reduction standard, only the heat input supplied to the affected facility from the combustion of 

coal and oil is counted in this paragraph. No credit is provided for the heat input to the affected 

facility from the combustion of natural gas, wood, municipal-type solid waste, or other fuels or 

heat derived from exhaust gases from other sources, such as gas turbines, internal combustion 

engines, kilns, etc. 
(c) On and after the date on which the performance test is completed or is required to be 

completed under §60.8, whichever comes first, no owner or operator of an affected facility that 

combusts coal or oil, either alone or in combination with any other fuel, and that uses an 

emerging technology for the control of SO2emissions, shall cause to be discharged into the 

atmosphere any gases that contain SO2in excess of 50 percent of the potential SO2emission rate 

(50 percent reduction) and that contain SO2in excess of the emission limit determined according 

to the following formula: 

Where: 

Es= SO2 emission limit, in ng/J or lb/MM Btu heat input; 

Kc= 260 ng/J (or 0.60 lb/MMBtu); 

Kd= 170 ng/J (or 0.40 lb/MMBtu); 

Hc= Heat input from the combustion of coal, in J (MMBtu); and 

Hd= Heat input from the combustion of oil, in J (MMBtu). 

For facilities complying with the percent reduction standard, only the heat input supplied to the 

affected facility from the combustion of coal and oil is counted in this paragraph. No credit is 

provided for the heat input to the affected facility from the combustion of natural gas, wood, 

municipal-type solid waste, or other fuels, or from the heat input derived from exhaust gases 

from other sources, such as gas turbines, internal combustion engines, kilns, etc. 

(d) On and after the date on which the performance test is completed or required to be completed 

under §60.8, whichever comes first, no owner or operator of an affected facility that commenced 

construction, reconstruction, or modification on or before February 28, 2005 and listed in 

paragraphs (d)(1), (2), (3), or (4) of this section shall cause to be discharged into the atmosphere 

any gases that contain SO2in excess of 520 ng/J (1.2 lb/MMBtu) heat input if the affected facility 

combusts coal, or 215 ng/J (0.5 lb/MMBtu) heat input if the affected facility combusts oil other 

than very low sulfur oil. Percent reduction requirements are not applicable to affected facilities 

under paragraphs (d)(1), (2), (3) or (4) of this section. For facilities complying with paragraphs 

(d)(1), (2), or (3) of this section, only the heat input supplied to the affected facility from the 

combustion of coal and oil is counted in this paragraph. No credit is provided for the heat input 

to the affected facility from the combustion of natural gas, wood, municipal-type solid waste, or 

other fuels or heat derived from exhaust gases from other sources, such as gas turbines, internal 

combustion engines, kilns, etc. 

(1) Affected facilities that have an annual capacity factor for coal and oil of 30 percent (0.30) or 

less and are subject to a federally enforceable permit limiting the operation of the affected 

facility to an annual capacity factor for coal and oil of 30 percent (0.30) or less; 

(2) Affected facilities located in a noncontinental area; or 
(3) Affected facilities combusting coal or oil, alone or in combination with any fuel, in a duct 

burner as part of a combined cycle system where 30 percent (0.30) or less of the heat entering the 

steam generating unit is from combustion of coal and oil in the duct burner and 70 percent (0.70) 

or more of the heat entering the steam generating unit is from the exhaust gases entering the duct 

burner; or 

(4) The affected facility burns coke oven gas alone or in combination with natural gas or very 

low sulfur distillate oil. 

(e) Except as provided in paragraph (f) of this section, compliance with the emission limits, fuel 

oil sulfur limits, and/or percent reduction requirements under this section are determined on a 30-

day rolling average basis. 

(f) Except as provided in paragraph (j)(2) of this section, compliance with the emission limits or 

fuel oil sulfur limits under this section is determined on a 24-hour average basis for affected 

facilities that (1) have a federally enforceable permit limiting the annual capacity factor for oil to 

10 percent or less, (2) combust only very low sulfur oil, and (3) do not combust any other fuel. 

(g) Except as provided in paragraph (i) of this section and §60.45b(a), the SO2emission limits 

and percent reduction requirements under this section apply at all times, including periods of 

startup, shutdown, and malfunction. 

(h) Reductions in the potential SO2emission rate through fuel pretreatment are not credited 

toward the percent reduction requirement under paragraph (c) of this section unless: 

(1) Fuel pretreatment results in a 50 percent or greater reduction in potential SO2emissions and 

(2) Emissions from the pretreated fuel (without combustion or post-combustion SO2control) are 

equal to or less than the emission limits specified in paragraph (c) of this section. 

(i) An affected facility subject to paragraph (a), (b), or (c) of this section may combust very low 

sulfur oil or natural gas when the SO2control system is not being operated because of 

malfunction or maintenance of the SO2control system. 

(j) Percent reduction requirements are not applicable to affected facilities combusting only very 

low sulfur oil. The owner or operator of an affected facility combusting very low sulfur oil shall 

demonstrate that the oil meets the definition of very low sulfur oil by: (1) Following the 

performance testing procedures as described in §60.45b(c) or §60.45b(d), and following the 

monitoring procedures as described in §60.47b(a) or §60.47b(b) to determine SO2emission rate 

or fuel oil sulfur content; or (2) maintaining fuel records as described in §60.49b(r). 

(k)(1) Except as provided in paragraphs (k)(2), (k)(3), and (k)(4) of this section, on and after the 

date on which the initial performance test is completed or is required to be completed under 

§60.8, whichever date comes first, no owner or operator of an affected facility that commences 

construction, reconstruction, or modification after February 28, 2005, and that combusts coal, oil, 

natural gas, a mixture of these fuels, or a mixture of these fuels with any other fuels shall cause 

to be discharged into the atmosphere any gases that contain SO2in excess of 87 ng/J (0.20 

lb/MMBtu) heat input or 8 percent (0.08) of the potential SO2emission rate (92 percent 

reduction) and 520 ng/J (1.2 lb/MMBtu) heat input. For facilities complying with the percent 
reduction standard and paragraph (k)(3) of this section, only the heat input supplied to the 

affected facility from the combustion of coal and oil is counted in paragraph (k) of this section. 

No credit is provided for the heat input to the affected facility from the combustion of natural 

gas, wood, municipal-type solid waste, or other fuels or heat derived from exhaust gases from 

other sources, such as gas turbines, internal combustion engines, kilns, etc. 

(2) Units firing only very low sulfur oil, gaseous fuel, a mixture of these fuels, or a mixture of 

these fuels with any other fuels with a potential SO2emission rate of 140 ng/J (0.32 lb/MMBtu) 

heat input or less are exempt from the SO2emissions limit in paragraph (k)(1) of this section. 

(3) Units that are located in a noncontinental area and that combust coal, oil, or natural gas shall 

not discharge any gases that contain SO2in excess of 520 ng/J (1.2 lb/MMBtu) heat input if the 

affected facility combusts coal, or 215 ng/J (0.50 lb/MMBtu) heat input if the affected facility 

combusts oil or natural gas.

(4) As an alternative to meeting the requirements under paragraph (k)(1) of this section, 

modified facilities that combust coal or a mixture of coal with other fuels shall not cause to be 

discharged into the atmosphere any gases that contain SO2 in excess of 87 ng/J (0.20 lb/MMBtu) 

heat input or 10 percent (0.10) of the potential SO2 emission rate (90 percent reduction) and 520 

ng/J (1.2 lb/MMBtu) heat input.

§60.46b Compliance and performance test methods and procedures for particulate matter 

and nitrogen oxides. 

(a) The PM emission standards and opacity limits under §60.43b apply at all times except during 

periods of startup, shutdown, or malfunction. The NOXemission standards under §60.44b apply 

at all times. 

(b) Compliance with the PM emission standards under §60.43b shall be determined through 

performance testing as described in paragraph (d) of this section, except as provided in paragraph 

(i) of this section. 

(c) Compliance with the NOXemission standards under §60.44b shall be determined through 

performance testing under paragraph (e) or (f), or under paragraphs (g) and (h) of this section, as 

applicable. 

(d) To determine compliance with the PM emission limits and opacity limits under §60.43b, the 

owner or operator of an affected facility shall conduct an initial performance test as required 

under §60.8, and shall conduct subsequent performance tests as requested by the Administrator, 

using the following procedures and reference methods: 

(1) Method 3A or 3B of appendix A–2 of this part is used for gas analysis when applying 

Method 5 of appendix A–3 of this part or Method 17 of appendix A–6 of this part. 

(2) Method 5, 5B, or 17 of appendix A of this part shall be used to measure the concentration of 

PM as follows: 

(i) Method 5 of appendix A of this part shall be used at affected facilities without wet flue gas 

desulfurization (FGD) systems; and 

Comment [CF1]: Correct FR mistake – never

intended to delete paragraph 60.42b(k)(4)
(ii) Method 17 of appendix A–6 of this part may be used at facilities with or without wet 

scrubber systems provided the stack gas temperature does not exceed a temperature of 160 °C 

(320 °F). The procedures of sections 8.1 and 11.1 of Method 5B of appendix A–3 of this part 

may be used in Method 17 of appendix A–6 of this part only if it is used after a wet FGD system. 

Do not use Method 17 of appendix A–6 of this part after wet FGD systems if the effluent is 

saturated or laden with water droplets. 

(iii) Method 5B of appendix A of this part is to be used only after wet FGD systems. 

(3) Method 1 of appendix A of this part is used to select the sampling site and the number of 

traverse sampling points. The sampling time for each run is at least 120 minutes and the 

minimum sampling volume is 1.7 dscm (60 dscf) except that smaller sampling times or volumes 

may be approved by the Administrator when necessitated by process variables or other factors. 

(4) For Method 5 of appendix A of this part, the temperature of the sample gas in the probe and 

filter holder is monitored and is maintained at 160±14 °C (320±25 °F). 

(5) For determination of PM emissions, the oxygen (O2) or CO2sample is obtained 

simultaneously with each run of Method 5, 5B, or 17 of appendix A of this part by traversing the 

duct at the same sampling location. 

(6) For each run using Method 5, 5B, or 17 of appendix A of this part, the emission rate 

expressed in ng/J heat input is determined using: 

(i) The O2or CO2measurements and PM measurements obtained under this section; 

(ii) The dry basis F factor; and 

(iii) The dry basis emission rate calculation procedure contained in Method 19 of appendix A of 

this part. 

(7) Method 9 of appendix A of this part is used for determining the opacity of stack emissions. 

(e) To determine compliance with the emission limits for NOXrequired under §60.44b, the owner 

or operator of an affected facility shall conduct the performance test as required under §60.8 

using the continuous system for monitoring NOXunder §60.48(b). 

(1) For the initial compliance test, NOXfrom the steam generating unit are monitored for 30 

successive steam generating unit operating days and the 30-day average emission rate is used to 

determine compliance with the NOXemission standards under §60.44b. The 30-day average 

emission rate is calculated as the average of all hourly emissions data recorded by the monitoring 

system during the 30-day test period. 

(2) Following the date on which the initial performance test is completed or is required to be 

completed in §60.8, whichever date comes first, the owner or operator of an affected facility 

which combusts coal (except as specified under §60.46b(e)(4)) or which combusts residual oil 

having a nitrogen content greater than 0.30 weight percent shall determine compliance with the 

NOXemission standards in §60.44b on a continuous basis through the use of a 30-day rolling 

average emission rate. A new 30-day rolling average emission rate is calculated for each steam 
generating unit operating day as the average of all of the hourly NOXemission data for the 

preceding 30 steam generating unit operating days. 

(3) Following the date on which the initial performance test is completed or is required to be 

completed under §60.8, whichever date comes first, the owner or operator of an affected facility 

that has a heat input capacity greater than 73 MW (250 MMBtu/hr) and that combusts natural 

gas, distillate oil, or residual oil having a nitrogen content of 0.30 weight percent or less shall 

determine compliance with the NOXstandards under §60.44b on a continuous basis through the 

use of a 30-day rolling average emission rate. A new 30-day rolling average emission rate is 

calculated each steam generating unit operating day as the average of all of the hourly 

NOXemission data for the preceding 30 steam generating unit operating days. 

(4) Following the date on which the initial performance test is completed or required to be 

completed under §60.8, whichever date comes first, the owner or operator of an affected facility 

that has a heat input capacity of 73 MW (250 MMBtu/hr) or less and that combusts natural gas, 

distillate oil, gasified coal, or residual oil having a nitrogen content of 0.30 weight percent or less 

shall upon request determine compliance with the NOXstandards in §60.44b through the use of a 

30-day performance test. During periods when performance tests are not requested, 

NOXemissions data collected pursuant to §60.48b(g)(1) or §60.48b(g)(2) are used to calculate a 

30-day rolling average emission rate on a daily basis and used to prepare excess emission 

reports, but will not be used to determine compliance with the NOXemission standards. A new 

30-day rolling average emission rate is calculated each steam generating unit operating day as 

the average of all of the hourly NOXemission data for the preceding 30 steam generating unit 

operating days. 

(5) If the owner or operator of an affected facility that combusts residual oil does not sample and 

analyze the residual oil for nitrogen content, as specified in §60.49b(e), the requirements of 

§60.48b(g)(1) apply and the provisions of §60.48b(g)(2) are inapplicable. 

(f) To determine compliance with the emissions limits for NOXrequired by §60.44b(a)(4) or 

§60.44b(l) for duct burners used in combined cycle systems, either of the procedures described in 

paragraph (f)(1) or (2) of this section may be used: 

(1) The owner or operator of an affected facility shall conduct the performance test required 

under §60.8 as follows: 

(i) The emissions rate (E) of NOXshall be computed using Equation 1 in this section: 

Where: 

E = Emissions rate of NOXfrom the duct burner, ng/J (lb/MMBtu) heat input; 

Esg= Combined effluent emissions rate, in ng/J (lb/MMBtu) heat input using appropriate F factor 

as described in Method 19 of appendix A of this part; 

The image cannot be displayed. Your computer may not have enough memory to open the image, or the image may have been corrupted. Restart your computer, and then open the file again. If the red x still appears, you may have to delete the image and then insert it again.
Hg= Heat input rate to the combustion turbine, in J/hr (MMBtu/hr); 

Hb= Heat input rate to the duct burner, in J/hr (MMBtu/hr); and 

Eg= Emissions rate from the combustion turbine, in ng/J (lb/MMBtu) heat input calculated using 

appropriate F factor as described in Method 19 of appendix A of this part. 

(ii) Method 7E of appendix A of this part shall be used to determine the NOXconcentrations. 

Method 3A or 3B of appendix A of this part shall be used to determine O2concentration. 

(iii) The owner or operator shall identify and demonstrate to the Administrator's satisfaction 

suitable methods to determine the average hourly heat input rate to the combustion turbine and 

the average hourly heat input rate to the affected duct burner. 

(iv) Compliance with the emissions limits under §60.44b(a)(4) or §60.44b(l) is determined by the 

three-run average (nominal 1-hour runs) for the initial and subsequent performance tests; or 

(2) The owner or operator of an affected facility may elect to determine compliance on a 30-day 

rolling average basis by using the CEMS specified under §60.48b for measuring NOXand O2and 

meet the requirements of §60.48b. The sampling site shall be located at the outlet from the steam 

generating unit. The NOXemissions rate at the outlet from the steam generating unit shall 

constitute the NOXemissions rate from the duct burner of the combined cycle system. 

(g) The owner or operator of an affected facility described in §60.44b(j) or §60.44b(k) shall 

demonstrate the maximum heat input capacity of the steam generating unit by operating the 

facility at maximum capacity for 24 hours. The owner or operator of an affected facility shall 

determine the maximum heat input capacity using the heat loss method or the heat input method 

described in sections 5 and 7.3 of the ASME Power Test Codes 4.1 (incorporated by reference, 

see §60.17). This demonstration of maximum heat input capacity shall be made during the initial 

performance test for affected facilities that meet the criteria of §60.44b(j). It shall be made within 

60 days after achieving the maximum production rate at which the affected facility will be 

operated, but not later than 180 days after initial start-up of each facility, for affected facilities 

meeting the criteria of §60.44b(k). Subsequent demonstrations may be required by the 

Administrator at any other time. If this demonstration indicates that the maximum heat input 

capacity of the affected facility is less than that stated by the manufacturer of the affected 

facility, the maximum heat input capacity determined during this demonstration shall be used to 

determine the capacity utilization rate for the affected facility. Otherwise, the maximum heat 

input capacity provided by the manufacturer is used. 

(h) The owner or operator of an affected facility described in §60.44b(j) that has a heat input 

capacity greater than 73 MW (250 MMBtu/hr) shall: 

(1) Conduct an initial performance test as required under §60.8 over a minimum of 24 

consecutive steam generating unit operating hours at maximum heat input capacity to 

demonstrate compliance with the NOXemission standards under §60.44b using Method 7, 7A, 7E 

of appendix A of this part, or other approved reference methods; and 

(2) Conduct subsequent performance tests once per calendar year or every 400 hours of operation 

(whichever comes first) to demonstrate compliance with the NOXemission standards under 
§60.44b over a minimum of 3 consecutive steam generating unit operating hours at maximum 

heat input capacity using Method 7, 7A, 7E of appendix A of this part, or other approved 

reference methods. 

(i) The owner or operator of an affected facility seeking to demonstrate compliance with the PM 

limit in paragraphs §60.43b(a)(4) or §60.43b(h)(5) shall follow the applicable procedures in 

§60.49b(r). 

(j) In place of PM testing with Method 5 or 5B of appendix A–3 of this part, or Method 17 of 

appendix A–6 of this part, an owner or operator may elect to install, calibrate, maintain, and 

operate a CEMS for monitoring PM emissions discharged to the atmosphere and record the 

output of the system. The owner or operator of an affected facility who elects to continuously 

monitor PM emissions instead of conducting performance testing using Method 5 or 5B of 

appendix A–3 of this part or Method 17 of appendix A–6 of this part shall comply with the 

requirements specified in paragraphs (j)(1) through (j)(14) of this section. 

(1) Notify the Administrator one month before starting use of the system. 

(2) Notify the Administrator one month before stopping use of the system. 

(3) The monitor shall be installed, evaluated, and operated in accordance with §60.13 of subpart 

A of this part. 

(4) The initial performance evaluation shall be completed no later than 180 days after the date of 

initial startup of the affected facility, as specified under §60.8 of subpart A of this part or within 

180 days of notification to the Administrator of use of the CEMS if the owner or operator was 

previously determining compliance by Method 5, 5B, or 17 of appendix A of this part 

performance tests, whichever is later. 

(5) The owner or operator of an affected facility shall conduct an initial performance test for PM 

emissions as required under §60.8 of subpart A of this part. Compliance with the PM emission 

limit shall be determined by using the CEMS specified in paragraph (j) of this section to measure 

PM and calculating a 24-hour block arithmetic average emission concentration using EPA 

Reference Method 19 of appendix A of this part, section 4.1. 

(6) Compliance with the PM emission limit shall be determined based on the 24-hour daily 

(block) average of the hourly arithmetic average emission concentrations using CEMS outlet 

data. 

(7) At a minimum, valid CEMS hourly averages shall be obtained as specified in paragraphs 

(j)(7)(i) of this section for 75 percent of the total operating hours per 30-day rolling average. 

(i) At least two data points per hour shall be used to calculate each 1-hour arithmetic average. 

(ii) [Reserved] 

(8) The 1-hour arithmetic averages required under paragraph (j)(7) of this section shall be 

expressed in ng/J or lb/MMBtu heat input and shall be used to calculate the boiler operating day 

daily arithmetic average emission concentrations. The 1-hour arithmetic averages shall be 

calculated using the data points required under §60.13(e)(2) of subpart A of this part. 
(9) All valid CEMS data shall be used in calculating average emission concentrations even if the 

minimum CEMS data requirements of paragraph (j)(7) of this section are not met. 

(10) The CEMS shall be operated according to Performance Specification 11 in appendix B of 

this part. 

(11) During the correlation testing runs of the CEMS required by Performance Specification 11 

in appendix B of this part, PM and O2(or CO2) data shall be collected concurrently (or within a 

30-to 60-minute period) by both the continuous emission monitors and performance tests 

conducted using the following test methods. 

(i) For PM, Method 5 or 5B of appendix A–3 of this part or Method 17 of appendix A–6 of this 

part shall be used; and 

(ii) After July 1, 2010 or after Method 202 of appendix M of part 51 has been revised to 

minimize artifact measurement and notice of that change has been published in theFederal 

Register,whichever is later, for condensable PM emissions, Method 202 of appendix M of part 

51 shall be used; and

(iii) For O2(or CO2), Method 3A or 3B of appendix A–2 of this part, as applicable shall be used. 

(12) Quarterly accuracy determinations and daily calibration drift tests shall be performed in 

accordance with procedure 2 in appendix F of this part. Relative Response Audit's must be 

performed annually and Response Correlation Audits must be performed every 3 years. 

(13) When PM emissions data are not obtained because of CEMS breakdowns, repairs, 

calibration checks, and zero and span adjustments, emissions data shall be obtained by using 

other monitoring systems as approved by the Administrator or EPA Reference Method 19 of 

appendix A of this part to provide, as necessary, valid emissions data for a minimum of 75 

percent of total operating hours per 30-day rolling average. 

(14) After July 1, 2011, within 90 days after completing a correlation testing run, the owner or 

operator of an affected facility shall either successfully enter the test data into EPA's WebFIRE 

data base located at http://cfpub.epa.gov/oarweb/index.cfm?action=fire.main or mail a copy to: 

United States Environmental Protection Agency; Energy Strategies Group; 109 TW Alexander 

DR; Mail Code: D243–01; RTP, NC 27711. 

§60.48b Emission monitoring for particulate matter and nitrogen oxides. 

(a) Except as provided in paragraph (j) of this section, the owner or operator of an affected 

facility subject to the opacity standard under §60.43b shall install, calibrate, maintain, and 

operate a continuous opacity monitoring systems (COMS) for measuring the opacity of 

emissions discharged to the atmosphere and record the output of the system. The owner or 

operator of an affected facility subject to an opacity standard under §60.43b and meeting the 

conditions under paragraphs (j)(1), (2), (3), (4), or (5) of this section who elects not to use install 

a COMS shall conduct a performance test using Method 9 of appendix A–4 of this part and the 

procedures in §60.11 to demonstrate compliance with the applicable limit in §60.43b by April

29, 2011, within 45 days of stopping use of an existing COMS, or 180 days after initial startup of 

the facility, whichever is later, and shall comply with either paragraphs (a)(1), (a)(2), or (a)(3) of 
this section. The observation period for Method 9 of appendix A-4 of this part performance tests 

may be reduced from 3 hours to 60 minutes if all 6-minute averages are less than 10 percent and 

all individual 15-second observations are less than or equal to 20 percent during the initial 60 

minutes of observation.If during the initial 60 minutes of observation all 6-minute averages are 

less than 10 percent and all individual 15-second observations are less than or equal to 20 

percent, the observation period may be reduced from 3 hours to 60 minutes.

(1) Except as provided in paragraph (a)(2) and (a)(3) of this section, the owner or operator shall 

conduct subsequent Method 9 of appendix A–4 of this part performance tests using the 

procedures in paragraph (a) of this section according to the applicable schedule in paragraphs 

(a)(1)(i) through (a)(1)(iv) of this section, as determined by the most recent Method 9 of 

appendix A–4 of this part performance test results. 

(i) If no visible emissions are observed, a subsequent Method 9 of appendix A–4 of this part 

performance test must be completed within 12 calendar months from the date that the most 

recent performance test was conducted; 

(ii) If visible emissions are observed but the maximum 6-minute average opacity is less than or 

equal to 5 percent, a subsequent Method 9 of appendix A–4 of this part performance test must be 

completed within 6 calendar months from the date that the most recent performance test was 

conducted; 

(iii) If the maximum 6-minute average opacity is greater than 5 percent but less than or equal to 

10 percent, a subsequent Method 9 of appendix A–4 of this part performance test must be 

completed within 3 calendar months from the date that the most recent performance test was 

conducted; or 

(iv) If the maximum 6-minute average opacity is greater than 10 percent, a subsequent Method 9 

of appendix A–4 of this part performance test must be completed within 4530 calendar days 

from the date that the most recent performance test was conducted. 

(2) If the maximum 6-minute opacity is less than 10 percent during the most recent Method 9 of 

appendix A–4 of this part performance test, the owner or operator may, as an alternative to 

performing subsequent Method 9 of appendix A–4 of this part performance tests, elect to 

perform subsequent monitoring using Method 22 of appendix A–7 of this part according to the 

procedures specified in paragraphs (a)(2)(i) and (ii) of this section. 

(i) The owner or operator shall conduct 10 minute observations (during normal operation) each 

operating day the affected facility fires fuel for which an opacity standard is applicable using 

Method 22 of appendix A–7 of this part and demonstrate that the sum of the occurrences of any 

visible emissions is not in excess of 5 percent of the observation period ( i.e. , 30 seconds per 10 

minute period). If the sum of the occurrence of any visible emissions is greater than 30 seconds 

during the initial 10 minute observation, immediately conduct a 30 minute observation. If the 

sum of the occurrence of visible emissions is greater than 5 percent of the observation period ( 

i.e. , 90 seconds per 30 minute period), the owner or operator shall either document and adjust 

the operation of the facility and demonstrate within 24 hours that the sum of the occurrence of 

visible emissions is equal to or less than 5 percent during a 30 minute observation ( i.e. , 90 

seconds) or conduct a new Method 9 of appendix A–4 of this part performance test using the 
procedures in paragraph (a) of this section within 4530 calendar days according to the 

requirements in §60.46d(d)(7). 

(ii) If no visible emissions are observed for 30 operating days during which an opacity standard 

is applicable, observations can be reduced to once every 7 operating days during which an 

opacity standard is applicable. If any visible emissions are observed, daily observations shall be 

resumed. 

(3) If the maximum 6-minute opacity is less than 10 percent during the most recent Method 9 of 

appendix A–4 of this part performance test, the owner or operator may, as an alternative to 

performing subsequent Method 9 of appendix A–4 performance tests, elect to perform 

subsequent monitoring using a digital opacity compliance system according to a site-specific 

monitoring plan approved by the Administrator. The observations shall be similar, but not 

necessarily identical, to the requirements in paragraph (a)(2) of this section. For reference 

purposes in preparing the monitoring plan, see OAQPS “Determination of Visible Emission 

Opacity from Stationary Sources Using Computer-Based Photographic Analysis Systems.” This 

document is available from the U.S. Environmental Protection Agency (U.S. EPA); Office of Air 

Quality and Planning Standards; Sector Policies and Programs Division; Measurement Policy 

Group (D243–02), Research Triangle Park, NC 27711. This document is also available on the 

Technology Transfer Network (TTN) under Emission Measurement Center Preliminary 

Methods. 

(b) Except as provided under paragraphs (g), (h), and (i) of this section, the owner or operator of 

an affected facility subject to a NOXstandard under §60.44b shall comply with either paragraphs 

(b)(1) or (b)(2) of this section. 

(1) Install, calibrate, maintain, and operate CEMS for measuring NOXand O2(or CO2) emissions 

discharged to the atmosphere, and shall record the output of the system; or 

(2) If the owner or operator has installed a NOXemission rate CEMS to meet the requirements of 

part 75 of this chapter and is continuing to meet the ongoing requirements of part 75 of this 

chapter, that CEMS may be used to meet the requirements of this section, except that the owner 

or operator shall also meet the requirements of §60.49b. Data reported to meet the requirements 

of §60.49b shall not include data substituted using the missing data procedures in subpart D of 

part 75 of this chapter, nor shall the data have been bias adjusted according to the procedures of 

part 75 of this chapter. 

(c) The CEMS required under paragraph (b) of this section shall be operated and data recorded 

during all periods of operation of the affected facility except for CEMS breakdowns and repairs. 

Data is recorded during calibration checks, and zero and span adjustments. 

(d) The 1-hour average NOXemission rates measured by the continuous NOXmonitor required by 

paragraph (b) of this section and required under §60.13(h) shall be expressed in ng/J or 

lb/MMBtu heat input and shall be used to calculate the average emission rates under §60.44b. 

The 1-hour averages shall be calculated using the data points required under §60.13(h)(2). 

(e) The procedures under §60.13 shall be followed for installation, evaluation, and operation of 

the continuous monitoring systems. 
(1) For affected facilities combusting coal, wood or municipal-type solid waste, the span value 

for a COMS shall be between 60 and 80 percent. 

(2) For affected facilities combusting coal, oil, or natural gas, the span value for NOXis 

determined using one of the following procedures: 

(i) Except as provided under paragraph (e)(2)(ii) of this section, NOXspan values shall be 

determined as follows: 

Fuel Span values for NOX

(ppm) 

Natural gas 500. 

Oil 500. 

Coal 1,000. 

Mixtures 500 (x + y) + 1,000z. 

Where: 

x = Fraction of total heat input derived from natural gas; 

y = Fraction of total heat input derived from oil; and 

z = Fraction of total heat input derived from coal. 

(ii) As an alternative to meeting the requirements of paragraph (e)(2)(i) of this section, the owner 

or operator of an affected facility may elect to use the NOXspan values determined according to 

section 2.1.2 in appendix A to part 75 of this chapter. 

(3) All span values computed under paragraph (e)(2)(i) of this section for combusting mixtures 

of regulated fuels are rounded to the nearest 500 ppm. Span values computed under paragraph 

(e)(2)(ii) of this section shall be rounded off according to section 2.1.2 in appendix A to part 75 

of this chapter. 

(f) When NOXemission data are not obtained because of CEMS breakdowns, repairs, calibration 

checks and zero and span adjustments, emission data will be obtained by using standby 

monitoring systems, Method 7 of appendix A of this part, Method 7A of appendix A of this part, 

or other approved reference methods to provide emission data for a minimum of 75 percent of 

the operating hours in each steam generating unit operating day, in at least 22 out of 30 

successive steam generating unit operating days. 

(g) The owner or operator of an affected facility that has a heat input capacity of 73 MW (250 

MMBtu/hr) or less, and that has an annual capacity factor for residual oil having a nitrogen 

content of 0.30 weight percent or less, natural gas, distillate oil, gasified coal, or any mixture of 

these fuels, greater than 10 percent (0.10) shall: 

(1) Comply with the provisions of paragraphs (b), (c), (d), (e)(2), (e)(3), and (f) of this section; or 
(2) Monitor steam generating unit operating conditions and predict NOXemission rates as 

specified in a plan submitted pursuant to §60.49b(c). 

(h) The owner or operator of a duct burner, as described in §60.41b, that is subject to the 

NOXstandards in §60.44b(a)(4), §60.44b(e), or §60.44b(l) is not required to install or operate a 

continuous emissions monitoring system to measure NOXemissions. 

(i) The owner or operator of an affected facility described in §60.44b(j) or §60.44b(k) is not 

required to install or operate a CEMS for measuring NOXemissions. 

(j) The owner or operator of an affected facility that meets the conditions in either paragraph 

(j)(1), (2), (3), (4), (5), or (6) of this section is not required to install or operate a COMS if: 

(1) The affected facility uses a PM CEMS to monitor PM emissions; or 

(2) The affected facility burns only liquid (excluding residual oil) or gaseous fuels with potential 

SO2emissions rates of 26 ng/J (0.060 lb/MMBtu) or less and does not use a post-combustion 

technology to reduce SO2or PM emissions. The owner or operator must maintain fuel records of 

the sulfur content of the fuels burned, as described under §60.49b(r); or 

(3) The affected facility burns coke oven gas alone or in combination with fuels meeting the 

criteria in paragraph (j)(2) of this section and does not use a post-combustion technology to 

reduce SO2or PM emissions; or 

(4) The affected facility does not use post-combustion technology (except a wet scrubber) for 

reducing PM, SO2, or carbon monoxide (CO) emissions, burns only gaseous fuels or fuel oils 

that contain less than or equal to 0.30 weight percent sulfur, and is operated such that emissions 

of CO to the atmosphere from the affected facility are maintained at levels less than or equal to 

0.15 lb/MMBtu on a steam generating unit operating day average basis. Owners and operators of 

affected facilities electing to comply with this paragraph must demonstrate compliance according 

to the procedures specified in paragraphs (j)(4)(i) through (iv) of this section; or 

(i) You must monitor CO emissions using a CEMS according to the procedures specified in 

paragraphs (j)(4)(i)(A) through (D) of this section. 

(A) The CO CEMS must be installed, certified, maintained, and operated according to the 

provisions in §60.58b(i)(3) of subpart Eb of this part. 

(B) Each 1-hour CO emissions average is calculated using the data points generated by the CO 

CEMS expressed in parts per million by volume corrected to 3 percent oxygen (dry basis). 

(C) At a minimum, valid 1-hour CO emissions averages must be obtained for at least 90 percent 

of the operating hours on a 30-day rolling average basis. The 1-hour averages are calculated 

using the data points required in §60.13(h)(2). 

(D) Quarterly accuracy determinations and daily calibration drift tests for the CO CEMS must be 

performed in accordance with procedure 1 in appendix F of this part. 

(ii) You must calculate the 1-hour average CO emissions levels for each steam generating unit 

operating day by multiplying the average hourly CO output concentration measured by the CO 
CEMS times the corresponding average hourly flue gas flow rate and divided by the 

corresponding average hourly heat input to the affected source. The 24-hour average CO 

emission level is determined by calculating the arithmetic average of the hourly CO emission 

levels computed for each steam generating unit operating day. 

(iii) You must evaluate the preceding 24-hour average CO emission level each steam generating 

unit operating day excluding periods of affected source startup, shutdown, or malfunction. If the 

24-hour average CO emission level is greater than 0.15 lb/MMBtu, you must initiate 

investigation of the relevant equipment and control systems within 24 hours of the first discovery 

of the high emission incident and, take the appropriate corrective action as soon as practicable to 

adjust control settings or repair equipment to reduce the 24-hour average CO emission level to 

0.15 lb/MMBtu or less. 

(iv) You must record the CO measurements and calculations performed according to paragraph 

(j)(4) of this section and any corrective actions taken. The record of corrective action taken must 

include the date and time during which the 24-hour average CO emission level was greater than 

0.15 lb/MMBtu, and the date, time, and description of the corrective action. 

(5) The affected facility uses a bag leak detection system to monitor the performance of a fabric 

filter (baghouse) according to the most recent requirements in section §60.48Da of this part; or 

(6) The affected facility burns only gaseous fuels or fuel oils that contain less than or equal to 

0.30 weight percent sulfur and operates according to a written site-specific monitoring plan 

approved by the permitting authority. This monitoring plan must include procedures and criteria 

for establishing and monitoring specific parameters for the affected facility indicative of 

compliance with the opacity standard. 

(k) Owners or operators complying with the PM emission limit by using a PM CEMS must 

calibrate, maintain, operate, and record the output of the system for PM emissions discharged to 

the atmosphere as specified in §60.46b(j). The CEMS specified in paragraph §60.46b(j) shall be 

operated and data recorded during all periods of operation of the affected facility except for 

CEMS breakdowns and repairs. Data is recorded during calibration checks, and zero and span 

adjustments. 
Subpart Dc—Standards of Performance for Small Industrial-Commercial-Institutional Steam 

Generating Units 

§60.45c Compliance and performance test methods and procedures for particulate matter. 

(a) The owner or operator of an affected facility subject to the PM and/or opacity standards under 

§60.43c shall conduct an initial performance test as required under §60.8, and shall conduct subsequent 

performance tests as requested by the Administrator, to determine compliance with the standards using 

the following procedures and reference methods, except as specified in paragraph (c) of this section. 

(1) Method 1 of appendix A of this part shall be used to select the sampling site and the number of 

traverse sampling points. 

(2) Method 3A or 3B of appendix A–2 of this part shall be used for gas analysis when applying 

Method 5 or 5B of appendix A–3 of this part or 17 of appendix A–6 of this part. 

(3) Method 5, 5B, or 17 of appendix A of this part shall be used to measure the concentration of PM as 

follows: 

(i) Method 5 of appendix A of this part may be used only at affected facilities without wet scrubber 

systems. 

(ii) Method 17 of appendix A of this part may be used at affected facilities with or without wet 

scrubber systems provided the stack gas temperature does not exceed a temperature of 160 °C (320 

°F). The procedures of Sections 8.1 and 11.1 of Method 5B of appendix A of this part may be used in 

Method 17 of appendix A of this part only if Method 17 of appendix A of this part is used in 

conjunction with a wet scrubber system. Method 17 of appendix A of this part shall not be used in 

conjunction with a wet scrubber system if the effluent is saturated or laden with water droplets. 

(iii) Method 5B of appendix A of this part may be used in conjunction with a wet scrubber system. 

(4) The sampling time for each run shall be at least 120 minutes and the minimum sampling volume 

shall be 1.7 dry standard cubic meters (dscm) [60 dry standard cubic feet (dscf)] except that smaller 

sampling times or volumes may be approved by the Administrator when necessitated by process 

variables or other factors. 

(5) For Method 5 or 5B of appendix A of this part, the temperature of the sample gas in the probe and 

filter holder shall be monitored and maintained at 160 ±14 °C (320±25 °F). 

(6) For determination of PM emissions, an oxygen (O2) or carbon dioxide (CO2) measurement shall be 

obtained simultaneously with each run of Method 5, 5B, or 17 of appendix A of this part by traversing 

the duct at the same sampling location. 

(7) For each run using Method 5, 5B, or 17 of appendix A of this part, the emission rates expressed in 

ng/J (lb/MMBtu) heat input shall be determined using: 

(i) The O2or CO2measurements and PM measurements obtained under this section, (ii) The dry basis F 

factor, and 

(iii) The dry basis emission rate calculation procedure contained in Method 19 of appendix A of this 

part. 
(8) Method 9 of appendix A–4 of this part shall be used for determining the opacity of stack emissions. 

(b) The owner or operator of an affected facility seeking to demonstrate compliance with the PM 

standards under §60.43c(b)(2) shall demonstrate the maximum design heat input capacity of the steam 

generating unit by operating the steam generating unit at this capacity for 24 hours. This demonstration 

shall be made during the initial performance test, and a subsequent demonstration may be requested at 

any other time. If the demonstrated 24-hour average firing rate for the affected facility is less than the 

maximum design heat input capacity stated by the manufacturer of the affected facility, the 

demonstrated 24-hour average firing rate shall be used to determine the annual capacity factor for the 

affected facility; otherwise, the maximum design heat input capacity provided by the manufacturer 

shall be used. 

(c) In place of PM testing with Method 5 or 5B of appendix A–3 of this part or Method 17 of appendix 

A–6 of this part, an owner or operator may elect to install, calibrate, maintain, and operate a CEMS for 

monitoring PM emissions discharged to the atmosphere and record the output of the system. The 

owner or operator of an affected facility who elects to continuously monitor PM emissions instead of 

conducting performance testing using Method 5 or 5B of appendix A–3 of this part or Method 17 of 

appendix A–6 of this part shall install, calibrate, maintain, and operate a CEMS and shall comply with 

the requirements specified in paragraphs (c)(1) through (c)(14) of this section. 

(1) Notify the Administrator 1 month before starting use of the system. 

(2) Notify the Administrator 1 month before stopping use of the system. 

(3) The monitor shall be installed, evaluated, and operated in accordance with §60.13 of subpart A of 

this part. 

(4) The initial performance evaluation shall be completed no later than 180 days after the date of initial 

startup of the affected facility, as specified under §60.8 of subpart A of this part or within 180 days of 

notification to the Administrator of use of CEMS if the owner or operator was previously determining 

compliance by Method 5, 5B, or 17 of appendix A of this part performance tests, whichever is later. 

(5) The owner or operator of an affected facility shall conduct an initial performance test for PM 

emissions as required under §60.8 of subpart A of this part. Compliance with the PM emission limit 

shall be determined by using the CEMS specified in paragraph (d) of this section to measure PM and 

calculating a 24-hour block arithmetic average emission concentration using EPA Reference Method 

19 of appendix A of this part, section 4.1. 

(6) Compliance with the PM emission limit shall be determined based on the 24-hour daily (block) 

average of the hourly arithmetic average emission concentrations using CEMS outlet data. 

(7) At a minimum, valid CEMS hourly averages shall be obtained as specified in paragraph (c)(7)(i) of 

this section for 75 percent of the total operating hours per 30-day rolling average. 

(i) At least two data points per hour shall be used to calculate each 1-hour arithmetic average. 

(ii) [Reserved] 

(8) The 1-hour arithmetic averages required under paragraph (c)(7) of this section shall be expressed in 

ng/J or lb/MMBtu heat input and shall be used to calculate the boiler operating day daily arithmetic 
average emission concentrations. The 1-hour arithmetic averages shall be calculated using the data 

points required under §60.13(e)(2) of subpart A of this part. 

(9) All valid CEMS data shall be used in calculating average emission concentrations even if the 

minimum CEMS data requirements of paragraph (c)(7) of this section are not met. 

(10) The CEMS shall be operated according to Performance Specification 11 in appendix B of this 

part. 

(11) During the correlation testing runs of the CEMS required by Performance Specification 11 in 

appendix B of this part, PM and O2(or CO2) data shall be collected concurrently (or within a 30- to 60-

minute period) by both the continuous emission monitors and performance tests conducted using the 

following test methods. 

(i) For PM, Method 5 or 5B of appendix A–3 of this part or Method 17 of appendix A–6 of this part 

shall be used; and 

(ii) After July 1, 2010 or after Method 202 of appendix M of part 51 has been revised to minimize 

artifact measurement and notice of that change has been published in theFederal Register,whichever is 

later, for condensable PM emissions, Method 202 of appendix M of part 51 shall be used; and

(iii) For O2 (or CO2), Method 3A or 3B of appendix A–2 of this part, as applicable shall be used. 

(12) Quarterly accuracy determinations and daily calibration drift tests shall be performed in 

accordance with procedure 2 in appendix F of this part. Relative Response Audit's must be performed 

annually and Response Correlation Audits must be performed every 3 years. 

(13) When PM emissions data are not obtained because of CEMS breakdowns, repairs, calibration 

checks, and zero and span adjustments, emissions data shall be obtained by using other monitoring 

systems as approved by the Administrator or EPA Reference Method 19 of appendix A of this part to 

provide, as necessary, valid emissions data for a minimum of 75 percent of total operating hours on a 

30-day rolling average. 

(14) After July 1, 2011, within 90 days after the date of completing each performance evaluation 

required by paragraph (c)(11) of this section, the owner or operator of the affected facility must either 

submit the test data to EPA by successfully entering the data electronically into EPA's WebFIRE data 

base available at http://cfpub.epa.gov/oarweb/index.cfm?action=fire.main or mail a copy to: United 

States Environmental Protection Agency; Energy Strategies Group; 109 TW Alexander DR; Mail 

Code: D243–01; RTP, NC 27711. 

(d) The owner or operator of an affected facility seeking to demonstrate compliance under 

§60.43c(e)(4) shall follow the applicable procedures under §60.48c(f). For residual oil-fired affected 

facilities, fuel supplier certifications are only allowed for facilities with heat input capacities between 

2.9 and 8.7 MW (10 to 30 MMBtu/hr). 

§60.47c Emission monitoring for particulate matter. 

(a) Except as provided in paragraphs (c), (d), (e), (f), and (g) of this section, the owner or operator of 

an affected facility combusting coal, oil, or wood that is subject to the opacity standards under §60.43c 

shall install, calibrate, maintain, and operate a continuous opacity monitoring system (COMS) for 

measuring the opacity of the emissions discharged to the atmosphere and record the output of the 
system. The owner or operator of an affected facility subject to an opacity standard in §60.43c(c) and 

that is not required to useinstall a COMS due to paragraphs (c), (d), (e), or (f) of this section that elects 

not to useinstall a COMS shall conduct a performance test using Method 9 of appendix A–4 of this part 

and the procedures in §60.11 to demonstrate compliance with the applicable limit in §60.43c by April

29, 2011, within 45 days of stopping use of an existing COMS, or 180 days after initial startup of the 

facility, whichever is later, and shall comply with either paragraphs (a)(1), (a)(2), or (a)(3) of this 

section. The observation period for Method 9 of appendix A-4 of this part performance tests may be 

reduced from 3 hours to 60 minutes Iif during the initial 60 minutes of observation all 6-minute 

averages are less than 10 percent and all individual 15-second observations are less than or equal to 20 

percent during the initial 60 minutes of observation.., the observation period may be reduced from 3 

hours to 60 minutes.

(1) Except as provided in paragraph (a)(2) and (a)(3) of this section, the owner or operator shall 

conduct subsequent Method 9 of appendix A–4 of this part performance tests using the procedures in 

paragraph (a) of this section according to the applicable schedule in paragraphs (a)(1)(i) through 

(a)(1)(iv) of this section, as determined by the most recent Method 9 of appendix A–4 of this part 

performance test results. 

(i) If no visible emissions are observed, a subsequent Method 9 of appendix A–4 of this part 

performance test must be completed within 12 calendar months from the date that the most recent 

performance test was conducted; 

(ii) If visible emissions are observed but the maximum 6-minute average opacity is less than or equal 

to 5 percent, a subsequent Method 9 of appendix A–4 of this part performance test must be completed 

within 6 calendar months from the date that the most recent performance test was conducted; 

(iii) If the maximum 6-minute average opacity is greater than 5 percent but less than or equal to 10 

percent, a subsequent Method 9 of appendix A–4 of this part performance test must be completed 

within 3 calendar months from the date that the most recent performance test was conducted; or 

(iv) If the maximum 6-minute average opacity is greater than 10 percent, a subsequent Method 9 of 

appendix A–4 of this part performance test must be completed within 30 45 calendar days from the 

date that the most recent performance test was conducted. 

(2) If the maximum 6-minute opacity is less than 10 percent during the most recent Method 9 of 

appendix A–4 of this part performance test, the owner or operator may, as an alternative to performing 

subsequent Method 9 of appendix A–4 of this part performance tests, elect to perform subsequent 

monitoring using Method 22 of appendix A–7 of this part according to the procedures specified in 

paragraphs (a)(2)(i) and (ii) of this section. 

(i) The owner or operator shall conduct 10 minute observations (during normal operation) each 

operating day the affected facility fires fuel for which an opacity standard is applicable using Method 

22 of appendix A–7 of this part and demonstrate that the sum of the occurrences of any visible 

emissions is not in excess of 5 percent of the observation period ( i.e. , 30 seconds per 10 minute 

period). If the sum of the occurrence of any visible emissions is greater than 30 seconds during the 

initial 10 minute observation, immediately conduct a 30 minute observation. If the sum of the 

occurrence of visible emissions is greater than 5 percent of the observation period ( i.e. , 90 seconds 

per 30 minute period) the owner or operator shall either document and adjust the operation of the 

facility and demonstrate within 24 hours that the sum of the occurrence of visible emissions is equal to 
or less than 5 percent during a 30 minute observation ( i.e. , 90 seconds) or conduct a new Method 9 of 

appendix A–4 of this part performance test using the procedures in paragraph (a) of this section within 

30 45 calendar days according to the requirements in §60.45c(a)(8). 

(ii) If no visible emissions are observed for 30 operating days during which an opacity standard is 

applicable, observations can be reduced to once every 7 operating days during which an opacity 

standard is applicable. If any visible emissions are observed, daily observations shall be resumed. 

(3) If the maximum 6-minute opacity is less than 10 percent during the most recent Method 9 of 

appendix A–4 of this part performance test, the owner or operator may, as an alternative to performing 

subsequent Method 9 of appendix A–4 performance tests, elect to perform subsequent monitoring 

using a digital opacity compliance system according to a site-specific monitoring plan approved by the 

Administrator. The observations shall be similar, but not necessarily identical, to the requirements in 

paragraph (a)(2) of this section. For reference purposes in preparing the monitoring plan, see OAQPS 

“Determination of Visible Emission Opacity from Stationary Sources Using Computer-Based 

Photographic Analysis Systems.” This document is available from the U.S. Environmental Protection 

Agency (U.S. EPA); Office of Air Quality and Planning Standards; Sector Policies and Programs 

Division; Measurement Policy Group (D243–02), Research Triangle Park, NC 27711. This document 

is also available on the Technology Transfer Network (TTN) under Emission Measurement Center 

Preliminary Methods. 

(b) All COMS shall be operated in accordance with the applicable procedures under Performance 

Specification 1 of appendix B of this part. The span value of the opacity COMS shall be between 60 

and 80 percent. 

(c) Owners and operators of an affected facilities that burn only distillate oil that contains no more than 

0.5 weight percent sulfur and/or liquid or gaseous fuels with potential sulfur dioxide emission rates of 

26 ng/J (0.060 lb/MMBtu) heat input or less and that do not use a post-combustion technology to 

reduce SO2 or PM emissions and that are subject to an opacity standard in §60.43c(c) are not required 

to operate a COMS if they follow the applicable procedures in §60.48c(f). 

(d) Owners or operators complying with the PM emission limit by using a PM CEMS must calibrate, 

maintain, operate, and record the output of the system for PM emissions discharged to the atmosphere 

as specified in §60.45c(c). The CEMS specified in paragraph §60.45c(c) shall be operated and data 

recorded during all periods of operation of the affected facility except for CEMS breakdowns and 

repairs. Data is recorded during calibration checks, and zero and span adjustments. 

(e) Owners and operators of an affected facility that is subject to an opacity standard in §60.43c(c) and 

that does not use post-combustion technology (except a wet scrubber) for reducing PM, SO2, or carbon 

monoxide (CO) emissions, burns only gaseous fuels or fuel oils that contain less than or equal to 0.5 

weight percent sulfur, and is operated such that emissions of CO discharged to the atmosphere from 

the affected facility are maintained at levels less than or equal to 0.15 lb/MMBtu on a boiler operating 

day average basis is not required to operate a COMS. Owners and operators of affected facilities 

electing to comply with this paragraph must demonstrate compliance according to the procedures 

specified in paragraphs (e)(1) through (4) of this section; or 

(1) You must monitor CO emissions using a CEMS according to the procedures specified in 

paragraphs (e)(1)(i) through (iv) of this section. 
(i) The CO CEMS must be installed, certified, maintained, and operated according to the provisions in 

§60.58b(i)(3) of subpart Eb of this part. 

(ii) Each 1-hour CO emissions average is calculated using the data points generated by the CO CEMS 

expressed in parts per million by volume corrected to 3 percent oxygen (dry basis). 

(iii) At a minimum, valid 1-hour CO emissions averages must be obtained for at least 90 percent of the 

operating hours on a 30-day rolling average basis. The 1-hour averages are calculated using the data 

points required in §60.13(h)(2). 

(iv) Quarterly accuracy determinations and daily calibration drift tests for the CO CEMS must be 

performed in accordance with procedure 1 in appendix F of this part. 

(2) You must calculate the 1-hour average CO emissions levels for each steam generating unit 

operating day by multiplying the average hourly CO output concentration measured by the CO CEMS 

times the corresponding average hourly flue gas flow rate and divided by the corresponding average 

hourly heat input to the affected source. The 24-hour average CO emission level is determined by 

calculating the arithmetic average of the hourly CO emission levels computed for each steam 

generating unit operating day. 

(3) You must evaluate the preceding 24-hour average CO emission level each steam generating unit 

operating day excluding periods of affected source startup, shutdown, or malfunction. If the 24-hour 

average CO emission level is greater than 0.15 lb/MMBtu, you must initiate investigation of the 

relevant equipment and control systems within 24 hours of the first discovery of the high emission 

incident and, take the appropriate corrective action as soon as practicable to adjust control settings or 

repair equipment to reduce the 24-hour average CO emission level to 0.15 lb/MMBtu or less. 

(4) You must record the CO measurements and calculations performed according to paragraph (e) of 

this section and any corrective actions taken. The record of corrective action taken must include the 

date and time during which the 24-hour average CO emission level was greater than 0.15 lb/MMBtu, 

and the date, time, and description of the corrective action. 

(f) Owners and operators of an affected facility that is subject to an opacity standard in §60.43c(c) and 

that uses a bag leak detection system to monitor the performance of a fabric filter (baghouse) according 

to the most recent requirements in section §60.48Da of this part is not required to operate a COMS. 

(g) Owners and operators of an affected facility that is subject to an opacity standard in §60.43c(c) and 

that burns only gaseous fuels or fuel oils that contain less than or equal to 0.5 weight percent sulfur and 

operates according to a written site-specific monitoring plan approved by the permitting authority is 

not required to operate a COMS. This monitoring plan must include procedures and criteria for 

establishing and monitoring specific parameters for the affected facility indicative of compliance with 

the opacity standard.