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Chapter 11

Monitoring and Compliance

Contents

11.1 Initial Compliance Demonstration....................................................................................... 3

Initial Compliance Determination........................................................................................... 3

Hybrid Approach .................................................................................................................... 5

Should Conduct Initial Performance Testing.......................................................................... 5

Should Not Conduct Initial Performance Testing................................................................... 6

Best Approach for Initial Performance ................................................................................... 8

11.2 Proposed CO2 Monitoring Methods..................................................................................... 9

11.2.1 The CEMS Option........................................................................................................ 9

Allow O2 Monitoring ............................................................................................................ 11

Other Monitoring .................................................................................................................. 11

11.2.2 The Heat Input and Fuel Factor Option...................................................................... 12

Recommend fuel flow monitoring........................................................................................ 12

Support Use of Appendix D and Appendix G ...................................................................... 15

11.3 Monitoring of CO2 Mass Emissions from Integrated Equipment...................................... 16

11.4 Monitoring and Reporting of Gross Generation ................................................................ 16

11.5 Quality Assurance and Quality Control (QA/QC)............................................................. 18

11.6 Additional Measurement Requirements ............................................................................ 20

11.7 The Monitoring Plan.......................................................................................................... 24

11.8 Schedule for Monitoring System Certification.................................................................. 25

11.9 Annual or Multi-Year Compliance Periods....................................................................... 25

Annual vs. Multi-Year Basis................................................................................................. 25

Support Multi-Year Compliance........................................................................................... 26

Oppose Multi-Year Compliance ........................................................................................... 27

Support 12-month Compliance ............................................................................................. 27

Include an Option for 12-month Compliance ....................................................................... 28

Not Set a More Stringent Standard for Multi-Year Compliance .......................................... 28

Include Stringent Measures for 84-month Compliance Option............................................ 29

NGCC ................................................................................................................................... 30

Hourly, Monthly, Daily......................................................................................................... 31
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Daily Violations.................................................................................................................... 32

Format of the Standard, Total Emissions over Total Electrical Output................................ 33

Include 0 for Emission Rates if Not Operating..................................................................... 34

Compliance Issues with 3-Year Applicability Threshold..................................................... 34

Compliance Issues Related to Applicability......................................................................... 34

11.10 Valid Data, Backup Monitors, Missing Data Procedures, and Minimum Data 

Availability ................................................................................................................................... 35

Valid Data ............................................................................................................................. 35

Backup Monitors................................................................................................................... 36

95 Percent Data Availability................................................................................................. 37

Missing Data ......................................................................................................................... 37

11.11 Violation of Monitoring Requirements.......................................................................... 38

11.12 Carbon Capture and the Calculation of lb/MMBtu Emission Values............................ 40

11.13 Part 75 Monitoring Methods.......................................................................................... 41
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11.1 INITIAL COMPLIANCE DEMONSTRATION

Initial Compliance Determination

Comment 11.1-1: Commenter 9514 stated EPA must take steps to improve near-term 

compliance. Commenter 9514 stated EPA should establish a requirement for an early initial 

compliance demonstration.

Commenter 9514 stated that ignoring emissions that predate the applicability threshold is 

unwarranted. Commenter 9514 stated that one impact of the extended averaging period for the 

applicability determination is a significant delay in the date by which certain sources must 

comply with the proposed standards. Commenter 9514 gave an example where, for a source that 

exceeds the applicability threshold in January, this language appears to allow the source to 

ignore all emissions prior to that month, with the source’s first 12-month compliance period 

concluding in December of that year, so the proposed rule would not require a compliance 

determination until up to 12 months after the applicability threshold is crossed.

Commenter 9514 stated there is no reason to wait up to a full year after applicability is triggered 

to make the first compliance demonstration, and EPA should require the initial compliance 

determination in the first month after a source crosses the applicability threshold. Commenter 

9514 stated the initial compliance dates should reflect that most plant operators will know the 

ultimate applicability status of their sources well in advance of crossing the applicability

threshold. Commenter 9514 stated EPA should factor into the initial averaging period to 

determine a source’s compliance the operating days that predate the point at which the source 

crosses the applicability threshold. Commenter 9514 further stated that including in a compliance 

determination the emissions that predate the point at which a source crosses the applicability

threshold is consistent with Congress's timing scheme for applying NSPS to new sources. 

Commenter 9514 stated the CAA defines a "new source" for the purposes of section 111 as "any 

stationary source, the construction or modification of which is commenced after the publication 

of regulations (or, if earlier, proposed regulations) prescribing a standard of performance under 

this section which will be applicable to such source." Commenter 9514 stated this unique use of 

the date of proposed regulations to define the sources to which an NSPS applies shows that 

Congress meant to require compliance by new sources without delay. Commenter 9514 further 

stated, EPA should therefore not base applicability determinations on a source's actual 

generation.

Response 11.1-1: The EPA agrees with commenter 9514 that the sources subject to the 

regulation will need to start monitoring and reporting under the regulation. In doing so the 

affected sources will need to certify all new monitoring equipment. The EPA will require 

reporting of these certifications prior to the affected source completing a full compliance period. 

Additionally affected sources will be required to report data after every quarter to the ECMPS 

Client Tool. The data that will be submitted after every quarter will not always include a 

compliance period average but will include all of the hourly data that the source will use to 

calculate the compliance averages when applicable. Additionally the EPA will only determine 

compliance with respect to the appropriate reported 12
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Comment 11.1-2: With respect to the first performance test or compliance period, Commenter 

9666 stated that EPA’s reference to the Part 75 reporting provision in section 75.64(a) is 

unnecessarily confusing. Commenter 9666 stated if compliance is based on a 12-month rolling 

average, the period should begin with the first operating month following the month in which 

monitoring system certification is complete, or the month when the 180-day period in section 

75.4 expires, whichever is earlier, but it should not begin in the month in which that event 

occurred. Under the proposal, Commenter 9666 stated if the EGU did not certify the monitoring 

system, or the period did not expire, on the first day of the month (i.e., if the monitor was not 

certified in the middle or the end of the month), the EGU would be required to calculate their 

first 12-month rolling average with less than 12 full operating months of data. Commenter 9666 

stated EGUs should not be required to artificially schedule the certification of their monitoring 

systems to occur on the first day of the month in order to obtain a full 12 operating months of 

data.

Response 11.1-2: The EPA appreciates the commenter for pointing out the need for additional 

clarification under the regulation with respect to the certification of instruments under Part 

75.64(a). The EPA is requiring in the final rule that all CO2 CEMS must be certified within 180

days after startup and that monitoring must begin immediately after certification.

Comment 11.1-3: Commenter 9666 stated that if compliance is determined annually, and for 

EGUs that become subject to the NSPS as a result of a change in capacity factor, the first

compliance period or performance test would begin with the first operating month of the first 

calendar year following monitoring system certification or expiration. Commenter 9666 noted 

that alternatively, for new units, rather than discard the data for the first partial year of 

commercial operation, EPA could require that the data recorded during the first partial year be 

combined with data from the first full calendar year of operation for the initial compliance 

demonstration.

Commenter 9780 asked EPA to clarify that "before sources have completed the first 12 or 84 

months of operation...there is no calculation of a rolling average and thus no basis for 

finding noncompliance with the emissions rate standard."

Commenter 9427 asked, "when does the first compliance period begin and end? Does the 

combustion turbine wait until the first 3-year applicability period is satisfied, and then 

comply going forward? Or, does compliance look back to the beginning of the 3-year period?"

Commenter 10095 asked, "does the affected facility have a compliance obligation during the first 

three years of operation?" and "when is the first compliance determination for a CT?"

Response 11.1-3: In the final rulemaking the applicability has been clarified so that a source 

cannot go “in and out” of being subject to the rule. Compliance with the emission standards is 

based on a 12-operating month average where the averaging period starts with the first operating 

month a source becomes subject to the NSPS. Compliance is to be assessed solely on the basis of 

whether the average CO2 emission rate over the specified 12-operating month averaging period 

meets the standard. For more discussion on the 12-operating month compliance period please see 

section IV.C. of the preamble.
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Hybrid Approach

Comment 11.1-4: Commenter 10389 recommended a hybrid approach that combines (1) initial 

performance standard, and (2) 12-month average performance standard. Commenter 10389 

stated that requiring an initial compliance test that is numerically more stringent than the annual 

standard for new combined cycle facilities would insure that the most efficient stationary

combustion turbines are installed and the right investment decisions are made at the outset. 

Commenter 10389 stated the less stringent 12-month rolling average standard would be set at a 

level that would take into account actual operating conditions. Commenter 8957 stated daily

emissions performance matters less than performance over many years or decades.

Response 11.1-4: According to §60.5508 of Subpart TTTT, the rule applies only to new units 

that commence construction after the specified date. After careful consideration of the comments 

received, the initial applicability criteria in the final rule have been simplified. Applicability is 

based on the size of the EGU (≥ 250 mmBtu/hr heat input capacity for fossil fuel combustion) 

and the size of the generator (> 25 MW) producing electricity for sale. It is therefore not 

necessary for a unit to operate for up to 3 years before it can be determined that it is subject to 

the rule. A unit that meets the applicability criteria in §60.5509(a)(1) or (a)(2) and is not 

exempted under §60.5509(b) will remain an affected unit; no “exit ramps” are provided.

Should Conduct Initial Performance Testing

Comment 11.1-5: Commenter 9514 stated an initial performance test is needed for all sources 

covered by these NSPS. Commenter 9514 stated EPA should require an initial performance test 

before the source begins operating, to ensure compliance with the NSPS. Commenter 9514 stated 

that failure to require performance testing is inconsistent with section 111(b)(1)(B) and 111(e).

Commenter 9514 stated the need for early compliance determinations is especially great in light 

of the long averaging times proposed. Commenter 9514 stated there is no reason not to require 

sources to demonstrate their ability to perform to the annual average emission limits when the 

unit is new and under controlled conditions.

Commenter 9514 noted that EPA departs from many years of consistent practice by failing to 

provide for an early initial compliance demonstration for either fossil-fuel EGUs or NG-fired 

CTs and CCGTs, and EPA does not provide adequate explanation.

Commenter 8957 believed an initial performance test for all sources is consistent with DEP’s 

requirement that all new sources, including turbines, must perform initial compliance tests after 

the shakedown period.

Commenter 9514 stated, for sources relying on the 84-month compliance alternative, it is 

essential to demonstrate the ability to meet the applicable emission limits, and provide sufficient 

documentation to demonstrate at startup that the CO2 capture system functions properly and that 

it will be able to sequester CO2 on-site at a properly permitted facility or assure long-term 

containment through transfer to an offsite facility. Commenter 9514 noted that where 

sequestration operations are under common ownership or control, there is no reason testing could 

not be conducted as normally required by NSPS. Commenter 9514 noted that where 

sequestrations operations are not co-located or under common control, there may be unique 
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challenges in conducting an initial performance test (where not already operating), however, an 

initial test of the EGU and its CO2 capture equipment would provide valuable information. 

Commenter 9514 stated that years of excess CO2 emissions could be avoided. Commenter 9514 

indicated that early initial performance tests for all regulated units will avoid periods of 

noncompliance, avoid situations where “equities on the ground” make injunctive relief less 

probable, and resolves issues of responsibility for any problems between vendor and operator.

Commenter 9514 noted that for transfer to a sequestration facility that is already in use, no initial 

performance testing may be necessary, but suggested documentation of the facility’s permit and 

most recent report be included in compliance materials.

Commenter 9514 stated that initial performance testing should be conducted using the most 

carbon-intensive fuels permitted at the source and with the source operating at load levels, 

including part-load operation, that reflect what the agency calls "realistic worst case conditions.?

Commenter 10681 stated EPA could use a single, multi-load set of stack tests using Part 60, 

Appendix A methods, and noted this initial compliance determination under 60.8 is different 

than meeting the 12-month rolling average limit of the NSPS. Commenter 10681 suggested EPA 

consider Washington state rule WAC 173-407, sections 140, 150, and 230, for a possible 

compliance approach. Commenter 10681 indicated Washington State utilizes a quarterly, 4 load 

emission test program to demonstrate compliance with GHG emissions standards.

Response 11.1-5: The final rule retains the exemption from performing initial performance stack 

tests. Because compliance with the emission standards is based on a 12-operating month average, 

it is not reasonable to hold the sources to these standards based on the results of a stack test. Over 

a long period of time, the CO2 mission rate will fluctuate and may exceed the numerical value of 

the standard at times. If a 3-hour emission test is performed during one of these incidents, it may

appear that the EGU is out of compliance. But this is not necessarily so. Compliance is to be 

assessed solely on the basis of whether the average CO2 emission rate over the specified 12-

operating month averaging period meets the standard. For more discussion on the 12-operating 

month compliance period please see section IV.C. of the preamble.

Should Not Conduct Initial Performance Testing

Comment 11.1-6: Commenter 9666 stated that while EPA proposes that the requirement to 

perform an initial stack test under section 60.8 would not apply (Proposed Subpart TTTT, Table 

2, identifies section 60.8 as inapplicable), EPA also solicits comment on requiring such a test, 

and thus initial compliance with a more stringent standard, for stationary combustion turbines to 

ensure that only the most efficient combustion turbines are installed. Commenter 9666 objected 

to this proposal and noted EPA has not provided any data to demonstrate that such a standard is 

achievable.

Commenter 9426 supported the proposal that an initial performance test should not be required 

under section 60.8 for utility boilers and IGCC units or for NG combustion turbines. Commenter 

9426 stated an initial performance test provides no added environmental benefit but does add 

cost. Commenter 9426 stated initial performance will be demonstrated when the facility

completes its first period of operation using the approved monitoring system, as is consistent 
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with Subpart Da compliance demonstration for SO2 and NOx, where the initial compliance test 

consists of operating the certified CEMS for 30 operating days and reporting those results.

Commenter 9426 stated the initial design efficiency or short-term measurement during a stack 

test would not be representative of the form of the emissions standards proposed and would not 

be representative of the data the EPA evaluated to establish the standards. Commenter 9426 

stated EPA has not provided any evaluation of short-term averages in developing BSER for 

combustion turbines, and there is no basis for establishing this “secondary” BSER. Commenter 

9426 stated that if EPA set an initial testing requirement under 60.8, the short-term standard 

equivalent to the long-term BSER would need to be less stringent, not more stringent. 

Commenter 9426 stated that setting an initial design efficiency by requiring an initial 

performance test would be difficult to set, given that new combustion turbines and combined 

cycle units may have significant variations in performance for many factors beyond EPA’s stated 

intention of insuring the most efficient units are installed, such as ambient conditions, fuel 

supply, elevation, physical arrangement and size of power generation block, choice of cooling 

system, amount of duct burning, etc.

Commenter 9426 stated that if EPA decides to set an initial design efficiency, it must reissue the 

NSPS for NG combustion turbines and provide the basis for public review and comment.

Commenter 8952 stated there is no value in conducting initial performance measurements at or 

near plant commissioning, prior to the 12-month compliance period. Commenter 8952 stated 

compliance with the standard will be strongly dictated by the operational profile of the plant, not 

the base load emission rate at or near commissioning. Commenter 8952 indicated the additional 

testing is unnecessary because the project owner always requires a performance validation.

Commenter 8952 recommended an exemption for turbines from initial performance testing.

Commenter 8952 stated the performance test should only apply to combined cycles using ASME 

PTC 46 (separate performance codes are defined for simple cycle gas turbines), and noted that no 

simple cycle turbines operate below 1,000 lb/MWh, and most operate above 1,100 lb/MWh. 

Commenter 9426 stated that conducting an initial performance test provides no added 

environmental benefit but adds cost. Commenter 9426 further stated that BSER is the appropriate 

mechanism to establish the standard. Commenter 9426 also stated that setting a short-term 

standard "equivalent to" the long-term BSER would need to be less stringent.

Commenter 10554 did not support an initial performance test.

Response 11.1-6: The final rule retains the exemption from performing initial performance stack 

tests. Because compliance with the emission standards is based on a 12-operating month average, 

it is not reasonable to hold the sources to these standards based on the results of a stack test. Over 

a long period of time, the CO2 mission rate will fluctuate and may exceed the numerical value of 

the standard at times. If a 3-hour emission test is performed during one of these incidents, it may

appear that the EGU is out of compliance. But this is not necessarily so. Compliance is to be 
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assessed solely on the basis of whether the average CO2 emission rate over the specified 12-

operating month averaging period meets the standard. For more discussion on the 12-operating 

month compliance period please see section IV.C. of the preamble.

Best Approach for Initial Performance

Comment 11.1-7: Commenter 8952 recommended EPA determine compliance with a CO2

lb/MWh standard at the maximum continuous rating point of the gas turbine and steam turbine 

during the initial performance testing on natural gas using a fuel measurement method noted in 

the text (reference ASME PTC 46).

Commenter 8952 believed ideal way to ensure the best technologies are deployed is to determine 

the overall performance as part of the performance testing conducted during the commissioning 

phase of a combined cycle facility, using already in place performance test standards ASME 

PTC 46, typically conducted within the first 180 days of first-fire. Commenter 8952 stated basing 

compliance evaluation at the maximum continuous rating point corrected to ISO standard 

conditions, uncertainties related to part load operation and transients can be avoided. Commenter 

8952 stated this is essentially an efficiency evaluation, which is what a performance test is.

Commenter 8952 stated the performance test should only apply to combined cycles using ASME 

PTC 46. Commenter 8952 stated performance compliance testing would be limited to natural 

gas operation only.

Commenter 7976 stated that a simple economical way to monitor compliance is to use accurately

tested rates of fuel consumption and concurrent MW output of the plant when operating at base 

load under strict test conditions. Commenter 7976 stated this data accurately establishes the plant 

capacity. Commenter 7976 noted that after initial compliance testing, regulators can monitor 

changes in plant heat rate and emission rate but they will not know why changes have occurred; 

review of maintenance will usually be the more effective way to monitor a plant, and regulators 

should review plant maintenance records to determine whether CO2 emission can be reduced by 

effective maintenance and repairs. Commenter 7976 stated re-testing is an option but the results 

need to be corrected for degradation. Commenter 7976 stated that limiting fuel burn until 

remedial maintenance is completed is the best remedy because it reduces emissions but avoids 

shutdown.

Response 11.1-7: The final rule retains the exemption from performing initial performance stack 

tests. Because compliance with the emission standards is based on a 12-operating month average, 

it is not reasonable to hold the sources to these standards based on the results of a stack test. Over 

a long period of time, the CO2 mission rate will fluctuate and may exceed the numerical value of 

the standard at times. If a 3-hour emission test is performed during one of these incidents, it may

appear that the EGU is out of compliance. But this is not necessarily so. Compliance is to be 

assessed solely on the basis of whether the average CO2 emission rate over the specified 12-

operating month averaging period meets the standard. For more discussion on the 12-operating 

month compliance period please see section IV.C. of the preamble.

Comment 11.1-8: Commenter 0585 stated energy is a large economic driver for much of 

Colorado, especially on the Western Slope and the proposed regulations will have impact on the 
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economy and livelihoods. Commenter 0585 asked that EPA consider including compliance 

flexibility in the rule, and this should include full consideration of distinct regions and would 

include individual stakeholders and their unique circumstances.

Response 11.1-8: The EPA thanks the commenter for their comment and the EPA believe that 

the final rule provides compliance flexibilities for all types of new affected sources.

Comment 11.1-9: Commenter 8952 stated emissions should only be reported during periods of 

natural gas operation. Commenter 8952 stated that during periods when gas supplies are 

curtailed, plants with interruptible gas supplies may use alternative or backup fuel, commonly

No.2 distillate or similar fuels, which have significantly higher CO2 emission profiles. 

Commenter 9661 stated EPA does not address compliance for units utilizing oil as a backup 

fuel, and stated this type of operation should be exempt, as units forced to burn oil for extended 

shutdowns of NG would emit at significantly higher CO2 emissions rates than allowed by the 

NSPS standard. Commenter 9661 stated many plants may fire oil as an emergency backup fuel, 

during period of NG curtailment such as hurricane recovery, other natural disaster disruption, 

and these periods are infrequent, as economics dictates it is disadvantageous to use oil except in 

emergency situations.

Response 11.1-9: The EPA disagrees with the commenters as reporting is required by affected 

EGUs for all fuel types in the final rule along with the associated fuel that was utilized during the 

compliance/reporting period. The affected source must comply then with the appropriate 

standard in the rule.

11.2 PROPOSED CO2 MONITORING METHODS

11.2.1The CEMS Option

Comment 11.2-1: Commenter 9514 stated EPA should require CEMS for emissions from all 

units, regardless of fuel type. Commenter 9514 stated direct monitoring of emissions, especially

using CEMS, is generally more accurate than estimating emissions using fuel consumption, as 

EPA has previously acknowledged (cited RIA for MRR). 

Commenter 10554 supported installation of CEMS as the only method to determine compliance 

with the CO2 standard, noting it is a standard system that follows many checks each day, quarter, 

and year to ensure the data are correct. Commenter 10554 noted fuel-based calculations have 

room for error in the analyses.

Commenter 9514 stated EPA should require all new plants to use CEMS to calculate CO2

emissions, and should require plants to include periods of ramping and low load in the 

compliance demonstration for any monitoring methods that are included in the final rule.

Commenter 9514 stated EPA should require all new plants to use CEMS to calculate CO2

emissions. Commenter 9514 stated the information used to set the standards for new gas turbines 

is largely CEMS data, which does not exclude periods of ramping activities and low load. 

Commenter 9514 noted the fuel sampling procedure allows a source to exclude ramping up or 
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down or low load, which effectively exempts periods of low or changing load from regulation. 

Commenter 9514 stated that allowing sources to disregard these modes of operation from a 

compliance demonstration weaken the standard below BSER and violate the requirement to 

demonstrate continuous compliance. Commenter 9514 should require plants to include periods of 

ramping and low load in the compliance determinations for any monitoring methods.

Commenter 10869 stated that CO2 CEMS will be a significant technological improvement in 

EPA’s ability to track emissions and will come at very little, if any additional cost. Commenter 

10869 stated CEMS data should be made available to the public, and it will help inform the 

impacts of different policies and inform the design and operation of future climate policies. 

Commenter 10869 stated mandating CEMS will create a more transparent and independent 

emissions-tracking system that will help improve the quality and credibility of GHG reporting 

and inventories. Commenter 10869 noted that CEMS are already used at many stationary 

sources, including power plants, and under the Acid Rain program, many power plants are 

already required to report SO2, NOx, and CO2 and O2. Commenter 10869 noted these existing 

CEMS may be used or upgraded and in some cases new devices may need to be installed. 

Commenter 10869 stated EPA should ensure robust tracking for CO2 emissions from plants with 

CCS and for non- CO2 GHGs.

Commenters 9425 and 9666 stated they do not oppose requiring use of CEMS and a stack flow 

monitor for solid fuel-fired units that employ carbon separation technology. Commenter 9666 

stated they do not oppose allowing other units to use such monitoring.

Response 11.2-1: The final rule requires the use of CEMS for coal-fired EGUs and IGCC units 

and allows all other affected units to use CEMS. However, units that combust only liquid and/or 

gaseous fuel may opt to use Equation G-4 in Appendix G of Part 75 to quantify the CO2 mass 

emission rate.

Comment 11.2-2: Commenter 9666 supported several monitoring options in the proposed rule 

but believed EPA has unreasonably eliminated several other Part 75 options. Commenter 9666 

supported requiring new EGUs that combust solid fuel, and to allow other new EGUs, to monitor 

CO2 mass emissions using a CO2 concentration monitor, flow monitor, and (if applicable) a 

moisture monitoring system in accordance with Part 75 (Proposed Subpart TTTT, Subpart Da, 

Subpart KKKK), and as an alternative, supported allowing EGUs that combust only liquid or 

gaseous fuel to determine CO2 mass emissions under the provision in Part 75, Appendix G 

section 2.3 that uses heat input determined under Part 75, Appendix D and a carbon-based Ffactor to determine CO2 mass emissions. (Proposed Subpart TTTT, Subpart Da, Subpart KKKK). 

Commenter 9780 supported used of CEMS data but EPA should consider fuel-based 

measurements as an alternative.

Commenter 1005 stated EPA should not require use of CO2 CEMS. Commenter 9426 stated use 

of CEMS would not be feasible for stationary combustion turbines.

Commenter 9661 stated EPA should not require stack flow monitors and CO2 analyzers and 

should allow fuel flow meters and other mass measurement technologies. 

Commenter 9426 stated use of CEMS would not be feasible for stationary combustion turbines.
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Commenter 9425 opposed a requirement to use CO2 CEMS for units that do not use carbon 

separation. 

Response 11.2-2: The final rule requires the use of CEMS for coal-fired EGUs and IGCC units 

and allows all other affected units to use CEMS. However, units that combust only liquid and/or 

gaseous fuel may opt to use Equation G-4 in Appendix G of Part 75 to quantify the CO2 mass 

emission rate.

Allow O2 Monitoring

Comment 11.2-3: Commenter 9425 stated that while most Part 75 coal-fired units use CO2

CEMS, EPA should include use of O2 CEMS and F-factors as alternatives, as Part 75 and 

Subpart Da allow these. Commenter 9666 noted that while Part 75 and Subpart Da allow use of 

an O2 CEMS in lieu of a CO2 CEMS, an O2 CEMS cannot obtain accurate CO2 measurement for 

EGUs that use carbon separation because the calculation relies on F-factors. Commenter 9425 

noted that EPA did not propose to allow the option in 75.10(a)(3)(iii) to use an O2 concentration 

monitor to determine CO2. Commenter 9425 advocated for an option to use an O2 concentration 

monitor.

Commenter 9666 did not understand why EPA has required use of a CO2 CEMS and not allowed 

use of an O2 CEMS to obtain CO2 at an EGU that does not use carbon separation, as both 

existing NSPS Subparts Da and KKKK allow use of either a CO2 concentration monitor or an O2

concentration monitor as the diluent monitor to calculate emissions in lbs per MMBtu. 

Commenter 9666 further noted that Part 75 explicitly allows use of an O2 concentration monitor 

to measure CO2 concentration to obtain CO2 mass emissions. Commenter 9666 stated there is no 

valid reason not to allow both types of monitoring systems under this rule as well for EGUs 

without carbon capture. Commenter 9666 noted that gas- or oil- fired EGUs might prefer an O2

monitor since O2 analyzers generally cost less, are more stable, and are less affected by 

interferences (e.g., H2O and CO) that can impact CO2 measurements.

Commenter 9666 stated EPA must issue a rulemaking for eliminating the O2 monitoring option 

for public comment. Commenter 9666 stated that eliminating the option in the NSPS effectively 

eliminates it for NSPS units subject to Part 75.

Commenter 9666 stated EPA could add an option for use of an O2 monitor simply by adding a 

reference in Proposed Subpart TTTT section 60.5535(b)(1), or in Proposed Subpart Da section 

60.46Da(f)(2)(i) and Subpart KKKK section 60.4373(b)(1), to section 75.10(a)(3)(iii).

Response 11.2-3: The final rule (Subpart TTTT) allows the use of data from a certified O2

monitor to calculate hourly CO2 concentrations, provided that the affected EGU does not use 

carbon separation.

Other Monitoring

Comment 11.2-4: Commenter 10098 urged EPA to adopt regulations to address facilities that 

cannot meet CEMS certification requirements. Commenter 10098 stated that some facilities are 

unable to comply with the 20 percent variability range for flow RATA for CEMS certification. 
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Commenter 10098 urged EPA to include additional provisions that would apply in lieu of the 

certification requirements, in the event that a source is unable to obtain CEMS certification.

Response 11.2-4: The EPA thanks the commenter for their concern however the EPA points to 

the data collected over the last 20 years from the Acid Rain Program that modern CO2 and flow 

rate monitors can easily meet Part 75 relative accuracy standards. 

Comment 11.2-5: Commenter 7976 stated that compliance monitoring needs improvement. 

Commenter 7976 stated it is impossible to know the cause of changes in an operating plant’s 

CO2 emission rates simply by monitoring the CO2 emission rate. Commenter 7976 noted that 

normal heat variations diminish the value of long term CO2 emission rate monitoring for 

compliance, and a regulator will not know the reason for the change in emission rate of a plant. 

Commenter 7976 stated if faulty or lax maintenance is not the cause for increased CO2

emissions, then it is unreasonable for regulators to take enforcement action against the plant. 

Commenter 7976 stated GHG regulators will find that long term online monitoring efforts will 

rarely uncover significant CO2 emission rate increases due to lax maintenance. Commenter 7976 

stated most combined cycle plants are well maintained for reasons of economy and reliability, 

plus insurance companies, public utility commissions, FERC, and NERC.

Response 11.2-5: The EPA thanks the commenter for their concern however the EPA is 

finalizing a 12 operating month rolling average discussed more in section IV.C of the preamble. 

11.2.2The Heat Input and Fuel Factor Option

Recommend fuel flow monitoring

Comment 11.2-6: Multiple commenters (8023, 9591, and 3862) supported the option of fuel 

flow meters for gas or liquid fuels. 

Commenter 9033 recommended that fuel flow composition and fuel flow rate are sufficient for 

reporting CO2 emissions.

Commenter 3862 stated fuel monitoring may be more accurate than available monitor in some 

cases.

Commenters 8937, 9426, and 9780 supported fuel-based measurements as an acceptable option 

or alternative to CEMS. Commenters 9426, 9780 stated utilities currently use fuel-based 

measurements to accurately measure fuel burned by a unit for their public utility commissions 

for both ratemaking and fuel supplier invoice true-up. Commenters 9426, 9780 stated fuelmeasurements coupled with chemical analysis of fuels burned provide an alternative 

methodology. Commenter 9780 stated that fuel measurements can provide GHG measurements 

with an average error of 1.6 percent, making this alternative potentially as accurate as the use of 

CEMS-based data.

Commenter 9661 stated there is no rational basis for EPA to limit monitoring options to stack 

flow monitors to the exclusion of fuel flow meters; fuel flow metering under 40 CFR 75 is 

widely utilized and provides high quality CO2 emissions data, and there is no rational basis not to 

allow the use of proven technology to calculate CO2 mass emissions as provided in 40 CFR 75, 
11-13

including fuel flow meters. Commenter 9661 noted, for example, proposed section 60.5525(c)(1) 

cross references 40 CFR 75.10(a)(3)(i), which would require the use of a stack flow monitor and 

would exclude other options, including fuel flow meters, that are provided within other 

provisions of 40 CFR 75.10(a)(3). Commenter 9661 stated EPA should update this and any other 

references to make clear that all of the monitoring options provided within 40 CFR 75.10(a)(3) 

are available.

Commenter 9665 stated periodic fuel sampling should be allowed as an acceptable/accurate 

monitoring method for compliance.

Commenter 8952 recommended fuel flow monitoring where applicable.

Commenters 8952, 9665 recommended the fuel monitoring method be the preferred compliance 

methodology, and Commenter 8952 recommended CEMs be included as an alternative 

methodology. Commenter 8952 stated fuel consumption monitoring should be the preferred 

method for gas turbines with CEMS being the alternative.

Commenter 9591 stated that fuel sampling is currently used to demonstrate compliance for gasand oil-fired units. Commenter 9591 stated that CEMS add to the cost of the rule and reduce 

flexibility.

Commenter 8952 recommended that fuel flow composition (weight percent carbon in the fuel) 

and fuel flow rate are sufficient metrics for reporting CO2 emissions. Commenter 8952 stated 

fuel analysis (fuel composition and consumption) is a more accurate, cost-effective method and 

maybe also report a higher output value than the CEMS, making it the more reasonable method 

for measuring CO2. 

Commenter 8937 noted the GHGRP for the power section relies on reporting using CEMS, and 

indicated more accurate emissions can be calculated from data reported to EIA-923 power plant 

operations surveys, and there is strong evidence to support the option of using fuel-based 

measurements as an alternative to CEMS. Commenters 9665, 10095 indicated that not requiring 

CEMS would be consistent with other EPA regulation (cited GHG MRR). Commenter 9665 

stated that fuel monitoring is superior to CEMS because (1) assumes all carbon in the fuel is 

oxidized to CO2, and (2) fuel flow data is very precise, since plants are charged for fuel 

consumption.

Commenter 9665 stated CEMS have inherent uncertainties, especially during transient operation 

(startup, shutdown, ramping). Commenter 9665 stated CEMS require both CO2 concentration 

measurement and volumetric flow rate measurement, which results in additional cost and 

equipment to maintain and certify. Commenter 9665 indicated that one valid data reading is 

required every 15 minutes (per PS in part 60) but plant parameters can vary significantly over 15 

minutes, resulting in significant uncertainty.

Commenter 8952 presented data for combined cycle CEM data that reveals emission levels 

below 1,000 lb/MWh emission output (average was 880 lb/MWh) however few simple cycle 

units can match this emissions performance. Commenter 8952 noted that using the recommended 

fuel flow technique suggests that actual emissions values are higher than the CEMS data 

presented. Commenter 8952 stated that combined cycle data (NG, using high capacity factor) 

give an emission average of 880 lb/MWh, and assuming 95 percent compliance and 2 sigma 
11-14

statistical calculation on the historical operation dataset, NG operation would have a 

recommended benchmark of 1,092 lb/MWh (880 + 2 x 106 = 1,092) or approximately 1,100 

lb/MWh.

Commenter 8952 compared the CO2 produced based on total fuel consumption and the reported 

CO2 based on CEMS measurements (for gas-fired systems that are not cogeneration or CHP, and 

with extreme emission data points removed). Commenter 8952 noted that total fuel consumption 

is expected to be more indicative of total carbon released to the environment, including startup 

and shutdown. Commenter 8952 noted that for combined cycle, the median value [emission rate] 

is somewhat higher when determined using fuel consumption. Commenter 8952 stated that 

engineering principles suggest that the fuel flow measurement method would be more accurate, 

and the data reveal that emission levels [from fuel measurement] are nominally higher than 

reported by the CEMS. Commenter 8952 stated that differences in the measured values provided 

are believed to result from inherent inaccuracies in the CEMS measurement systems, most 

notably during periods of startup and shutdown (although it is not clear whether this CEMS data 

was operational during startup). Commenter 8952 further noted that during transient events such 

as startup, there is a time delay between the fuel consumption and the combustion parameters 

and the CO2 level measured by the emission measurement device. Commenter 8952 explained 

the delay is caused by the time required for the gases to leave the combustor, reach the exhaust 

stack, travel down the flow extraction umbilical tube, and then reach the monitor; in some 

installations this can be a minute or more. As a result, CO2 concentration is measured and 

converted to a CO2 mass flow based on exhaust flow measurements that may differ by several 

minutes. Commenter 8952 noted this time lag is not significant during steady operation, but can 

be significant during transient events, especially start-up or shutdown. Commenter 8952 stated 

that measurement error is reduced if the fuel flow measurement technique is used. Commenter 

8952 stated EPA should adopt a fuel flow method for measuring CO2 for any gas turbine cycle 

due to its greater accuracy and ease of adoption by those units. Commenter 8952 further noted 

that these data support their claim that the actual benchmark should be above the proposed 1,000 

to 1,100 lb/MWh range.

Response 11.2-6: The final rule allows the use of Appendices D and G (specifically, Equation 

G-4) for units that combust only liquid and/or gaseous fuel.

Comment 11.2-7: Commenter 8952 stated that exempting startup and shutdown period from 

reporting and averaging would allow fuel flow and CEM methods to be better aligned.

Commenter 9514 stated EPA’s “average fuel consumption per unit of generation” procedure 

allows a source to exclude as nonrepresentative any hours in which the unit is ramping up or 

down or is operating at low-load. Commenter 9514 stated this procedure exempts period of low 

or changing load, which are high emissions periods. Commenter 9514 stated that if EPA include 

a monitoring option based on fuel consumption, the ramping up or down periods and operation at 

low-load periods should not be excluded from the emissions calculation. Commenter 9514 stated 

the best CCGT designs provide for a broader range of efficient operation than poorer designs, a 

fact that should be recognized in BSER and in compliance obligations of the rule.

Response 11.2-7: The EPA is requiring monitoring at all times and the EPA recognizes the 

concern with startup and shutdown which is why a 12-operating month rolling average is being 
11-15

finalized. The startup and shutdown events will have a small impact on emissions during this 

long averaging time.

Support Use of Appendix D and Appendix G

Comment 11.2-8: Commenter 10095 supported the option of using any part 60 and 75 methods 

for monitoring and calculating CO2 mass emissions. Commenter 10095 stated monitoring and 

reporting should be as flexible as the existing requirements under parts 60 and 75, including the 

ability to use part 75 Appendix D and G methodologies.

Commenters 8023, 9666 agreed with use of Appendix G of part 75 as an alternative to CEMS for 

liquid and gas-fired EGUs. [4562] Commenter 10095 stated EPA allow use of Appendix D and 

G for units that do not combust solid fuel or burn exclusively gaseous or liquid fuels.

Commenter 9427 supported the alternative to use Appendix D to part 75, noting that they

currently use Appendix D and find it to be accurate, reliable, better data collection, and fewer 

equipment malfunctions than CEMS.

Commenter 9425 supported use of fuel flow as an option. Commenter 9524 indicated that most 

new gas- and oil-fired combined cycle units will comply with the ARP to monitor and report 

hourly heat input and SO2 mass emissions by using Part 75 Appendix D fuel measurement, 

sampling, and analysis; the heat input value calculated under Appendix D can be used to 

calculate CO2 mass emissions under Part 75, Appendix G section 2.3 (9425) and subpart KKKK 

for NOx in lb/MWh. Commenter 9666 noted that EPA previously considered and rejected 

requiring such units to install stack flow monitoring systems in lieu of Appendix D. Commenter 

9666 noted that fuel flow meters are not subject to interferences that can bias measurement. 

Commenter 9666 stated requiring diluent CEMS at gas and oil-fired combustion turbines would 

be unjustified.

Commenter 9666 agreed with the option to use, but not require, site-specific F-factors under 

Equation G-4, noting that Appendix F provides F-factors for most commonly used fuels and 

includes a procedure for annual determination of a site-specific F-factor for fuels that are not 

listed, or if a source wants to develop its own F-factor. Commenter 9666 indicated that the 

variability in commonly used fuels is not sufficient to warrant determination of a site-specific Ffactor for all fuels, and that to the extent there is small variability, it is unlikely that variability

would be captured in an annual determination. Commenter 9666 further noted that EPA has 

relied on F-factors identical to those in Part 75, Appendix F in NSPS compliance determinations 

since the mid-1970s, and requiring development of a site-specific F-factor for commonly used 

fuels would be a waste of time and resources. 

Commenter 7990 stated EPA should align monitoring, testing, compliance, and reporting 

requirements with current practices. Commenter 7990 supported use of Equation G-4 to calculate 

mass emissions, as is allowed under EPA’s GHGRP and ARB MRGHG.

Commenter 7990 asked that the monitoring, testing, compliance, and reporting requirements in 

the NSPS align with current practice established by EPA and ARB.
11-16

Commenter 9425 supported the option for oil- and gas-fired units of using heat input calculated 

under Part 75 Appendix D and carbon based F-factors as provided in Appendix F using Equation 

G-4, as the use of Equation G-4 is appropriate for Appendix D units. Commenter 9425 requested 

EPA include the option of Equation G-4A, and noted that for Appendix D units that fire multiple 

fuel types simultaneously, ECMPS requires use of Equation G-4A to calculated total CO2 from 

the individual fuels combusted in the same hour.

Commenter 10952 encouraged EPA to rethink its rejection of optimized reasonable heat rate 

efficiencies approach, as it is the only rational and legally permissible option at this time.

Response 11.2-8: The final rule allows the use of Appendices D and G (specifically, Equation 

G-4) for units that combust only liquid and/or gaseous fuel.

11.3 MONITORING OF CO2 MASS EMISSIONS FROM INTEGRATED 

EQUIPMENT

Comment 11.3-1: Commenters 9666 and 10023 noted that if integrated equipment were used, 

continuous monitoring likely would not be warranted, as integrated equipment has very few 

emissions or operates very infrequently. Commenters 9666 and 10023 believed that because 

there is uncertainty about their use, EPA should not spend resources specifying monitoring 

requirements. Commenters 9666 and 10023 suggested a provision allowing submission and 

approval of a petition for exemption of emissions that are de minimis from the compliance 

calculation, or for an alternative means of accounting for any resulting emissions. Commenter 

9666 suggested, mass balance calculation or engineering estimate) from any integrated 

equipment that are not otherwise accounted for.

Response 11.3-1: The EPA is finalizing the use of all applicable continuous monitoring 

requirements that are currently in the Acid Rain Program’s part 75 requirements to comply with 

the emission limits. The EPA believes that there is flexibility provided in the final rule that still 

maintains the stringency required to determine compliance with the appropriate emission 

standard. 

11.4 MONITORING AND REPORTING OF GROSS GENERATION

Comment 11.4-1: Commenter 10243 agreed that compliance should be based on gross 

generation. Commenter 3493 stated that gross generation is consistent with reporting 

requirements under Part 75. Commenter 3495 stated gross generation does not factor into the 

emissions rate the parasitic load from emissions control technologies.

Commenter 9666 stated EGUs already are required to record and report hourly gross unit load in 

MWge under Part 75 (72.2, 75.57(b)(3), and 75.64(a)(2)). Commenter 9666 stated all new EGUs 

likely already measure and record MWs for all generation. 

Commenter 9666 stated that EPA’s ECMPS instructions say that the value reported under Part 

75 represents an hourly rate and not the total load for the hour, so that for hours of partial 

operation, the value reported will not represent the actual output for that hour. 
11-17

Commenter 9666 stated that units on common stacks report the weighted sum of the hourly unit 

loads for all units that exhaust through the stack. Commenter 9666 stated that reported steam 

load for an hour is reported at the measured temperature and pressure and is not corrected to ISO 

conditions.

Commenter 9666 stated that EPA proposal requires calculation and use of actual gross electrical 

output for each hour and useful thermal energy relative to ISO conditions. Commenter 9666 

stated that if EPA includes partial unit operating hours, the values already reported under Part 75 

will need adjustment.

Commenter 9666 stated EPA should clarify in the rule partial unit operating hours are included. 

Commenter 9666 stated that the Part 60 General Provisions make clear that partial unit operating 

hours are only used in emission calculations when that use is specified (60.13(h)(2)); subpart Da 

does not included partial unit operating hours for compliance calculations; and subpart KKKK 

does require inclusion of partial unit operating hours. Commenter 9666 stated that if EPA intends 

to include, EPA must ensure the data analysis to develop the final emission standard also 

includes such partial operating hours.

Commenter 9425 stated the requirement should be to report the gross electric output generated 

during the year and the potential electric generation of the facility. Commenter 9425 stated that 

reporting the gross electric output sold to an electric grid during the year can’t really be done, 

would have to report the net MW load, since the gross load is not sold to the grid. Commenter 

9425 stated the rule should define the potential electric output of the facility. Commenter 9425 

stated EPA should consider the methodology defined in part 75, i.e., nameplate load rating 

multiplied by 8,760 hours.

Commenter 9427 stated stationary combustion turbines are already required by Part 75 to 

measure heat input, including heat input to duct burners at associated HRSGs, and allocating 

gross output (MWh) of a common steam turbine electric generator by using heat input to 

combustion turbines and associated HRSGs would be a very straightforward process and should 

be allowed without the need for a plan approved by the Administrator.

Commenter 9425 stated the standard would need to allow for the additional CO2 produced for 

the number of starts a unit could potentially have. Commenter 9425 stated coal units combusting 

startup fuel or small amounts of coal, the minimum air flow through the boiler dilutes the 

measured percent CO2 to approximately zero; Commenter 9425 notes the accuracy of 

determining CO2 mass emissions during these period needs to be evaluated against the small 

increase in CO2 that would be reported.

Commenter 10681 questioned the basis for including only 75 percent of the “useful thermal 

output”, on page 1450 of the proposed rule.

Commenter 10095 supported the proposed strategy to only monitor the common exhaust for 

units that share an exhaust stack, but stated that if a single unit uses multiple stacks or ducts that 

each should be monitored.
11-18

Commenter 9666 stated that while EPA proposes to require EGUs with common stacks or 

multiple stack to monitoring “stack operating time”, there is not a requirement in the rule to 

record or report the adjusted electrical and thermal energy output values and if EPA wants those 

values, EPA must include a requirement in the rule.

Response 11.4-1: The final rule retains the requirement to use gross output (Pgross) in the 

compliance calculations in addition to allowing sources with permit requirements to monitor net 

energy output. For partial operating hours, the gross MW values reported under Part 75 must be 

adjusted using the unit or stack operating time, to convert them to MWh. 

EPA agrees with Commenter 9427 that it is unnecessary to submit a plan to apportion the gross 

output at a common steam turbine. The final rule allows the combined gross electrical load to be 

apportioned to the individual EGUs based on the fraction of the total steam load contributed by

each unit. If the units are identical, the combined hourly gross electrical load may be apportioned 

to the individual EGUs according to the fraction of the total heat input contributed by each unit. 

Comment 11.4-2: Commenters 9425 and 9666 stated EPA should include a provision in the rule 

allowing use a value of 1 or 2 MW for any hour during which monitoring gross load is zero. 

Commenter 9666 noted EPA previously developed a policy to allow use of default values for 

reporting under Part 75; because some such hours were included in the Part 75 data EPA used to 

support the emission limit, EPA should explicitly allow use of default values for the NSPS.

Response 11.4-2: EPA believes it is unnecessary to report a 1 or 2 MW default electrical load 

during operating hours when the actual gross output is zero, because the CO2 emission rate 

(kg/MWh) is not calculated on an hourly basis. Rather, zero gross output is considered to be a 

valid value for use in the compliance calculations.

Comment 11.4-3: Commenter 1899 suggested the use of mass-based compliance instead of ratebased compliance.

Response 11.4-3: The EPA disagrees with the commenter and the final rule retains the ratebased compliance approach.

11.5 QUALITY ASSURANCE AND QUALITY CONTROL (QA/QC)

Comment 11.5-1: Commenter 9666 supported reliance on Part 75 QA/QC.

Commenter 9666 does not understand EPA’s reference to compliance with part 75 Appendix D, 

as Appendix A is CEMS certification requirements, Appendix B is ongoing QA/QC 

requirements, and Appendix D is calculating heat input and mass emissions for SO2 units 

without CEMS. Commenter 9666 stated EPA should replace Appendices B and D with 

Appendices A and B.

Commenter 9593 supported exclusion of CEMS bias adjustment and data substitution provision.
11-19

Commenters 9471, 9666, and 9780 do not support bias adjustments from Part 75. Commenters 

9471 and 9666 noted the bias adjustment factor is a one-way (positive) adjustment that was 

justified based on the ARP's status as a market-based program, but it has not been used for other 

NSPS. 

Commenters 8937, 9426, 9661, 9780, 10095, and 10243 supported the use of unadjusted stack 

gas flow rate values in CEMS calculations, instead of the bias adjustment factors. Commenter 

9661 stated there is little margin with the compliance limits proposed by EPA, and requiring use 

of data that has a positive BAF applied to adjust for uncertainty in the measurement process 

would be punitive and inappropriately lead to situations of noncompliance.

Commenter 10095 stated EPA should allow grace periods from part 60 and part 75 for QA 

activities, such as for linearities and RATAs, as was incorporated into MATS.

Response 11.5-1: For units using CEMS to demonstrate compliance, the final rule requires 

unadjusted stack gas flow rate values to be used in the compliance calculations. Also, the 

standard frequencies for performing the required QA tests and the allowable grace periods 

specified in Part 75 apply to all affected units.

The incorrect reference to Appendix D of Part 75 for CEMS certification has been removed and 

replaced with a reference to Appendix A.

Comment 11.5-2: Commenter 9666 stated that to ensure that EGUs are not subject to 

duplicative and inconsistent QA/QC requirements, EPA must exempt EGUs using CEMS from 

the requirement in 60.13(a) to comply with performance specifications in Part 60, Appendix B 

and ongoing QA/QC under Part 60, Appendix F.

Commenter 9666 stated that if EPA wants CO2 mass emissions under this NSPS to be qualityassured according to Part 75, EPA must identify the QA/QC requirements in §60.13(a) as not 

applicable in Table 1 to Subpart TTTT, and should explicitly state in the applicable rules that 

those requirements do not apply. Commenter 9666 stated if there are specific elements of Part 

60, Appendices B and F that EPA believes should apply in lieu of Part 75, EPA should identify

them and solicit comment on that alternative approach. Commenter 9666 stated EPA’s proposal 

to require compliance with both QA/QC rules would result in significant overlap in testing and 

confusion regarding the validity of monitored CO2 CEMS data, contrary to EPA’s intent and 

assertions in its proposed ICR. Commenter 9666 noted that EPA previously provided an option 

to use Part 75 QA/QC in lieu of Part 60 requirements for CO2 and O2 monitors used to monitor 

SO2 and NOx in lb/MMBtu under Subpart Da (60.49Da(w)(3) and (4)).

Response 11.5-2: Table 3 of the final rule explicitly states that §60.13 is inapplicable, and that 

all emissions monitoring under Subpart TTTT is to be done according to Part 75.

Comment 11.5-3: Multiple commenters (2471, 9426, 9591, 9661, 9666, and 9780) requested 

that the current Part 75 calibration drift and RATA criteria remain the same. Commenter 10095 

supported the calibration drift in Part 75 and the applicable alternative specifications.
11-20

Commenter 9666 opposed any divergence from the calibration drift or RATA criteria in Part 75, 

and in particular the stringent criteria given for comment (daily calibration error of 0.3 percent 

for CO2 and O2 CEMS, and RATA specification of 2.5 percent for CO2 CEMS and stack flow 

monitors), as neither criterion are consistently achievable. Because EGUs have reported initial 

and daily CO2 and O2 calibration drift, and initial and annual stack flow RATA results since 

1994, EPA has robust database from which to determine whether the increased stringency is 

warranted and supported under subpart TTTT, and EPA would have provided this data 

demonstration if they had it.

Commenter 10554 stated that EPA should not require a daily calibration drift cap no greater than 

0.3 percent CO2 for CO2 CEMS because it is infeasible. Commenter 10554 asked that EPA retain 

the 7.5 percent (annual) and 10 percent (semiannual) limits as in Part 75.

Commenter 10095 stated that the relative accuracy standard of 2.5 percent is not supported by

current data, methods, or monitoring system equipment.

Commenter 9666 further noted that EPA evaluated CO2 and flow monitor RATA results reported 

under Part 75 (results showed 3.06 percent of 2736 CO2 RATAs and 5.78 percent on 3019 flow 

RATAs), and determined no revision was warranted; EPA concluded that tightening the standard 

would not result in any appreciable improvement in results, and also expressed concern that a 

standard closer to the achieved results would approach the variability of the reference method 

itself and be beyond the limits of current monitoring technology. Commenter 9666 stated that 

EPA must issue a proposal supported by data showing the criteria are necessary and achievable if 

EPA believes the criteria should be tightened. Commenter 9666 stated that more stringent 

QA/QC criteria in subpart TTTT would impact reporting under other NSPS programs, including 

ARP, since inconsistent QA/QC requirements would require separate databases for the different 

validation criteria.

Commenters 9426 and 9666 stated that EPA must evaluate the impact of data loss on compliance 

determinations due to additional QA/QC test failures under the more stringent criteria. 

Commenters opposed the more stringent daily calibration drift (9425) and relative accuracy

requirements (8023, 9425). Commenter 9425 stated the criteria are lower than any other EPA 

rule. Commenters (8023, 9425) stated EPA must provide data to show these standards are 

achievable. Commenter 9425 stated EPA cannot promulgate new requirements without data and 

analysis. Commenter 9425 stated these criteria would result in missing data. Commenter 9425 

stated lower QA/QC would require separate data sets for Part 75 and for Part 60.

Response 11.5-3: The final rule defers to the existing Part 75 CEMS performance specifications 

for calibration error and relative accuracy. If EPA believes, at a later date, that these performance 

specifications need to be revised, changes will be proposed in a separate rulemaking.

11.6 ADDITIONAL MEASUREMENT REQUIREMENTS

Comment 11.6-1: Commenters 9666 and 10023 objected to all additional measurement 

requirements on which EPA requested comment. Commenters 9666 and 10023 noted EPA did 
11-21

not provide any justification for additional requirements, and EPA must propose the 

requirements and identify the supporting data. Commenters 9666 and 1023 also noted that EPA 

did not rely on any of these in establishing the proposed emission standards.

Commenter 2471 has no objection to the use of Methods 1, 2F, 3A, and 4.

Commenter 10095 stated that none of the additional test methods are likely to improve the 

precision or accuracy of CEMS data.

Response: The additional and alternative measurement requirements described in the preamble 

of the proposed rule have not been finalized. The final rule defers to the test methods allowed 

under Part 75.

Comment:

Commenters 8023, 9425, and 9666 stated EPA should allow use of M2F and M2H or CTM-041 

but should not require them. Commenter 9666 explained that M2F was developed to eliminate 

high bias of stack flow measurements for cyclonic flow, and M2H and CTM-041 to correct for 

velocity decay near a stack or duct wall that is not present at other measurement points. 

Commenters 9425, 9666 stated any EGU concerned about overestimation of measured flow due 

cyclonic flow conditions or wall effects can opt to use the methods but there is no reason to 

require their use.

Commenter 10095 asked that M2F not be mandatory.

Commenters 9425, 9666 stated EPA should allow use of M2G, and can opt to use the best flow 

method for a particular application but should not be required to use.

Commenter 9425 stated that M2 should be allowed, if the facility can demonstrate compliance 

with the standard even with overstated flow and the resulting higher emission rate estimates.

Commenters 8023, 9425, and 9666 noted the methods impose additional burden. Commenter 

10554 stated that EPA should not require M2F because it is expensive, time-consuming, 

difficult to calibrate, and calculate flow during RATA testing. Commenter 10554 offered M2G 

as an alternative.

Response 11.6-1: The final rule allows the use of Method 2, 2F, or 2G at the discretion of the 

owner or operator after a source has examined the flow patterns in the stack or duct to see if 

significant flow angularity is present; if so, the use of Method 2F or 2G must be used as 

applicable.

Comment 11.6-2: Commenters 8023, 9666 stated that Part 75 allows use of 3, 3A, and 3B for 

dry molecular weight. Commenter 8023 recommended that these methods be an option. 

Commenters 9425, 9666 stated EGUs should be allowed to use any method allowed under Part 

75. Commenter 9666 stated EPA has not provided any explanation for the restriction to M3A or 

M3B only.
11-22

Commenter 10095 stated that M3A and M3B should be allowed but not required. Commenter 

9425 opposed a requirement to use M3A. Commenter 1054 asked that EPA not require Method 

3B.

Response 11.6-2: The final rule defers to the test methods required and allowed for under Part 

75.

Comment 11.6-3: Commenter 9666 did not understand why EPA solicited comment on use of 

M4, because these sources are already required to use M4 for flow RATAs (M2, M2F, or M2G 

for performing flow RATAs and each require use of M 4), and asked that EPA explain how use 

of M4 would differ from what is already required under Part 75. Commenter 9666 indicated that 

Part 75 allows use of both the reference method and the approximation method in M4.

Commenter 10095 supports the use of M4.

Response 11.6-3: The final rule defers to the test methods required and allowed for under Part 

75.

Comment 11.6-4: With respect to ambient air Argon concentration, Commenter 9666 stated the 

negative error of approximately 0.4 percent suggested in M3 is trivial and not worth correcting, 

and noted that EPA has not considered the error significant enough to require correction in the 

past. Comment 9666 stated EPA must provide explanation and propose a procedure for including 

argon in the analysis. Commenter 9666 stated EPA would best make a proposal for revision to 

M3 rather than in an individual NSPS. 

Commenter 10095 stated dry gas molecular weight requirements should be consistent with Part 

75 and not require the change to use ambient air argon concentration and molecular weight. 

Commenter 10095 stated this change would minimally improve accuracy given the insignificant 

percentage of argon in ambient air, but further complicates compliance with additional 

calculations than that required in Part 75.

Response 11.6-4: The additional and alternative measurement requirements described in the 

preamble of the proposed rule have not been finalized. 

Comment 11.6-5: With respect to requiring use of a value for pi of 3.14159, Commenter 9666 

stated that EPA provides no explanation for this proposed requirement. Commenter 9666 further 

noted that to the extent EPA proposes this value to obtain greater accuracy, that effort is 

misguided. Commenter 9666 stated the impact on CO2 mass emissions would be insignificant 

and would suggest a level of accuracy that simply does not exist in the required stack 

measurements.

Response 11.6-5: The additional and alternative measurement requirements described in the 

preamble of the proposed rule have not been finalized. 

Comment 11.6-6: Commenter 9666 noted that language for installing moisture monitoring 

systems for dry basis CO2 CEMS could be interpreted as eliminating use of default moisture 

values (see 75.11(b), Proposed Subpart Da section 60.46Da(f)(2)(1), Subpart KKKK section 
11-23

60.4373(b)(1), Subpart TTTT section 60.5535(b)(1)). Commenter 9666 stated they can think of 

no reason why EPA would eliminate use of default moisture values for new units, and hope it 

was not intended to eliminate use of default values.

Commenter 9666 stated EPA must issue a rulemaking for eliminating moisture default value 

option for public comment. Commenter 9666 stated that eliminating the option in the NSPS 

effectively eliminates them for NSPS units subject to Part 75.

If CO2 is measured on a dry basis, commenter 9593 stated the rule should require a continuous 

moisture monitoring system or allow a fuel-specific default moisture value for each unit 

operating hour, as is consistent with Part 75.11(b). 

Commenter 10100 stated EPA should eliminate the requirement to monitor stack moisture 

content using CEMS, noting that nearly all solid fuel CEMS systems are dilution extraction 

systems, so moisture is not an issue. Commenter 10100 noted that moisture monitoring 

capability is unusual in CEMS.

Response 11.6-6: The final rule allows the fuel-specific moisture defaults in §75.11(b) to be 

used in lieu of continuously monitoring the stack gas moisture content.

Comment 11.6-7: Commenter 9666 objected to the requirement to measure the stack or duct 

dimensions using a laser device (see Proposed Subpart TTTT section 60.5535(b)(3), Subpart Da 

section 60.46Da(f)(2)(iii), Subpart KKKK section 60.4373(b)(3)). Commenter 9666 stated the 

record contains no evidence to support that existing methods are not sufficiently accurate or that 

laser devices are more accurate. Commenter 9666 stated the requirement imposes additional cost 

and burden with no benefit.

Commenter 10095 stated there is no mention of the conditions under which measurements 

should be made; off-line, full-load, ambient conditions affect expansion and contraction of ducts 

and stacks. Commenter 10095 stated EPA should provide explanation how the laser devices 

improve the measurement accuracy, and otherwise, EPA should not require this measurement. 

Commenter 9593 stated the requirement to measure stack dimensions at 3 distinct locations 

should be reduced to 2 distinct locations to prevent installation of an additional sample port just 

for stack dimension measurement. Commenter 9593 stated the stack dimension requirement 

should be to within 0.25 inches at the flow monitor location.

Commenter 9426 supported the use of a laser device to make stack diameter measurements. 

Commenter 9426 stated that the EPA should make it clear in the final rule that the laser 

measurements are to be taken only at the stack testing or flow monitoring elevation on the stack, 

and that only a single set of measurements should be required if the testing elevation and the 

flow monitoring elevation are closely coupled in the stack. Commenter 9426 stated the 

requirement to measure stack dimensions at 3 distinct locations should be reduced to 2 distinct 

locations because the cost of installing two additional ports to accommodate a third measurement 

location does not justify the potentially small increase in measurement precision.
11-24

Response 11.6-7: The EPA thanks the commenters for the comments and is finalizing the rule 

with the requirement to measure stack gas flow according to Appendix A or part 75 and 

§75.10(a)(3)(i). Additionally the EPA is finalizing measurements of diameter to be required at 

only 2 locations for circular stacks and 2 locations for each length and width of rectangular 

ducts.

11.7 THE MONITORING PLAN

Comment 11.7-1: Four commenters (8023, 9425, 9666, and 10023) had no opposition to the 

Monitoring Plan requirement. Commenters 9425, 9666, and 10023 indicated that new EGUs 

already have to develop these plans under Part 75 and are submitted by Part 72 designated 

representative (DR); Commenters 9425 and 9666 noted that information for NSPS must 

be submitted by facility owner or operator, which may be someone other than the DR. 

Commenters (8023, 9425, 9666, and 10023) requested EPA clearly state that the Part 75 plan 

submitted by the Part 72 DR would constitute compliance with NSPS requirement. Commenters 

9425 and 9666 requested that to avoid having two individuals certify the same information, 

where the NSPS relies on information already submitted and certified under Part 75, no further 

submission or certification should be required.

Response 11.7-1: For Acid Rain Program units, the final rule simply affirms the existing 

requirement for monitoring plan submittals to be made by either the Designated Representative 

(DR), the Alternate DR, or a delegated agent of the DR. To ensure consistent implementation of 

the rule, the owner or operator of an affected unit that is not in the Acid Rain Program (ARP) 

must, at a minimum, appoint a DR and the DR must register with the Clean Air Markets Division 

(CAMD) Business System. The monitoring plan submittals for a non-ARP unit must be made by

the DR, or, if applicable, by the ADR, or by a delegated agent of the DR.

Comment 11.7-2: Commenter 9666 stated the Monitoring Plan rule language is too broad in that 

section 75.53(g) and (h) are not limited to CEMS for CO2 mass emissions only, and EPA should 

limit the Monitoring Plan information to CO2 emissions monitoring.

Response 11.7-2: The final rule requires reporting of only those monitoring plan data elements 

in §75.53(g) and (h) that are needed to quantify the hourly CO2 mass emission rate (tons/hr). 

This clarification is especially important for units that are not in the Acid Rain Program.

Comment 11.7-3: Commenter 10095 supported the use of ECMPS to collect reports, CO2-

related data, and gross energy output data for a unit, provided that EPA can supply any necessary

updates to ECMPS in a timely manner. Commenter 10095 noted that ECMPS already contains 

megawatt data and should be modified to also allow the reporting of steam flow rather than 

pulling generation data from another source. Commenter 10095 stated that EPA should allow 

permitting authorities the flexibility to collect reports and data through different mechanisms if 

desired or needed.

Response 11.7-3: The final rule requires the quarterly CO2 emissions reports and the compliance 

reports to be submitted electronically using ECMPS.
11-25

Comment 11.7-4: Commenter 10029 suggested that EPA require EGUs to prepare monitoring, 

reporting, and verification (MRV) plans to ensure proper monitoring and reporting of the 

disposition or fate of CO2 once transferred from an affected EGU, similar to the MRV plans 

under 40 CFR 98.448.

Response 11.7-4: The EPA thanks the commenter for their comment the EPA is requiring in the 

final rule reporting under subpart RR of part 98 and points the commenter to see Chapter 6 of 

this document for responses relating to 40 CFR Part 98 Subpart RR.

11.8 SCHEDULE FOR MONITORING SYSTEM CERTIFICATION

Comment 11.8-1: Commenter 9666 supported the 180 days allowed for CEMS certification. 

Commenter 9666 pointed out that while the preamble indicates all "monitoring systems" for CO2

may be certified in timeframe for 40 CFR 75.4(b), they could not find rule language that 

implements this; the commenter noted that the two rules should have the same certification 

deadlines, and the regulatory text should refer specifically to "monitoring systems required to 

monitor CO2 mas emissions" rather than to CEMs, to reflect that Appendix G monitoring 

systems rely on certified fuel flow meters and not CEMS.

Commenter 9514 stated EPA needs to reduce the 180 days allowed for CEMS certification, 

noting that the 180 day allowance in Part 75 reflects the more difficult task of retrofitting 

monitoring equipment onto existing sources and new sources should not face similar challenges. 

Commenter 9514 recommended 90 days for CO2 CEMS certification.

Response 11.8-1: The EPA disagrees with Commenter who stated that the window of time 

allowed to complete certification of the continuous monitoring systems should be shortened. The 

180 day certification window specified in §75.4(b) is the existing requirement for new Acid Rain 

Program (ARP) units. The Agency believes it is inappropriate to deviate from that established 

certification timeline. Nearly all of the affected units under Subpart TTTT will also be in the 

Acid Rain Program. 

11.9 ANNUAL OR MULTI-YEAR COMPLIANCE PERIODS

Annual vs. Multi-Year Basis

Comment 11.9-1: Commenter 9514 stated that even the 12-month compliance will leave the 

compliance status of newly constructed sources uncertain for an extended period. 

Multiple commenters (8964, 8969, 8970, 8973, 8995, 9318, 9671, 9672, 9736, 10392, and 

10876) did not support a short-term standard but if EPA decides to adopt a short-term standard 

the commenters asked that it be based on vendor guarantees of unit performance during precommissioning testing.

Response 11.9-1: The EPA disagrees with the commenter 9514 and compliance is to be assessed 

solely on the basis of whether the average CO2 emission rate over the specified 12-operating 

month averaging period meets the standard. For more discussion on the 12-operating month 

compliance period please see section IV.C. of the preamble
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Support Multi-Year Compliance

Comment 11.9-2: Commenter 10239 stated EPA must include a multi-year compliance option.

Commenters 9515, 10031, 10089, 10095, 10098, 10239 supported multi-year compliance 

periods. Commenters 10098, 10239, and 10788 supported the 84-month compliance period. 

Commenter 10031 supported a 24 month calendar average.

Commenter 9666 recommended that EPA establish a single compliance period on a calendar 

year or longer basis for both coal-fired and NGCC units. Commenter 9666 stated that requiring 

more frequent compliance demonstrations would hinder operational flexibility without providing 

any additional environmental protection. 

Commenter 9664 stated 84-month compliance option increases operational flexibility. 

Commenter 9964 indicated this is helpful in earliest stages of facility operation and early years 

of the performance standard, where captured CO2 is delivered offsite to sequestration not under 

owner control. Commenter 9471 stated compliance under a sliding scale over a 7-year period 

provides some additional flexibility for new coal units with CCS, and it also implicitly

acknowledges the uncertainties as to when or if CCS technology will be developed.

Commenters 9666 and 10023 stated a multi-year compliance period, such as the proposed 84-

month compliance period for coal-fired EGUs, would be justified because of the nature of the 

alleged effects on public health and welfare. Commenters 9666 and 10023 stated this approach 

would be consistent with the year-to-year changes in operations and emissions of EGUs. 

Commenter 9664 stated the 84-month compliance option minimizes rule effects on electricity

prices to a certain extent, but unlikely to translate to significant cost benefits associated with 

former 30-year alternative.

Commenter 9471 supported the regulatory flexibility for the 84-month compliance period, but 

does not view it as a meaningful provision that preserves future coal-fired generation.

Commenters 2470 and 9035 asked that EPA consider compliance flexibility to allow time for 

CCS technology development. Commenter 9035 offered two options: 1) allow a percentage of 

capture over an extended period of time (e.g., 20 or 30 years), or 2) require a set percentage of 

capture by a nearer set date but allow some time for new plants to operate without CCS.

Commenter 9317 stated that the compliance period should be no shorter than a 12-month rolling 

average but an 84 month averaging period could create problems with enforcement. Commenter 

9317 stated that a limit more consistent with the five year term of a title v permit would be more 

logical.

Commenters 3862, 8967, and 10525 supported a choice to maintain the 84-operating month 

rolling average or the 12-operating month rolling average.

Commenter 9765 asked that EPA clarify in detail why the 84 month averaging period was 

proposed and why it is preferred over the 30 year period originally proposed in April 2012.
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Commenter 1900 asked that EPA consider 24 months as the compliance period.

Response 11.9-2: A 12 operating month compliance period has been retained for the final rule 

for all affected EGUs. More discussion on this can be found in section IV.C of the preamble.

Oppose Multi-Year Compliance

Comment 11.9-3: Commenter 8957 believed the 84-month compliance standard runs counter to 

the Agency’s argument that CCS is commercially available, and why would an 84-month period 

be needed to dampen short-term excursion if the technology is already available. Commenter 

8957 believed the 12-month standard is sufficient.

Commenter 7977 stated that enforcement of the 84-operating month rolling average is 

problematic because operating permits issued under Part 70 or 71 are five years.

Commenter 10869 noted that the 84-operating month compliance option is problematic and 

should be tightened to "ensure that it does not merely serve as a loophole for new high-emitting 

power plants to continue to be built with a high risk that those emissions may never be 

significantly reduced." Commenter 10869 further stated, "Given the fact that many U.S. coal 

plant operators have resisted installing pollution controls for sulfur dioxide (SO2 scrubbers), their 

assurances that CCS will be added at some future date must be viewed with some degree of 

skepticism. Finally, if a plant's backers fail to include the cost of a future CCS retrofit in the 

plant's original price tag that could prevent regulators, ratepayers, and investors from knowing its 

true cost and judging how the proposed plant compares with cleaner energy alternatives."

Commenter 10869 asked that the compliance period be as short as possible and also 

recommended "including a provision requiring power plant owners who want to employ this 

option to simultaneously invest in renewable energy, energy efficiency, or other low carbon 

technologies that would compensate for the emissions released during the first years of operation 

as a conventional coal plant."

Commenter 8924 disagreed with the 30-year average compliance period.

Response 11.9-3: A 12 operating month compliance period has been retained for the final rule 

for all affected EGUs. More discussion on this can be found in section IV.C of the preamble

Support 12-month Compliance

Comment 11.9-4: Commenters 2470, 9591, 10100, 10554, and 10788 recommended EPA to 

allow a choice of either 12-month rolling average or an annual basis (calendar year). Commenter 

10100 noted that some facilities will prefer 12-month rolling average (peaking units, extreme 

seasonal weather), and some facilities will prefer a calendar year average (less variability over 

year, extreme summer weather). Commenters 9591, 10095, 10100 noted that calendar year basis 

is consistent with ARP and MRR.

Commenter 10239 believed a 12-month compliance period is necessary.
11-28

Commenters 8957, 9033, 9591, 9678, 9780, 10681, and 10693 supported the 12-month rolling 

average calculation for compliance. Commenter 10389 noted the rolling 12-month compliance 

provides critical flexibility for start and stops or burning oil.

Commenter 9425 believed the 12-month method of compliance is an improvement. Commenter 

9425 stated EPA should clarify that the compliance determination does not begin until there is 

12 months of data to make the calculation, citing precedent for this (310 CMR 7.29 in 

Massachusetts).

Commenters 7990, 9042, 9194, 9426, 9592, 9666, 9777, 10023, 10031, 10095, 10098, and 

10239 supported a 12-month compliance based on an annual standard (calendar year), not a 

rolling average. Commenters 9592, 10095, 10239 stated an annual basis for compliance will be 

less costly to industry, reduce burden, easier to administer, and will provide the same level of 

compliance assurance. Commenter 10095 stated EPA has not identified any environmental 

benefits that warrant rolling 12-month compliance. Commenter 10095 stated that if EPA chooses 

a rolling 12-month compliance, EPA must clearly identify why that compliance period is a better 

balance of economic, environmental, and energy considerations that a block calendar compliance 

period. Commenter 10031 preferred a 24 month calendar average but 12 month calendar year 

average was the second choice.

Commenter 10095 stated EPA must revise the definition of “operating month” to provide a 

threshold exclusion for months when minimum amounts of fuel are combusted (e.g., only fuel 

combusted was for testing, equipment exercising, post maintenance, compliance testing, etc.)

Commenter 9666 stated that the additional language in Proposed Subpart Da section 60.46Da(d) 

is confusing and should be deleted; although compliance is determined at the end of each 

operating month, compliance is not determined "for the month."

Response 11.9-4: A 12 operating month compliance period has been retained for the final rule 

for all affected EGUs. The compliance determination is not made until 12 operating months has 

occurred, however the hourly CO2 data will be reported quarterly via part 75’s ECMPS client 

tool during those first 12 operating months and thereafter. More discussion on this can be found 

in section IV.C of the preamble

Include an Option for 12-month Compliance

Comment 11.9-5: Commenter 9666 supported providing owners or operators with an option of 

complying on a 12-operating month rolling average basis if they so choose.

Response 11.9-5: The 12 operating month compliance period has been retained for the final rule 

for all affected EGUs. More discussion on this can be found in section IV.C of the preamble.

Not Set a More Stringent Standard for Multi-Year Compliance

Comment 11.9-6: Commenters 9515, 10023, 10098, 10239 disagreed with a lower emissions 

limit for multi-year compliance timeframe. Commenter 10239 supported an emissions limit that 

is the same as the limit for 12-month compliance.
11-29

Commenter 9666, 10095 did not believe that a compliance period longer than 12 months justifies 

setting a more stringent standard for either coal- or gas-fired EGUs.

Commenter 10095 stated intermediate standards are not warranted for longer compliance 

periods.

Commenter 9780 stated it is not clear why EPA imposes a 12-month operating average that 

undercuts flexibility, if the goal of the 84-month compliance option is to provide additional 

flexibility to units installing a new technology.

Commenter 9780 stated that if EPA holds a unit liable for every day of the 84-month compliance 

period if the CO2 standard is exceeded, there is already more than ample incentive to ensure 

careful compliance with an additional 12-month operating average standard.

Response 11.9-6: A 12 operating month compliance period has been retained for the final rule 

for all affected EGUs. More discussion on this can be found in section IV.C of the preamble

Include Stringent Measures for 84-month Compliance Option

Comment 11.9-7: Commenter 9660 indicated that States are concerned that the 84-month option 

may pose compliance and enforcement issues if a power plant fails to meet the NSPS. 

Commenter 9960 stated EPA should include effective deterrence mechanisms, adequate 

contingency measures in the event that the plant violates the NSPS, and mandatory reporting of 

emission averages at specified intervals to be able to gauge whether the plant is on track to 

comply with the NSPS and allow for timely corrective action as needed.

Commenter 5537 noted the 84-month compliance option could create difficulties in effective 

enforcement if the unit fails to meet the NSPS. Commenter 5537 stated the longer term 

compliance option should be done to seek greater total CO2 reductions over the lifetime of the 

EGU relative to the 12-month option, provided effective deterrence mechanisms at the outset to 

avoid later noncompliance, scaled penalties for violating the standard, and should be uniformly

applied across all states and regions. Commenter 5537 stated noncompliance penalties should 

continue to be assessed according to the more stringent CO2 emission limit of the 84-operatingmonth option on a rolling monthly basis. Commenter 5537 stated the option should promote 

greater technology innovation for installation of measures that go beyond that needed for 12-

month compliance standard. 

Commenter 5537 stated the standard should be more stringent relative to the 12-month 

compliance standard.

Commenter 9514 stated the agency must include interim demonstrations for the 84-month 

compliance option, to ensure compliance. Commenter 9514 stated EPA should limit the option’s 

application only to those sources that may need the additional flexibility it provides.

Commenter 9514 stated EPA must require milestones to ensure that regulated sources take all 

necessary steps to prepare for, and operate under, the 84-month emission limitation period.
11-30

Commenter 9514 stated EPA must require that the operator demonstrate at the end of each 12-

operating month period that the source will meet the requirement. Commenter 9514 further 

stated the permitting authority would be required to approve the certification and demonstration 

of compliance; regulators and the public could bring an enforcement action if the demonstration 

was not sufficient to establish compliance with the NSPS. Commenter 9514 noted these steps 

will avoid situations where sources find themselves ultimately unable to achieve sufficient 

emission reductions to make up for excess emissions during the initial months of operations.

Commenter 9514 indicated the key question to answer for interim analysis is whether they retain 

the capability to comply with the 84-month limit given the time that remains in the compliance 

period. Commenter 9514 suggested a 3-step process that would enable permitting authorities to 

annually evaluate the ability to meet the 84-month compliance: (1) Step 1 - Determine the 

projected 84-month MWh output of the source; (2) Step 2 - Determine the minimum practicable 

84-month CO2 emissions for the source; and (3) Step 3 - Calculate the source’s minimum 

practicable 84-month CO2 emission rate. Commenter 9514 stated if the “minimum rate” exceeds 

the standard, then the source is in violation and must cease operating until it is able to come into 

compliance.

Commenter 9514 stated EPA must ensure that information on the progress of sources subject to 

the 84-month compliance option is available. Commenter 9514 stated this information is needed 

for EPA to review and revise this NSPS and for other source categories where CCS may be 

appropriate, and for citizens concerned about health and environmental impacts of power plants. 

Commenter 9514 stated the rule needs to include specific deadlines and required filings with the 

permitting agency to ensure all carbon capture equipment, necessary infrastructure and 

sequestration agreements, and any other components are in place. Commenter 9514 stated these 

measures must be incorporated into a source’s Title V permit, to ensure they are binding and 

enforceable.

Commenter 9514 stated the rule should clarify the 84-month compliance option is available only

during a source’s initial 84 months of operation after construction; after this, EPA's rationale for 

the extended compliance period no longer applies, and the flexibility provided by the 84-month 

option is no longer warranted. Commenter 9514 stated that after their initial 84 operating 

months, all sources should be subject to the 12-operating month standard.

Commenter 9514 stated the 84-month option should automatically terminate for new plants 

commencing construction eight years or more after the proposed rule, i.e., in 2021. Commenter 

9514 stated that automatic termination of the provision will prevent unwarranted expectations 

that the option will be renewed, but does not precluding EPA from renewing the provision if it is 

still determined to be appropriate in 2021.

Response 11.9-7: A 12 operating month compliance period has been retained for the final rule 

for all affected EGUs. More discussion on this can be found in section IV.C of the preamble

NGCC

Comment 11.9-8: With respect to NGCC units, Commenter 9666 supported basing compliance 

requirements on an annual (calendar year) average basis because a single compliance period each 
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year simplifies compliance. More frequent compliance demonstrations would hinder operational 

flexibility without providing any additional environmental protection. 

Commenter 9666 suggested that EPA provide owners and operators of NGCC units with the 

option of complying on a 12-operating-month rolling average basis.

For NGCC units, commenter 10243 supported the methodology of calculating 12-month average 

emission rates based on hourly mass CO2 emissions and would also support a multi-year 

averaging period.

Commenter 10466 asked that any standard for large natural gas combined cycle turbines be 

implemented on a 3-year average basis. Commenter 10466 noted that the 3-year average ensures 

that efficiency declines due to blade fouling are accounted for.

Response 11.9-8: The 12-operating month rolling average compliance periods have been 

retained in the final rule and for a detailed discussion on this topic please see section IV.C of the 

preamble. Initial performance stack tests and interim compliance assessments are not required. 

However, the regulatory agencies and other interested persons can monitor the progress of the 

affected EGUs by reviewing the quarterly Part 75 electronic emissions reports. These reports 

include hourly CO2 mass emission rates (tons/hr), hourly unit or stack operating times, and 

hourly gross electrical loads. This information is sufficient for regulatory agencies and auditors 

to make general assessments of the units’ ability to meet the emission limits. 

Hourly, Monthly, Daily

Comment 11.9-9: Commenter 9033 suggested that hourly reporting data is a significant burden 

to the operator and not required.

Commenter 8952 stated hourly reporting is not a necessity because the total fuel flow 

corresponds exactly to the total CO2 mass emissions and these data are already reporting through 

regulatory channels (FERC). Commenter 8952 stated that where fuel monitoring reporting is 

already underway, the rule should allow these data to be used as substitute in lieu of collecting 

hourly information.

Commenter 8952 saw no reasonable justification for the requirement to quantify each hourly 

emission period when the averaging period is 12 or 84 months. Commenter 8952 stated the 

requirement imposes burden without any environmental or other benefit.

Commenter 8952 noted there is no public health or environmental protection benefit from 

compliance on a monthly basis or even to require continuous hourly data collection; these 

requirements are therefore not reasonable. Commenter 8952 stated it would be far more accurate, 

at the end of each month, to compute a new rolling average by summing all CO2 emitted in the 

past 12 months and dividing by the total MWhs generated in the past 12 months.

Commenter 10239 did not support compliance determinations each month for a rolling 

compliance period.

Commenter 8952 stated that monthly data collection would be more than sufficient for reporting 

purposes.
11-32

Commenter 9514 stated daily computation poses no additional burden on permitting authority 

audits, since those authorities have to review hourly and daily emission data in order to properly

audit the monthly averages, and software applications can be used. Commenter 9514 also noted 

the utility industry is already required to monitor and electronically report hourly CO2 emissions 

data under Part 75. See 40 C.F.R. section 75.64(a)(6). 

Response 11.9-9: The EPA is utilizing the Acid Rain Program part 75 monitoring and reporting 

procedures as much as practicable for compliance with the emission standards set in this rule. 

The EPA believes that many sources will already be reporting under part 75 however additional 

detail is needed in the final rule for those units potentially not subject to the applicability

requirements under the Acid Rain Program.

Daily Violations

Comment 11.9-10: Commenter 9514 stated EPA should require daily, rather than monthly, 

calculation of rolling annual average, as is consistent with CAA penalty provisions for “each day

of violation”, not merely those days on which compliance happens to fall. Commenter 9514 

stated that once a facility is in violation of the standards, penalizing each additional day spent 

operating in excess of the applicable CO2 limit will better ensure that the source comes into 

compliance as soon as possible. Commenter 9514 noted that sources will likely calculate the 

rolling average each day even if only monthly data is submitted to EPA, and therefore this 

change would likely impose little additional burden.

Commenter 9033 suggested the requirement to report daily violations is unreasonable since the 

basis of compliance is a 12 month rolling average.

Commenter 10100 supported calculating the number of daily violations within an averaging 

period, which prevents double-counting of violations across different rolling averaging periods.

Commenter 8952 stated determining daily violations is not reasonable. Commenter 8952 stated 

that the inclusion of hourly or daily emissions rates will become a determinant factor in 

establishing any potential penalty.

Commenter 10681 stated that the discussion of daily violations is inappropriate and if EPA wants 

to provide for daily violations, EPA should develop and propose a "not to exceed" daily emission 

limitation.

Commenter 9317 did not agree with EPA's proposal on determining daily violations and stated, 

"There could only be one violation for each month where the rolling average exceeds the 

standard."

Commenter 10048 asked that EPA consider assessing violations on a case-by-case basis. 

Commenter 10048 suggested that instead of counting all days within the operating period as 

violations, EPA could determine the specific days that contributed to the actual exceedance and 

only count those days. 
11-33

Response 11.9-10: Affected units must begin using ECMPS to submit quarterly electronic 

emissions reports as soon as the monitoring systems have been certified. These reports, which 

are also required for new units that are subject to the Acid Rain Program, include hourly CO2

mass emission rates (tons/hr), hourly unit or stack operating times, and hourly gross electrical 

loads. The vast majority of the units in Subpart TTTT are also in the Acid Rain program---

therefore, the requirement in Subpart TTTT to report hourly CO2 emissions data introduces no 

new reporting burden. Note that affected sources are not required to calculate hourly, daily, or 

monthly CO2 emission rates in units of the standard (kg/MWh)---rather, a single CO2 emission 

rate is calculated at the end of each compliance period, as the ratio of the total CO2 mass to the 

total gross output for the valid operating hours in that period

If the standard is exceeded for a particular compliance period, it counts as one violation. The 

EPA has removed the concepts of “excess emissions” over the 12 operating month averaging 

period.

Format of the Standard, Total Emissions over Total Electrical Output

Comment 11.9-11: Commenters 8952, 9033, 9591, 9678, 10095, and 10389 supported 

compliance calculation as total CO2 emissions over total generation data over the period. 

Commenter 8952 noted the calculation is an improvement.

Commenter 9678 stated this ensures that plants that cycle more frequently in some months have 

additional compliance flexibility.

Commenter 10100 stated that for 12-month calendar year average, compliance should be based 

on annual emissions over annual MWhs (instead of an arithmetic average of 12 monthly values).

Commenter 9514 supported the abandonment of the April 2012 strategy of using the "average of 

12 monthly averages" to determine compliance.

Commenter 9780 should address whether the average is a straight average of the monthly

emissions rates, or is the average weighted in any way by output in the month, and any weighting 

in determining the average must be specified.

Commenter 8952 suggested simplifying the method for computing the 12-month rolling average. 

For fuel consumption monitoring, commenter 8952 stated monthly data collection would be 

more than sufficient for reporting purposes.

Commenter 10389 stated the only potential problem is where a facility is burning fuel in reserve, 

but not delivering “useful energy output” to the grid; by counting the emissions, but no megawatt 

hours, a plant owner would artificially increase its average emission rate.

Commenter 10095 stated EPA’s calculation for longer compliance periods must continue to be 

the sum of emissions for all operating hours over the compliance period over the sum of all gross 

energy output over the same compliance period.

Response 11.9-11: In the final rule the EPA is finalizing the method to sum all hourly emissions 

and energy output for the compliance period and then doing the calculation for an emission rate 

to be compared to the applicable emission standard. The EPA believes this method provides the 
11-34

greatest consistency of comparing emission rates for the long averaging times to the applicable 

emission standards.

Include 0 for Emission Rates if Not Operating

Comment 11.9-12: Commenter 9780 stated EPA should clarify that if a unit is not operating 

during a calendar month, an emissions rate of 0 lbs/MWh is to be used for that month in the 

rolling average calculation.

Response 11.9-12: The EPA does not agree with the commenter and compliance is assessed on a 

12- operating month basis. Non-operating months are disregarded when determining compliance.

Compliance Issues with 3-Year Applicability Threshold

Comment 11.9-13: Commenter 9427 stated EPA needs to address multiple issues related to the 

3-year application threshold: (1) What if a combustion turbine owner/operator complies with 

requirements such as reporting, but it turns out that the requirements were not applicable because 

the 3-year thresholds were not met? Alternatively, what if a combustion turbine owner/operator 

assumes the requirements would not apply but then at the end of a 3-year period finds the 

applicability thresholds were met? (2) In Title V annual compliance certifications, how can an 

owner/operation certify compliance when applicability is not known? (3) How is compliance 

handled if a combustion turbine may or does routinely operate above and below applicability

thresholds over consecutive but overlapping 3-year periods? Commenter 9427 recommended the 

following to address these issues: (1) Owners/operators of new stationary combustion turbines 

that meet design applicability criteria but do not meet all operating applicability criteria could 

certify that their facility is not subject to the standard; and (2) By notification or certification, 

owners/operators should be able to revise the applicability status to reflect changes in operating 

status over successive "three consecutive calendar years" periods.

Response 11.9-13: The 3-year thresholds have been removed from the final rule. Additionally,

compliance for all EGUs subject to emission limits is over a 12 operating month rolling average. 

For more discussion on the 12-operating month compliance period please see section IV.C. of 

the preamble

Compliance Issues Related to Applicability

Comment 11.9-14: Given the applicability criteria for fossil fuel-fired boilers and IGCCs, 

Commenter 10095 stated that EPA needs to clarify how the applicability criteria interact with the 

84-month compliance period, and whether the timeframes within an 84-month period that do not 

meet the applicability criteria count towards compliance.

Given the applicability criteria for combustion turbines, Commenter 10095 stated that EPA 

needs to clarify how the applicability criteria interact with the 12-month rolling average 

compliance period, and if a CT meets all three of the applicability criteria below listed over a 

three year average but fails to meet one of the criteria for a year during the same three year 

period, from which 12-operating month rolling average compliance determinations are the 

affected facility excluded, and to which 12-operating month rolling average compliance 
11-35

determinations do the affected facility have compliance obligations? (If a CT does not meet the 

10.0 percent fossil fuel criteria, from which 12-operating month rolling average compliance 

determinations are the affected facility excluded? If a CT does not meet the 90 percent natural 

gas criteria, from which 12-operating month rolling average compliance determinations are the 

affected facility excluded? If a CT does not meet the one-third and/or 219,000 MWh sales 

criteria, from which 12-operating month rolling average compliance determinations are the 

affected facility excluded?)

Commenter 9427 recommended a "three consecutive calendar years" compliance timeframe to 

address variability issues, shortcomings in EPA's BSER database, and there is no scientific 

reason to require a 12-operating month compliance period for carbon dioxide.

Commenter 3862 noted that an option based on a 36 month operating month rolling average 

would be consistent with other 3 year applicability periods in the proposed rule.

Commenter 7977 recommended a 3-year averaging period to determine applicability of the rule 

to allow for usage during emergencies regardless of the type of unit, purpose, or fuel.

Response 11.9-14: According to §60.5508 of Subpart TTTT, the rule applies only to new units 

that commence construction after the specified date. After careful consideration of the comments 

received, the initial applicability criteria in the final rule have been simplified. Applicability is 

based on the size of the EGU (≥ 250 mmBtu/hr heat input capacity for fossil fuel combustion) 

and the size of the generator (> 25 MW) producing electricity for sale. It is therefore not 

necessary for a unit to operate for up to 3 years before it can be determined that it is subject to 

the rule. In the final rule, the annual and 3-year rolling average assessments of the unit’s status 

have been eliminated. A unit that meets the applicability criteria in §60.5509(a)(1) or (a)(2) and 

is not exempted under §60.5509(b) will remain an affected unit; no “exit ramps” are provided.

11.10 VALID DATA, BACKUP MONITORS, MISSING DATA 

PROCEDURES, AND MINIMUM DATA AVAILABILITY

Valid Data

Comment 11.10-1: Commenter 9666 stated EPA does not define the term "valid 

data." Commenter 9425, 9666 indicated EPA must be clear about what it means by "valid data".

Commenter 9666 indicated one interpretation is that data are valid as long as the MS is not “out 

of control” (consistent with Part 75). Commenters 9425, 9666 stated that use of part 75 definition 

for "out of control" would allow EGUs to rely on the same definition for both rules. Commenters 

9425, 9666 stated Subpart Da and Subpart KKKK definitions are not consistent with Part 75. 

Commenter 9666 objected to EPA’s use of "out of control" period beginning and ending with the 

corresponding "quadrant" of an hour instead of the corresponding clock hour under Subpart Da, 

revised without notice and comment, and the revision to the Subpart KKKK “out of control”

definition.
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Commenters 9425, 9666 stated that having inconsistent definitions for valid data make 

programming difficult, results in inconsistent data sets, and inappropriate invalidation of data. 

Commenter 9666 stated facilities would have to have systems in place to track the different data 

validation rules and how data under each rule are affected.

Commenter 9666 believed that the Subpart Da definition of out of control would not result in a 

greater level of data availability than the Part 75 definition, citing issues with calibration error 

tests and RATA.

Commenters 9425, 9666 stated EPA should revise the definition in subpart Da to be consistent 

with Part 75, adopt a consistent definition in Subpart KKKK, and defer to Part 75 definition in 

Subpart TTTT.

Commenter 9666 stated EPA must clarify whether additional provisions apply for invalid data in 

Part 75, such as when certain types of changes are made to the monitoring system or if QA test is 

not conducted on time.

Commenter 9661 supported use of data only from valid operating hours. Commenter 9661 stated 

that since the substitute data provisions are intentionally punitive in nature to provide an 

incentive for companies to maximize the availability of CEMS, use of substitute data would lead 

to intentionally overstated CO2 emissions, unnecessarily putting compliance demonstration at 

risk. Commenters 9426 and 10243 supported using data only from valid operating hours and not 

using substitute data provisions of part 75. Commenter 9426 supported the use of only operating 

hours for which you have valid data for all the parameters used to determine the hourly CO2

mass emissions and gross output data.

Commenter 9426 noted the rule is silent on the matter of how to handle substituted flow or CO2

data that are applicable to Part 75, and is also silent on how to handle flow or CO2 data that have 

had "full scale range exceedance" values applied to hourly averages, which are also applicable to 

data used for compliance with Part 75. Commenter 9426 recommended the rule should stipulate 

that neither substituted data (flow or CO2) to be used in the emissions calculation, nor any hourly 

data containing "full scale range exceedance" data, should be used in the emissions calculation. 

Commenter 9426 stated those hourly averages should be considered monitor downtime and so 

identified in the quarterly summary of emissions and monitoring system performance.

Response 11.10-1: The EPA has included in the final rule a definition of valid data and 

additionally has required that only valid data be used in determining compliance with an affected 

EGUs emission standard. The EPA is also adding more detail with respect to the monitoring 

provisions that will be used in accordance with part 75 procedures already in place. The EPA has 

additionally in the final rule expanded upon the requirements of the rule with respect to the 

requirement to not use substitute data that is allowed for in part 75 provisions as the EPA found 

that substitute data is not appropriate to use when determining compliance with a rate-based 

emission standard. 

Backup Monitors

Comment 11.10-2: Commenters 9425, 9666 stated EPA should allow, but not require, use of 

backup monitoring systems under Part 75.
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Commenter 3862 asked for an allowance to use backup monitoring equipment in case of a 

primary monitoring failure.

Response 11.10-2: The final rule does not prohibit the use of back up monitoring systems 

allowed for under part 75.

95 Percent Data Availability

Comment 11.10-3: Commenter 9514 supported the proposed 95 percent requirement.

Commenter 9666 noted that CO2 MS may not be able to meet the 95 percent data availability

requirement if the Part 75 data validation/invalidation provisions are used. Commenter 9666 

stated they did not object to invalidation of data under Part 75 because it does not treat missing 

data or missed QA test as a violation, and because it allows facilities to petition EPA for 

alternative data validation and substitution procedures.

Commenter 9425 stated EPA requires use of "all valid data" collected by the monitoring systems 

(including data recorded during startup, shutdown, and malfunction) to assess compliance, 

however, only those operating hours during which valid data are collected for all required 

parameters would be used. Commenter 9425 noted that having to distinguish between "valid" 

and "non out-of-control" data types will impose a significant burden, without gaining much 

additional data to report for GHG as compared to Part 75 reporting. Commenter 9425 stated they

would support the option to report "'non-out-of-control" data if we need to find "valid" data to 

maintain > 95% data capture.

Commenter 9666 stated a rule with 95 percent data availability requirement should have an 

alternative validation procedure. Commenter 9666 indicated EPA should either (1) make clear 

that data are invalidated under this rule unless a performance test is failed (i.e., the MS is out of 

control), or (2) include a procedure to validate data that does not otherwise meet Part 75. 

Commenter 9666 stated EPA must take into account in the ICR the development and 

maintenance of separate databases for the two rules.

Commenters 9425, 9666 stated EPA should allow a petition to validate data, similar to Part 75 

with respect to alternative data substitution procedures. 

Commenter 9425 indicated the rule should provide an alternative allowed number of missing 

data hours for units that meet 72.2 definition of peaking unit or other limited operation.

Response 11.10-3: The EPA is finalizing the requirement of the use of valid data in all 

calculations for compliance with an applicable emission standard and is retaining the 

requirement of 95% data availability. Additionally the EPA is not allowing in this final rule for 

the use of any substitute data as the EPA does not believe it is appropriate to use for complying 

with the rate-based emission standards put in place by the final rule.

Missing Data

Comment 11.10-4: Commenter 9666 supported reliance on part 75 monitoring procedures, 

without the missing data substitution.
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Commenter 8937 supported the use of data only from valid operating hours, avoiding the 

incorporation of Part 75 substitute data in the calculations.

Commenters 9425, 9666 agreed EPA should not use Part 75 missing data 

procedures/substitution. Commenters 9425, 9666 stated EPA should allow, but not require, use 

of backup monitoring systems.

Commenter 9471 opposed mandatory use of missing data procedures. Commenters 2590, 9471, 

and 9666 stated missing data procedures can overstate emissions, and EPA has not required 

missing data for EGU NSPS in the past. Commenter 9471 stated EPA has not provided 

justification for its use.

Commenter 10095 stated EPA should not allow substitute data, and should adopt the same 

approach as MATS.

Commenter 9425 should provide an alternative allowable number of missing data hours for units 

that meet section 72.2 definition of a peaking unit or otherwise has limited operation.

Commenters 9593 and 10100 urged EPA to allow use of Equation G-4 in Appendix G of Part 75 

during CO2 CEMS downtime.

Response 11.10-4: The final rule includes a definition of “valid data”, which defers to the data 

validation criteria in Part 75. Section §60.5540(a)(1) also defines a “valid operating hour” as one 

in which: (1) “valid data” are obtained for all parameters that are used to calculate the CO2 mass 

emission rate (tons/hr); and (2) the corresponding gross output value is available. Part 75 

substitute data values are not considered to be valid data. Also, for the purposes of Subpart 

TTTT, an operating hour in which there is a full-scale exceedance for a parameter that is used to 

calculate the CO2 mass emission rate (tons/hr) is not considered to be a valid operating hour.

The final rule retains the 95 percent data availability requirement and ties it to the definition of 

“valid operating hours”. For units that operate frequently, at least 95 percent of the operating 

hours in each compliance period must be “valid operating hours”.

The rule includes a provision allowing the use of backup monitors, in accordance with 

§§75.10(e) and 75.20(d). 

11.11 VIOLATION OF MONITORING REQUIREMENTS

Comment 11.11-1: Commenter 9666 objected to EPA's assertion that failure to collect and 

record required data is a violation of monitoring requirements, indicating that EPA includes 

exceptions for monitoring system malfunctions, repairs associated with monitoring system 

malfunctions, and required monitoring system QA/QC activities. Commenter 9666 stated that 

not all maintenance can be identified in a QA/QC plan, EPA has never included such a definition 

in an NSPS, and EPA has not provided a reason for doing so in this subpart. Commenter 9666 

stated that if EPA includes such a provision, then both periods of scheduled and unscheduled 

monitoring system maintenance must be excluded. Commenter 9666 further noted that if such 

maintenance is defined as a deviation, EGUs may be forced to wait until a monitoring system 

malfunctions or fails a QA/QC test before taking action.
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Response 11.11-1: The final rule does not include the statement to which the Commenter 

objects---that statement was only in the preamble, not in the proposed rule text. The final rule 

requires the continuous monitoring systems to be installed, certified, maintained, and operated 

according to Part 75. Section 75.5(e) allows for temporary interruptions of emissions monitoring 

for various reasons, including times when maintenance must be performed.

Comment 11.11-2: Commenters 9780 and 10095 supported not double counting operating days 

that were determined as violations under the previous compliance averaging period. Commenter 

10095 stated that EPA must clarify, for all sources, how civil penalties for violations will interact 

with the proposed applicability criteria and compliance period. Commenter 10095 further insists 

that EPA first clarify their intent and then allow the public to review and comment on EPA's 

implementation of the proposal.

Response 11.11-2: Section 113 of the Clean Air provides statutory criteria for the evaluation of 

a violation and the assessment of civil penalties. The EPA evaluates any instance of 

noncompliance on a case-by-case basis to determine the appropriate response and resolution.

Comment 11.11-3: Commenter 10100 supports the exceptions to continuous monitoring 

obligations during the periods identified in the Proposal but does not believe EPA should limit 

the repair exception to repairs associated with monitoring system malfunctions. Commenter 

10100 noted that requiring demonstration of a malfunction for each period excluded due to 

CEMS repairs would be burdensome and is not appropriate since CEMS may incur downtime for 

a variety of reasons that are not related or traceable to a specific malfunction. Commenter 10100 

further noted that there are no environmental or human health impacts associated with the failure 

of a CEMS, making any malfunction demonstration unnecessary. Commenter 10100 supports 

EPA's proposed exception for monitoring during QA/QC periods, but stated that EPA should 

also include other exceptions that are allowed under the Acid Rain Program, including periods of 

preventative maintenance and repair.

Response 11.11-3: The final rule requires the continuous monitoring systems to be installed, 

certified, maintained, and operated according to Part 75. Section 75.5(e) allows for temporary

interruptions of emissions monitoring for various reasons, including times when maintenance 

must be performed.

Comment 11.11-4: Commenter 9425 does not support EPA's approach to define deviations of 

the monitoring requirements, in particular EPA's failure to account for monitor downtime due to 

maintenance activities. Commented 9425 noted that not all maintenance can be reasonably 

identified in a QA/QC plan and further noted that EPA had not included any rule language 

associated with this proposal in proposed Subpart TTTT.

Response 11.11-4: The final rule requires the continuous monitoring systems to be installed, 

certified, maintained, and operated according to Part 75. Section 75.5(e) allows for temporary

interruptions of emissions monitoring for various reasons, including times when maintenance 

must be performed.
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11.12 CARBON CAPTURE AND THE CALCULATION OF LB/MMBTU 

EMISSION VALUES

Comment 11.12-1: Commenter 9666 noted that while Part 75 and Subpart Da allow use of an 

O2 CEMS in lieu of a CO2 CEMS, an O2 CEMS cannot obtain accurate CO2 measurement for 

EGUs that use carbon separation because the calculation relies on F-factors. Commenter 9666 

stated any equation that uses an F-factor will not provide accurate measurements downstream of 

any device that removes CO2 from the gas stream.

Commenter 9666 noted an F-factor represents the ratio of the gas volume of the products of 

combustion to the heat content of the fuel; the calculation for lb/MMBtu from CEMS data is 

dependent on the known relationship between the percent diluent gas produced from complete 

combustion of a fuel and the fuel’s heat content. Commenter 9666 further stated that when one 

of the assumptions is changed, for example fuel is not completely combusted or CO2 is removed 

by CCS prior to measurement, the methodology is no longer accurate. Commenter 9666 

indicated that EPA addressed these issues in ARP by allowing a diluent cap in place of O2 or 

CO2.

Commenter 9666 provided additional information in an attachment to its comment letter; with 

removal of CO2, the stoichiometric combustion assumption is invalid, the heat input is 

underestimated, and the lb/MMBtu rate is overestimated. Commenter 9666 indicated that 

removal of CO2 invalidates the use of diluent O2 monitors for CO2 concentration determinations, 

because this approach also uses F-factors and the stoichiometric combustion assumption is 

invalid. Commenter 9666 noted that pollutant concentrations are acceptable for determining lb/hr 

emissions if volumetric flow is measured because equations in Appendix F4 of Part 75 do not 

depend on F-factors.

Commenter 9666 stated if EPA promulgates an NSPS that can only be met by removing CO2

from the gas stream, EPA must recognize that the compliance procedures mandated in EPA and 

state CAA rules and permits will no longer be valid and overstate actual emissions in lb/MMBtu. 

Commenter 9666 further indicated that if either the diluent concentration will also have to be 

measured upstream of CO2 removal or the percent CO2 removed will also have to be measured 

and added back in, then EPA must account for the costs of that additional monitoring in the ICR.

Commenter 10039 noted that by requiring carbon capture from coal fired EGUs, the diluent 

ratios in the stack gases are changed and cannot be monitored in the manner required under ARP. 

Commenter 10039 noted that the rule does not account for this impact.

Commenter 10039 also noted that "monitoring for a minimum of two separate flue gas 

conditions" will be required. Commenter 10039 further stated that "One to include carbon 

capture systems functioning (i.e. reduced CO2 levels in flue gas) and the other would be with 

carbon capture systems off (i.e. normal CO2 levels in flue gas)."

Response 11.12-1: EPA agrees that when CO2 is removed from the flue gas, accurate CO2

concentrations cannot be determined using an O2 monitor and Equation F-14a or F-14b in 

Appendix F of Part 75. Therefore, the final rule allows the use of data from a certified O2
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monitor to calculate CO2 concentration only if the unit does not use carbon separation (e.g., 

carbon capture and storage).

11.13 PART 75 MONITORING METHODS

Comment 11.13-1: Commenter 9666 supported use of Part 75 monitoring procedures, and has 

noted their comments on EPA’s language, which in some cases is overly broad or duplicative.

Commenters 9666 and 10023 objected to elimination of some Part 75 monitoring options and the 

imposition of additional measurement requirements on new units. Commenter 9666 and 

10023 stated EPA has provided no justification for requiring EGUs to perform monitoring that is 

different from, or more stringent than, Part 75. Commenter 9666 and 10023 noted EPA has 

explicitly asserted in its ICR that monitoring is not different or more stringent.

Commenter 9666 did not object to the proposal to report the calculated CO2 emission rate on a 

quarterly basis.

Commenter 9666 did not object to the proposal to report the calculated CO2 emission rate on a 

quarterly basis.

Commenter 10100 requested annual reporting instead of quarterly reporting.

Commenter 7977 asked that EPA streamline all monitoring, recordkeeping, and reporting 

requirements to be consistent with other air quality programs, such as the ARP.

Commenter 10681 noted that, "instead of utilizing the preexisting monitoring, recordkeeping, 

reporting, and calculations, EPA has instead added to the complexity for a source and regulator 

to determine compliance with all requirements" of subparts Da, KKKK, and Part 75.

Response 11.13-1: The final rule defers to the monitoring, recordkeeping, and reporting 

requirements in Part 75.