11 - 1 

## Chapter **1 1**  **Monitoring and Compliance Contents**  11.1 Initial Compliance Demonstration ................................ ................................ ....................... 3 Initial Compliance Determination ................................ ................................ ........................... 3 Hy brid Approach ................................ ................................ ................................ .................... 5 Should Conduct Initial Performance Testing ................................ ................................ .......... 5 Should Not Conduct Initial Performance Testing ................................ ................................ ... 6 Best Approach for Initial Performance ................................ ................................ ................... 8 11.2 Proposed CO 2 Monitoring Methods ................................ ................................ ..................... 9 11.2.1 The CEMS Option ................................ ................................ ................................ ........ 9 Allow O 2 Monitoring ................................ ................................ ................................ ............ 11 Other Mo nitoring ................................ ................................ ................................ .................. 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 CO 2 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 Sy stem 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 In clude an Option for 12 - month Compliance ................................ ................................ ....... 28 Not Set a More Stringent Standard for Multi - Year Compliance ................................ .......... 28 In clude Stringent Measures for 84 - month Compliance Option ................................ ............ 29 NGCC ................................ ................................ ................................ ................................ ... 30 Hourly , Monthl y, Dail y ................................ ................................ ................................ ......... 3111 - 2

Daily Violations ................................ ................................ ................................ .................... 32 Format of th e Standard, Total Emissions over Total Electrical Output ................................ 33 In clude 0 for Emission Rates if Not Operating ................................ ................................ ..... 34 Compliance I ssues with 3 - Year Applicability Threshold ................................ ..................... 34 Compliance I ssues 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 ................................ ................................ .......................... 4111 - 3



### 11.1 **INITIAL COMPLIANCE D EMONSTRATION**  **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 earl y 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 compli ance 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 th e 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 sourc es 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 appl ying 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 monito ring 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 . Additional ly

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 sourc e will use to calculate the compliance averages when applicable . Additionally the EPA will only

determine compliance with respect to the appropriate reported 1211 - 4

**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 les s than 12 full operating months of data . Commenter 9666 stated EGUs should not be required to artificiall y s chedule 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 CO 2 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 alternativel y, 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 nonc ompliance 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 - ye ar applicability period is satisfied, and then comply going forward? Or, does compliance look back to the beginning of the 3 - ye ar period?" Commenter 10095 asked, "does the affected facility have a compliance obligation during the first three ye ars 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. C ompliance with the emission standards is based on a 12 - operating month average where the averaging period starts with the first operatin g 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.11 - 5

**Hybrid A pproach**  **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 u p 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 Condu ct Initial Performance T**  **esting Comment 11.1**  **- 5:**  Commenter 9514 stated an initial performance test is needed for all sources covered b y 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 earl y compliance determinations is especiall y great in light of the long averaging tim es 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 ye ars of consistent practice b y 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 rel ying 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 CO 2 capture system functions properly and that it will be able to sequester CO 2 on - site at a properly permitted facil ity 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 b y NSPS . Commenter 9514 noted that where sequestrations operations are not co - located or under common control, there may be unique11 - 6

challenges in conducting an initial performance test (where not already operating), however, an initial test of the EGU and its CO 2 capture equipment would provide valuable information . Commenter 9514 stated that years of excess CO 2 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 stac k 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, sectio ns 140, 150, and 230, for a possible compliance approach . Commenter 10681 indicated Washington State utilizes a quarterl y, 4 load emission test program to demonstrate compliance with GHG emissions standards. **Response 11.1 -**  **5:** The final rule retains the exemption from perfo rming 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, th e CO 2 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 necessaril y so . Compliance is to be assessed solel y on the basis of whether the average CO 2 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 N**  **ot 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 onl y the most efficient combustion turbines are installed . Commenter 9666 objec ted 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 s ys tem, as is consistent11 - 7

with Subpart Da compliance demonstration for S O 2 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 wil l 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 appl y 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 CO 2 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 compli ance . But this is not necessaril y so . Compliance is to be11 - 8

assessed solel y on the basis of whether the average CO 2 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 CO 2 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, ty

pically conducted within the first 180 days of first - fire . Commenter 8952 stated basing compliance evaluation at the maximum continuous rating point corrected to I SO 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 appl y to combined cycles using ASME PTC 46 . Commenter 8952 stated performance compliance testing would be limited to natural gas operation onl y. 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 . Comm enter 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 CO 2 emission can be reduced b y 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 CO 2 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 necessaril y so . Compliance is to be assessed solel y on the basis of whether the average CO 2 emi ssion 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, especiall y on the Western Slope and the proposed regulations will have impact on the11 - 9

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 ty pes 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 CO 2 emission profiles. Commenter 9661 stated EPA does not address compliance for units utilizing oil as a backup fuel, and stated this ty

pe of operation should be exempt, as units forced to burn oil for extended shutdowns of NG would emit at significantl y higher CO 2 emissions rates than allowed b y 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 ty

pe s 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 CO 2**  

### MONITORING METHODS **11.2.1 The 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 previ ously

acknowledged (cited RIA for MRR) . Commenter 10554 supported installation of CEMS as the only method to determine compliance with the CO 2 standard, noting it is a standard s ys tem 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 CO 2 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 CO 2 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 or11 - 10

down or low load, which effectivel y 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 belo w 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 CO 2 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 p olicies and inform the design and operation of future climate policies . Commenter 10869 stated mandating CEMS will create a more transparent and independent emissions - tracking s ys tem 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 p rogram, many power plants are already required to report S O 2 , NOx, and CO 2 and O 2 . 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 CO 2 emissions from plants with CCS and for non - CO 2 GHGs. Commenters 9425 and 9666 stated they do not oppos e 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 CO 2 mass emission rate. **Comment 11.2 -**  **2:** Commenter 9666 supported several monitoring options in the proposed rule but believed EPA has unreasonabl y eliminated several other Part 75 options. Commenter 9666 supported requiring new EGUs that combust solid fuel, and to allow other new EGUs, to monitor CO 2 mass emissions using a CO 2 concentration monitor, flow monitor, and (if applicable) a moisture monitoring sy stem 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 CO 2 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 F factor to determine CO 2 mass emissions. (Proposed Subpart TTTT, Subpart Da, Subpart KKKK). C ommenter 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 CO 2 CEMS . Commenter 9426 stated use of CEMS would not be feasible for stationary combustion tur

bines. Commenter 9661 stated EPA should not require stack flow monitors and CO 2 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 .11 - 11

Commenter 9425 opposed a requirement to use CO 2 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 onl y liquid and/or gaseous fuel may

opt to use Equation G - 4 in Appendix G of Part 75 to quantify the CO 2 mass emission rate. **Allow O 2**  **M onitoring**  **Comment 11.2 -**  **3:** Commenter 9425 stated that while most Part 75 coal - fired units use CO 2 CEMS, EPA should include use of O 2 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 O 2 CEMS in lieu of a CO 2 CEMS, an O 2 CEMS cannot obtain accurate CO 2 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 O 2 concentration monitor to determine CO 2 . Commenter 9425 advocat ed for an option to use an O 2 concentration monitor. Commenter 9666 did not understand why EPA has required use of a CO 2 CEMS and not allowed use of an O 2 CEMS to obtain CO 2 at an EGU that does not use carbon separation, as both existing NSPS Subparts Da and KKKK allow use of either a CO 2 concentration monitor or an O 2 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 O 2 concentration monitor to measure CO 2 concentration to obtain CO 2 mass emissions. Commenter 9666 stated there is no valid reason not to allow both ty pes of monitoring sy stems under this rule as well for EGUs without carbon capture. Commenter 9666 noted that gas - or oil - fired EGUs might p refer an O 2 monitor since O 2 analyzers generally cost less, are more stable, and are less affected b y interferences (e.g., H2O and CO) that can impact CO 2 measurements. Commenter 9666 stated EPA must issue a rulemaking for eliminating the O 2 monitoring option for public comment. Commenter 9666 stated that eliminating the option in the NSPS effectivel y eliminates it for NSPS units subject to Part 75. Commenter 9666 stated EPA could add an option for use of an O 2 monitor simply by adding a reference in Propos ed 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 O 2 monitor to calculate hourly CO 2 concentrations, provided that the affected EGU does not use carbon separation. **Other M onitoring**  **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 .11 - 12

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 CO 2 and flow rate monitors can easil y 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 CO 2 emission rates simply b y monitoring the CO 2 emiss ion rate. Commenter 7976 noted that normal heat variations diminish the value of long term CO 2 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 CO 2 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 rarel y uncover s ignificant CO 2 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 . 

### 11.2.2 **The 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 CO 2 emissions. Commenter 3862 stated fuel monitoring may be more accurate than av ailable 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 fuel measurements coupled with chemical anal ys is of fuels burned provide an alternative methodology . Commenter 9780 stated th at fuel measurements can provide GHG measurements with an average error of 1.6 percent, making this alternative potentiall y as accurate as the use of CEMS - based data. Commenter 9661 stated there is no rational basis for EPA to limit monitoring options to s tack flow monitors to the exclusion of fuel flow meters; fuel flow metering under 40 CFR 75 is widely utilized and provides high quality CO 2 emissions data, and there is no rational basis not to allow the use of proven technology to calculate CO 2 mass emis sions 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 gas and 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 perc ent carbon in the fuel) and fuel flow rate are sufficient metrics for reporting CO 2 emissions . Commenter 8952 stated fuel anal ys is (fuel composition and consumption) is a more accurate, cost - effective method and may be also report a higher output value than the CEMS, making it the more reasonable method for measuring CO 2 . 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 survey s, 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 CO 2 , and (2) fuel flow data is very precise, since plants are charged for fuel consumption. Commenter 9665 stated CEMS have inherent uncertaintie s, especially during transient operation (startup, shutdown, ramping) . Commenter 9665 stated CEMS require both CO 2 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 significantl y over 15 minutes, resulting in significant uncertainty . Commenter 8952 presented data for combined cycle CEM data th at 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 v alues 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 sigma11 - 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 CO 2 produced based on total fuel consumption and the reported CO 2 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 an d 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 m ore accurate, and the data reveal that emission levels [from fuel measurement] are nominally higher than reported b y the CEMS . Commenter 8952 stated that differences in the measured values provided are believed to result from inherent inaccuracies in the C EMS 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 CO 2 level measured by the emission measurement device. Commenter 8952 explained the delay is caused b y 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, CO 2 concentration is me asured and converted to a C O 2 mass flow based on exhaust flow measurements that may differ b y s everal minutes. Commenter 8952 noted this time lag is not significant during steady operation, but can be significant during transient events, especially start - u p 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 C O 2 for any gas turbine cycle due to its greater accuracy and eas e 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 perio d 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 stat ed 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 con cern with startup and shutdown which is why a 12 - operating month rolling average is being11 - 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 1 0095 supported the option of using any part 60 and 75 methods for monitoring and calculating C O 2 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 fo r liquid and gas - fired EGUs . [ 4562] Commenter 10095 stated EPA allow use of Appendix D and G for units that do not co mbust solid fuel or burn exclusively gaseous or liquid fuels. Commenter 9427 supported the alternative to use Appendix D to part 75, noting that they currentl y 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 S O 2 mass emissions by using Part 75 Appendix D fuel measurement, sampling, and anal ys is; the heat input value calculated under Appendix D can be used to calculate CO 2 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 s ys tems in lieu of Appendix D . Commenter 9666 noted that fuel flow meters are not subject to interferences that can bias measurement . Commenter 9666 stated r equiring 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 commonl y used fuels is not sufficient to warrant determination of a site - specific F factor 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 m onitoring, 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, c ompliance, 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 ty pes simultaneously , ECMPS requires use of Equation G - 4A to calculated total CO 2 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 CO 2**  

### MASS EMISSIONS **F ROM 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 infrequentl y . 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 calculati on, 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 REPOR TING OF GROSS GENERA**  **TION 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 hourl y 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 I SO conditions. Commenter 9666 stated that EPA propos al requires calculation and use of actual gross electrical output for each hour and useful thermal energy relative to I SO conditions . Commenter 9666 stated that if EPA includes partial unit operating hours, the values already reported under Part 75 will ne ed 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 onl y 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 anal ys is 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 ye ar 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 reall y 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 b y 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 CO 2 produced for the number of starts a unit could potentiall y 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 CO 2 to approximately zero; Commenter 9425 notes the accuracy of determining CO 2 mass emissions during these period needs to be evaluated against the small increase in CO 2 that would be reported. Commenter 10681 questioned the basis for including onl y 75 percent of the “useful thermal output” , on page 1450 of the proposed rule. Commenter 10095 supported the proposed strategy to onl y 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 combine d 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 CO 2 emission rate (kg/MWh) is not calculated on an hourl y basis . Rather, zero gross output is c onsidered 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 rate based compliance. **Response 11.4 -**  **3:** The EPA disagrees with the commenter and the final rule retains the rate based compliance approach. 

### 11.5 **QUALITY ASSURANCE AN D QUALITY CONTROL (Q** **A/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 S O 2 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 inappropriatel y 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 appl y 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 re quirement 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 CO 2 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, Appen dices 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 CO 2 CEMS data, contrary to EPA ’ s intent and assertions in its proposed I CR . Commenter 9666 noted that EPA previously provided an option to use Part 75 QA/QC in lieu of Part 60 requirements for C O 2 and O 2 monitors used to monitor S O 2 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 CO 2 and O 2 CEMS, and RATA specification of 2.5 percent for CO 2 CEMS and stack flow monitors), as neither criterion are consistently achievable. Because EGUs have reported initial and daily CO 2 and O 2 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 dail y calibration drift cap no greater than 0.3 percent CO 2 for CO 2 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 relativ e accuracy standard of 2.5 percent is not supported by current data, methods, or monitoring system equipment. Commenter 9666 further noted that EPA evaluated CO 2 and flow monitor RATA results reported under Part 75 (results showed 3.06 percent of 2736 CO 2 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 b y data showing the criteria are necessary and achievable if EP A 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 f or 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 9 425 stated EPA cannot promulgate new requirements without data and anal ys is . 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 d efers 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 **ADDITI ONAL MEASUREMENT REQ**  **UIREMENTS 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 did11 - 21

not provide any justification for additional requirements, and EPA must prop ose 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 likel y 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 finaliz ed . 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 emissi on 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 . C ommenter 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 sourc es 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 anal ys is . 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 con sistent 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 complic ates 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 o n CO 2 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 CO 2 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 section11 - 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 effectivel y eliminates them for NSPS units subject to Part 75. If CO 2 is measured on a dry basis, commenter 9593 stated the rule should require a continuous moisture monitoring sy stem 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 elimin ate the requirement to monitor stack moisture content using CEMS, noting that nearl y 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 P roposed 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 devic es 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 af fect 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 onl y 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 p recision.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 req uired 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 b y 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 clearl y 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 b y 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 S ys tem . The monitoring plan submittals for a non - ARP unit must be made by the DR, or, if applicable, by the AD R, 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 CO 2 mass emissions only , and EPA should limit the Monitoring Plan information to CO 2 emi ssions monitoring. **Response 11.7 -**  **2:** The final rule requires reporting of onl y those monitoring plan data elements in §75.53(g) and (h) that are needed to quantify the hourly CO 2 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, CO 2 - 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 CO 2 emissions reports and the compliance reports to be submitted electronicall y 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 CO 2 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 co mment 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 MONITOR ING SYSTEM CERTIFICA**  **TION Comment 11.8**  **- 1:**  Commenter 9666 s upported the 180 days allowed for CEMS certification . Commenter 9666 pointed out that while the preamble indicates all "monitoring s ys tems" for CO 2 may be certified in timeframe for 40 CFR 75.4(b), they could not find rule language that implements this; th e commenter noted that the two rules should have the same certification deadlines, and the regulatory text should refer specifically to "monitoring s ystems required to monitor CO 2 mas emissions" rather than to CEMs, to reflect that Appendix G monitoring systems rel y 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 day s for CO 2 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 sy stems 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 tim eline . Nearly all of the affected units under Subpart TTTT will also be in the Acid Rain Program . 

### 11.9 **ANNUAL OR MULTI -** **YEAR COMPLIANCE PERI ODS**  **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 pre commissioning testing. **Response 11.9 -**  **1:** The EPA disagrees with the commenter 9514 and c ompliance is to be assessed solely on the basis of whether the average CO 2 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 preamble11 - 26

**Support Multi -** **Year Compliance Comment 11.9**  **- 2:**  Commenter 10239 stated EPA must include a multi - ye ar 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 ye ar or longer basis for both coal - fired and NGCC units. Commenter 9666 stated that requiring more frequent compliance demonstrations would hinder operational f lexibility 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 earl y ye ars of the performance standard, where captured CO 2 is delivered offsite to sequestration not under owner control . Commenter 9471 stated compliance under a sliding scale over a 7 - ye ar 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 - ye ar compliance period, such as the proposed 84 - month compliance period for coal - fired EGUs, would be justified beca use 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 opti on minimizes rule effects on electricity prices to a certain extent, but unlikely to translate to significant cost benefits associated with former 30 - ye ar 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 b y a nearer set date but allow some time for new plants to operate without CCS. Commenter 9317 stated that the compliance peri od shoul d 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 th e 30 ye ar period originally proposed in April 2012.11 - 27

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 o f 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 s hort - 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 not ed 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 significantl y reduced." Commenter 10869 further stated, " G iven the fact that many U.S. coal plant operators have resisted installing pollution controls for sulfur dioxide (S O 2 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 seaso nal weather), and some facilities will prefer a calendar year average (less variability over ye ar, 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 stop s 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 prece dent 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, 1 0095, 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 w arrant rolling 12 - month compliance . Commenter 10095 stated that if EPA chooses a rolling 12 - month compliance, EPA must clearl y 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 ye ar 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., onl y 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 CO 2 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 f ound 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 compli ance 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 - ye ar 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 CO 2 stan dard 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 discus sion 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 fail s 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 gau ge 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 CO 2 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 CO 2 emission limit of the 84 - operating month optio n 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 anal ys is 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 CO 2 emissions for the source; and (3) Step 3 - Calculate the source ’ s minimum practicable 84 - month CO 2 emission rate . Commenter 9514 stated if the “minimum rate ” ex ceeds 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 ye ars 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 b een 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 ye ar) average basis because a single compliance period each11 - 31

ye ar 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 CO 2 emissions and would also support a multi - ye ar averaging period. Commenter 10466 asked that any standard for large natural gas combined cycle turbines be implemented on a 3 - ye ar average basis. Commenter 10466 noted that the 3 - ye ar average ensures that eff iciency 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 b y reviewing the quarterl y Part 75 electronic emissions reports . These reports inc lude hourly CO 2 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 emissi on 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 CO 2 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 hourl y 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 monthl y 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 b y summing all CO 2 emitted in the past 12 months and dividing b y 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 applicatio ns can be used . Commenter 9514 also noted the utility industry is already

required to monitor and electronically report hourly CO 2 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 dail y, rather than monthl y, calculation of rolling annual average, as is consistent with CAA penalty provisi ons for “ each day of violation ” , not merel y 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 CO 2 limit wi ll 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 onl y monthly data is submitted to EPA, and therefore this change would likel y impose li ttle 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 dail y 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 dail y emissions rates wil l 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 dail y violations, EPA should develop and propose a "not to exceed" dail y em ission limitation. Commenter 9317 did not agree with EPA's proposal on determining daily violations and stated, " There could onl y be one violation for each month where the rolling average exceeds the standard." Commenter 10048 asked that EPA consider ass essing 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 day s that contributed to the actual exceedance and only count those days .11 - 33

**Response 11.9 -**  **10:** Af

fected units must begin using ECMPS to submit quarterl y electronic emissions reports as soon as the monitoring s ys tems have been certified . These reports, which are also required for new units that are subject to the Acid Rain Program, include hourl y CO 2 m ass emission rates (tons/hr), hourl y 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 CO 2 emissi ons data introduces no new reporting burden. Note that affected sources are not required to calculate hourl y, dail y, or monthly CO 2 emission rates in units of the standard (kg/MWh) --- rather, a single CO 2 emission rate is calculated at the end of each compl iance period, as the ratio of the total CO 2 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 CO 2 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 frequentl y 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 det ermine 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. Comment er 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 th e 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 the11 - 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 lb s/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 - ye ar 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 - ye ar 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 - ye ar 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 - ye ar 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 - ye ar thresholds have been removed from the final rule. Additionall y, compliance for all EGUs subject to emission limits is over a 12 operating month rolling average. For more discussion on the 12 - operating mo nth compliance period please see section IV.C. of the preamble **Compliance Issues Related to Applicability Comment 11.9**  **- 14:**  Given the applicab ility 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 th at 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 ye ar average but fails to meet one of the criteria for a ye ar during the same three ye ar period, from which 12 - operating month rolling average compliance determinations are the affected facility

excluded , and to which 12 - operating month rolling average compliance11 - 35

determinations do the affected facility have co mpliance 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? I f 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 af fected 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 - ye ar averaging period to determine applicability of the rule to allow for usage during emergencies regardless of the ty pe 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 gen erator (> 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 - ye ar 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 M ONITORS, MISSING DAT**  **A PROCEDUR** **ES, 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 rel y on the same de finition 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.11 - 36

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 de finition 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 ty pes of changes are made to the monitoring sy stem 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 intentio nally punitive in nature to provide an incentive for companies to maximize the availability of CEMS, use of substitute data would lead to intentionally

overstated CO 2 emissions, unnecessarily putting compliance demonstration at risk . Commenters 9426 and 10 243 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 hourl y CO 2 mas s emissions and gross output data. Commenter 9426 noted the rule is silent on the matter of how to handle substituted flow or CO 2 data that are applicable to Part 75, and is also silent on how to handle flow or CO 2 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 CO 2 ) to be used in the emissions calculation, nor any hourl y 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 quarterl y 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 a ffected 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 i n 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 stat ed EPA should allow, but not require, use of backup monitoring s ys tems under Part 75.11 - 37

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 CO 2 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 b y the monitoring s ys tems (including data recorded during startup, shutdown, and malfunction) to assess compliance, however, onl y thos e 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 ty

pes 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 I CR the development and maintenance of separate databases for the two rules. Commenters 9425, 9666 stated EPA shoul d 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 p eaking 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 compl ying 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.11 - 38

Commenter 8937 supported the use of data onl y from valid operating hours, avoiding the incorporation of Part 75 substitute data in the calculations. Commenters 9425, 9666 agreed EPA s hould 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 s tated 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 sh ould 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 CO 2 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 CO 2 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 . A lso, 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 CO 2 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 pro vision allowing the use of backup monitors, in accordance with §§75.10(e) and 75.20(d) . 

### 11.11 **VIOLATION OF MONITOR ING 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 s ys tem malfunctions, repairs associated with monitoring s ys tem malfunctions, and required monitoring s ys tem QA/QC activities . Commenter 9666 stated that not all maintenance can be identif ied 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.11 - 39

**Response 11.11 -**  **1:** The final rule does not inc lude 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 sy stems 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 do es not believe EPA should limit the repair exception to repairs associated with monitoring s ys tem 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 o f 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. C ommented 9425 noted that not all maintenance can be reasonabl y 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.11 - 40



### 11.12 **CARBON CAPTURE AND T HE**  **CALCULATION OF LB/MM BTU**  **EMISSION VALUES Comment 11.12**  **- 1:**  Commenter 9666 noted that while Part 75 and Subpart Da allow use of an O 2 CEMS in lieu of a CO 2 CEMS, an O 2 CEMS cannot obtain accurate CO 2 measurement for EGUs that use carbon separation because the calculation reli es on F - factors . Commenter 9666 stated any equation that uses an F - factor will not provide accurate measurements downstream of any device that removes CO 2 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 96 66 further stated that when one of the assumptions is changed, for example fuel is not completely combusted or CO 2 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 O 2 or CO 2 . Commenter 9666 provided additional information in an attachment to its comment letter; with removal of CO 2 , the stoichiometric combustion assumption is invalid, the heat input is underestimated, and the lb/MMBtu rate is overestimated . Commenter 9666 indicated that removal of CO 2 invalidates the use of diluent O 2 monitors for CO 2 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 c an only be met by

removing CO 2 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 CO 2 removal or the percent CO 2 removed will also have to be measured and added back in, then EPA must account for the costs of that additional monitoring in the I CR. Commenter 10 039 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 100 39 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 s ys tems functioning (i.e. reduced CO 2 levels in flue gas) and the other would be with car bon capture s ys tems off (i.e. normal CO 2 levels in flue gas)." **Response 11.12 -**  **1:** EPA agrees that when CO 2 is removed from the flue gas, accurate CO 2 concentrations cannot be determined using an O 2 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 O 211 - 41

monitor to calculate CO 2 concentration only if the unit does not use carbon separation (e.g., carbon capture and storage). 

### 11.13 **PART 75 MONITORING M ETHODS**  **Comment 11.13 -**  **1:** Commenter 9666 supported use of Part 75 monitoring p rocedures, 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 CO 2 emission rate on a quarterl y basis. Commenter 9666 did not object to the proposal to report the calculated CO 2 emission rate on a quarterl y basis. Commenter 10100 requested annual reporting instead of quarterl y 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 .