These comments have been responded to in earlier variations in this Response-to-Comment document. The additional 2% CO2 emission reduction that was proposed has not been incorporated into the final requirements in the final standards of performance for modified steam generating units. Also, the TSD explaining the basis for the proposed standards was provided in the rulemaking at the time of proposal (at EPA-HQ-OAR-2013-0603-0005) and is provided in Chapter 2 of the "GHG Mitigation Measures" Technical Support Document for the CPP Final Rule. We further note that the EPA is only finalizing standards for EGUs that conduct modifications resulting in an increase in potential CO2 hourly emissions of more than 10 %. Based on historical trends, we expect few, if any, EGUs to trigger that threshold and become subject to the finals standards. Those that do will do so only after taking actions  -  likely capital intensive actions  -  that trigger the modification provisions. Sources undertaking such capital-intensive projects can take steps to avoid triggering modification, such as measures to avoid increasing their emissions of pollutants  -  or can take measures at the time of the capital-intensive modification project to ensure that the final standard can be achieved.
Commenter 0215 stated absent from this "analysis" is any discussion linking the 4 percent "best practices" estimate to any identifiable, technically feasible heat rate improvement measures. At most, EPA's discussion shows that a 4 percent reduction in overall heat rate can be calculated mathematically based on these data. Commenter said EPA made no attempt, however, to show whether the measures it identifies as "best practices" are technically capable of reducing heat input variation at individual units at all, let alone reducing variation to a sufficient degree to reach the target efficiency level. Moreover, the 10, 20, 30, 40, and 50 percent reductions in heat input variation that EPA calculates at each unit do not represent varying implementation levels of "best practices" measures; they were apparently selected without any technical basis. Thus, EPA's decision to "conservatively" select a level of reduction that is "in the middle of the range of options" it arbitrarily chose is itself arbitrary.
Commenter 0291 stated that although EPA claims their proposed NSPS can be met through a combination of best operating practices and equipment upgrades, EPA has not included the results of any such analysis in the docket nor provided such studies in connection with this rulemaking. There simply is no technical support; documentation on that provides a justification for EPA's proposed standards for modified units.
These comments have been responded to in earlier variations in this Response-to-Comment document. Also, the TSD explaining the basis for the proposed standards was provided in the rulemaking at the time of proposal (at EPA-HQ-OAR-2013-0603-0005) and is provided in Chapter 2 of the "GHG Mitigation Measures" Technical Support Document for the CPP Final Rule. We further note that the EPA is only finalizing standards for EGUs that conduct modifications resulting in an increase in potential CO2 hourly emissions of more than 10 %. Based on historical trends, we expect few, if any, EGUs to trigger that threshold and become subject to the finals standards. Those that do will do so only after taking actions  -  likely capital intensive actions  -  that trigger the modification provisions. Sources undertaking such capital-intensive projects can take steps to avoid triggering modification, such as measures to avoid increasing their emissions of pollutants  -  or can take measures at the time of the capital-intensive modification project to ensure that the final standard can be achieved.
Deterioration of heat rate over time
Commenter 0192 stated that EPA's proposal is arbitrary and capricious because it fails to explore how the declining performance of heat rate improvements over time will affect overall emissions from coal-fired EGUs. The commenter stated that neither maintenance best practices nor equipment upgrades provide long-term emissions reductions at a consistent level after they are implemented; instead, they are part of an ongoing process where maintenance must occur on a regular basis and certain equipment must be replaced or upgraded several times over the life of a plant. The commenter stated that for any given heat rate improvement, there is a decay process by which the emissions reductions gradually decline over time and, as a result, even if a modified source were to implement the heat rate improvements necessary to reduce CO2 emissions by two percent, it would not be able to maintain those emission reductions consistently over time. According to the commenter, a more likely scenario would be that different heat rate improvement projects are undertaken at different times and with different decay rates, meaning that facilities can maintain a moderately stable level of heat rate improvements, albeit at a lower rate than what EPA projects is possible under the best circumstances.
Commenter 0146 stated that requiring a two percent heat rate improvement over the best heat rate recorded since 2002 as the unit's own best demonstrated historical performance is unworkable and unrealistic. The commenter stated that the Agency's assumption that a unit can replicate its lowest heat rate since 2002 is incorrect, as year-to-year variation is largely due to factors beyond the unit's control, such as ambient temperature, operating duty, and auxiliary load requirements. See Cichanowicz Heat Rate Report. The commenter stated that the installation of environmental controls significantly degrade the net heat rates because of the associated parasitic power and many units have been retrofitted with these controls since 2002 in order to comply with obligations under the CAA. According to the commenter, the resulting increases in net heat rate often more than offset the potential decreases available through efficiency-improving measures; therefore, it would be arbitrary and capricious to use any year prior to retrofit of pollution control equipment as the baseline for heat rate improvements.
Commenter 0222 stated that an impacted unit cannot comply with the 2 percent reduction regardless of the requirements of the existing source 111(d) rule proposal because they are already operating at maximum efficiency and/or have undertaken previous efficiency improvements. The commenter stated that by establishing a baseline as sometime between the year 2002 and either the time of the modification of the source or the time when the source is subjected to a Section 111 (d) plan, EPA does not capture or accommodate any changes to sources due to other EPA rules; for instance, many coal- and lignite-fired EGUs were required to install new control technologies as a result of the MATS Rule, which increased the parasitic load of environmental controls at those respective EGUs and EPA does not account for those increased parasitic loads, and the effect that this would have on a CO2 emissions rate, in the Proposed Rule.
Several commenters (0146, 0257) stated that a unit's heat rate is substantially affected by its load duty and that subpart Da EGUs generally operate most efficiently at high capacity factors, with heat rate increasing dramatically at capacity factors below 50 percent. The commenters stated that at partial load, net plant heat rate (and CO2 emissions) can increase by 4 to 8 percent, depending on boiler design and coal rank and that EPA acknowledges as much in the subpart Da Reconstruction TSD. The commenters stated that because many Subpart Da units currently operate at lower capacity factors than they have in the past, it would be infeasible for modified units to match their best historical emissions performance - particularly if, as EPA proposes, those units are expected to further reduce their utilization pursuant to a section 111(d) plan for existing sources. According to the commenters, it is highly likely that individual units' operating conditions such as capacity factor, fuel source, cooling conditions, and auxiliary power demand from over 10 years ago cannot be replicated under present market and regulatory conditions. Commenter 0146-12863 stated that the EPA has failed to demonstrate that its proposed NSPS for modified subpart Da EGUs is achievable "under the range of relevant conditions which may affect the emissions to be regulated," including "under most adverse conditions which can reasonably be expected to recur."
Commenter 0214 stated that EPA has erred by failing to recognize that individual units change over time and impact a unit's ability to achieve any historical annual CO2 emission rate, much less its best historical emission rate. The commenter stated that EPA acknowledges this inherent variability but did not consider it in establishing the proposed standards. The commenter stated that these uncontrollable factors that impact a unit's CO2 emission rate, which EPA has acknowledged, demonstrate why consistently achieving a once-demonstrated annual performance level is unachievable. The commenter stated that by failing to account for these factors, EPA errs in assuming high variability in heat rates reflect opportunities for process improvement.
Commenter 0215 stated EPA's approach of requiring a 2 percentage point heat rate improvement over the best heat rate recorded since 2002 as the unit's "own best demonstrated historical performance" is unworkable and unrealistic. Commenter said EPA's assumption that a unit can feasibly replicate its lowest heat rate since 2002 is a fallacy, as variation in any individual unit's heat rate is largely due to factors beyond the unit's control, such as ambient temperature, operating duty, and auxiliary load requirements. The commenter referenced the Cichanowicz Modified Source Report for much of their information. For example, the installation of scrubbers, selective catalytic reduction ("SCR"), and baghouses significantly degrade the net heat rates of coal-fired EGUs because of the associated parasitic power. The retrofit of SCR increases auxiliary power by about 1.5 percent of gross output, while flue gas desulfurization ("FGD") retrofit may increase auxiliary power by 1-2 percent, depending on coal type. Since 2002, about 140,000 MW of SCR and 120,000 MW of FGD have been installed on EGUs. Commenter said in 2015 about 955 coal-fired power plants will be operating - about 520 of which are larger than 200 MW. Among the larger units, 192 have retrofitted one or more of these pollution control devices. Thus at least 37 percent of large coal-fired units would have significant increases in parasitic power that cause them to be less efficient on a net basis than their best operating year since 2002 for this reason alone. As detailed with case studies in the Reference Unit Critique, many utilities that took purposeful steps to improve their heat rates have already found those gains offset by parasitic power required by new environmental controls. The use of a historical best rate as the units "own best demonstrated . . . performance" lacks support and would be arbitrary and capricious to use any year prior to retrofit of pollution control equipment as the baseline for heat rate improvements. Commenter continued a unit's heat rate is substantially affected by its load duty. EGUs generally operate more efficiently at high capacity factors, with heat rate increasing dramatically at capacity factors below 50 percent. Operation at partial load can increase net plant heat rate (and CO2 emissions) by 4 to 8 percent, depending on boiler design and coal rank. See EPA 2014 Reconstruction Report. Commenter said the Cichanowicz report examined emissions data from the Subpart Da EGUs most likely to continue operating in future decades and concluded that for over half of the study population, the lowest CO2 emission rate occurred prior to 2008 in years in which those units operated at higher capacity factors. Commenter said EPA fails to account for the impact of load duty and other factors on EGUs' emission rates, and therefore EPA has failed to demonstrate that its proposed NSPS for modified Subpart Da EGUs is achievable. It is highly likely that unit operating conditions such as capacity factor, fuel source, cooling conditions, and auxiliary power demand from over 10 years ago cannot be replicated under present market and regulatory conditions.
The additional 2% CO2 emission reduction that was proposed has not been incorporated into the final requirements in the final standards of performance for modified steam generating units. Also, the TSD explaining the basis for the proposed standards was provided in the rulemaking at the time of proposal (at EPA-HQ-OAR-2013-0603-0005) and is provided in Chapter 2 of the "GHG Mitigation Measures" Technical Support Document for the CPP Final Rule. We further note that the EPA is only finalizing standards for EGUs that conduct modifications resulting in an increase in potential CO2 hourly emissions of more than 10 %. Based on historical trends, we expect few, if any, EGUs to trigger that threshold and become subject to the finals standards. Those that do will do so only after taking actions  -  likely capital intensive actions  -  that trigger the modification provisions. Sources undertaking such capital-intensive projects can take steps to avoid triggering modification, such as measures to avoid increasing their emissions of pollutants  -  or can take measures at the time of the capital-intensive modification project to ensure that the final standard can be achieved. Sources with declining heat rates must conduct on-going maintenance and best operating practices to ensure proper operation of the facility. Affected modified units also have the option of co-firing with natural gas to meet the final standard of performance. Regarding comments on equipment degradation, Section 2.6.8 of Chapter 2 of the `GHG Mitigation Measures' TSD discusses the impact of equipment degradation.
Issues Specific to Coal Refuse
Commenter 0182 stated that there is an issue with EPA's BSER analyses as it relates to alternative energy coal refuse CFB technology. The commenter stated that enhanced limestone injection along with increased fuel injection for coal refuse fired CFB Units will most likely be the optimal compliance methodology utilized to comply with MATS and CSAPR requirements and many of the coal refuse CFBs will be modifying their units to meet MATS and CSAPR. The commenter stated that the injected limestone is instantly calcined, which generates CO2 with the net result being an increase in CO2 emissions of potentially 1% to greater than 10%. The commenter stated that in one recent case where the limestone was increased by 10% and the fuel by 5%, there was an annual increase of over 100,000 tons of CO2. The commenter stated that in the case of modifying or reconstructing coal refuse CFB units, the failure to account for the additional CO2 associated with the usage of limestone makes it impossible to reduce CO2 to the required level. The commenter stated that enhanced limestone injection will impact these units by further increasing heat rates, increasing the parasitic load, and/or increasing the mass loading with the efficiency impacts ranging from 1% to greater than 6% increases in the measured heat rate; in the case of CFB Units, the required controls may cause the boilers to reach critical load material input limits (mass/weight) resulting in the units dropping load (less MW output) as the fuel, limestone, and ash mass in the boiler is approaching the limit on weight load, resulting in further negative impacts on heat rate.
Commenter 0182 stated that power plants exist as either regulated or non-regulated facilities, which in turn impacts their economics. According to the commenter, facilities in a deregulated market place are constantly working to lower the BTUs/kW heat rate to compete in the market place; thus, the never-ending quest for heat rate improvement, and improved maintenance programs over the past 10+ years (just to name two) does not leave much room to gain an additional 2 percent. The commenter stated that this is especially true for the coal refuse units whose boiler designs are based on plentiful sources of useable fuel (coal refuse) within close proximity of the plant and that coal refuse fuel quality varies widely as does each coal refuse CFB unit's heat rate.
In their comments regarding the effect of the proposed rule on coal refuse CFB, commenter 0182 stated that EPA is expecting improvements under the proposed rule by 2 percent, whereas, under the Clean Energy Plan, the expected improvements are upwards of 6 percent. The commenter stated that this looks like double counting.
Commenter 0182 stated that EPA should consider the multi-environmental benefits associated with coal refuse fired units and specifically the air pollution benefits of removing coal refuse from legacy coal refuse stock piles and using it as fuel in a controlled manner, rather than allowing these stock piles to uncontrollably burn.
Commenter 0182 stated that uncontrolled burning coal refuse legacy stock piles produce ground level emissions as well as CO2, methane, and other Greenhouse Gas emissions. The commenter recommended that EPA should consider giving CO2 credits for coal refuse CFBs that are eliminating these uncontrolled CO2-GHG emissions by encouraging the collection and conversion of legacy coal refuse into alternative energy.
Commenter 0182 suggested that EPA withdraw this proposed rule, as well as the NSPS Rule for CO2 emissions for new units and prior to publishing new proposed alternative rules, EPA should fully evaluate and understand varying combustion and integrated emission control technologies. The commenter stated that in developing this new proposed rule and the NSPS for new units, EPA may wish to evaluate CFB Control Technology and the required use of limestone. The commenter stated that unlike other combustion technologies that use add-on controls to control SO2 emissions CFB coal refuse units utilize limestone.
First, emissions increases attributable to the addition or use of any pollution reduction system or device (See 40 CFR 60.14(e)(5). So, limestone injection in a CFB unit (for the purpose of emission reduction of acidic gases) would not trigger the modification provisions. The additional 2% CO2 emission reduction that was proposed has not been incorporated into the final requirements in the final standards of performance for modified steam generating units. We further note that the EPA is only finalizing standards for EGUs that conduct modifications resulting in an increase in potential CO2 hourly emissions of more than 10 %. Based on historical trends, we expect few, if any, EGUs to trigger that threshold and become subject to the finals standards. Those that do will do so only after taking actions  -  likely capital intensive actions  -  that trigger the modification provisions. Sources undertaking such capital-intensive projects can take steps to avoid triggering modification, such as measures to avoid increasing their emissions of pollutants  -  or can take measures at the time of the capital-intensive modification project to ensure that the final standard can be achieved. Sources with declining heat rates must conduct on-going maintenance and best operating practices to ensure proper operation of the facility. Affected modified units also have the option of co-firing with natural gas to meet the final standard of performance.
<IP_ADDRESS> CO2 Reductions
Standards are more stringent than a 2% reduction in CO2/EPA failed to properly analyze available data
Commenter 0214 stated that the proposed standards are far more stringent than a two percent reduction in CO2 emission rate and included figures with their comments to illustrate the stringency of EPA's proposed standards considering a unit's annual emission rate variability. The figures present the units' highest and lowest annual net CO2 emission rates and a two percent reduction below the lowest emission rate with a red line represents EPA's proposed emission rate floor (1,900 lb CO2/MWh-net for large units (greater than 590 MW) and 2,100 lb CO2/MWh-net for small units (less than or equal to 590 MW)). The commenter stated that based on their analysis, EPA's proposed standards of performance would require a sustained 10 to 20 percent emission rate reduction from large units' historical highs and an eight to 21 percent emission rate reduction at small units and that the figures do not fully illustrate the stringency of EPA's proposed modified standards for boilers and IGCCs because: (1) EPA's proposed compliance criteria is based on a 12-operating month rolling average, not annual averages, (2) inter-annual emission rate variability is present, potentially requiring additional reductions beyond those illustrated, and (3) some units depicted will be required to add additional environmental controls which negatively impact net CO2 emission rate thus making compliance more challenging in the future. The commenter stated that EPA has not analyzed data to demonstrate that modified boilers and IGCC units can achieve the proposed standards on a 12-operating month rolling average for the units' remaining lives; EPA clearly has access to this data but has arbitrarily decided not to analyze it for this rulemaking.
 The EPA is not finalizing the proposed additional 2% CO2 emissions reduction.
If the standard assumes a baseline, variations in operation should be included.
Commenter 0156 stated that to the extent that the final performance standard assumes a reduction in CO2 emissions from a baseline, baseline should take into consideration variation in operation that can affect a unit's performance and CO2 emissions, such as load, fuel quality, and ambient as well as cooling water temperature; this variation can be addressed by establishing a baseline averaged over several years and the appropriate baseline should be at least the average of the highest three years during the period 2002 to the date of the modification.
The standard requires that the affected modified EGU meet its best historical performance between the years of 2002 and the time of the modification. A full 1-year average is sufficient to account for variation in operation, load changes, etc.
The commenter stated that the type of fuel combusted could impact the ability of a modified unit to maintain a CO2 emission rate 2% below a historic low level, even if reasonable efficiency measures are undertaken. The commenter stated that units combusting subbituminous coals have a higher CO2 emission rate than units burning 100% bituminous coal, yet many units have the flexibility and need to combust different fuel types depending on fuel availability and cost. The commenter stated that given that there is no cost effective method to control CO2 emissions from a coal-fueled boiler, this proposal would effectively foreclose any modifications that could increase the CO2 emission rate, including fuel changes that could be environmentally beneficial in other respects, like reducing emissions of sulfur dioxide or mercury. The commenter recommended that the rule should be revised to exclude fuel changes that result in reductions in the emission rate of other regulated air pollutants and should include an emission adjustment factor for pre-modification permitted fuel changes that occur following a NSPS modification.
The commenter stated that the CO2 emission rate proposed by EPA as the most stringent limitation that modified units could be required to meet is also unachievable for most units; the commenter operates two new supercritical units at its ERGS and there is no evidence that EPA considered emissions from the units in the context of this rulemaking.
The EPA is not finalizing the proposed additional 2% CO2 emissions reduction.
<IP_ADDRESS> Costs
Commenter 0215 stated EPA's estimated costs analysis for an illustrative modified coal-fired EGU to comply with the Proposed Standards lacks adequate detail and justification.
The commenter refers to the illustrative analysis presented in the RIA for the proposed rule. Because the EPA expects few units to trigger the NSPS modification provisions and has no data indicating a specific unit or type of unit might do so, the illustrative analysis was based on general information about a representative coal-fired unit. For the RIA supporting the final rule, the EPA considered the limited data available on past modifications and the diversity of existing units that could potentially modify and determined that it was not possible to conduct a representative illustrative analysis of what costs and benefits might result from this final rule in the unlikely case that a unit were to take an action that would be classified as a modification. However, the EPA anticipates that few EGUs will take actions that would be considered NSPS modifications and subject to the standards of performance finalized in this action during the period of analysis. For this reason, the standards will result in minimal emission reductions, costs, or quantified benefits in the period of analysis. Likewise, the Agency does not anticipate any impacts on the price of electricity or energy supplies
Lack of available projects at reasonable costs to provide benefit.
Commenter 0157 stated that EPA proposes a limit for coal plants based on operating at best historical CO2 emission rate plus an additional 2% emission reduction and, based on a hypothetical 500 MW coal-fired unit, estimates costs, net of fuel savings, of $0.78 million to $4.5 million (2011$). The commenter stated that EPA's assumptions are completely unrealistic and EPA offers no concrete example to ground its assumption. The commenter stated that they have retired many of its older, smaller coal-fired units in the last several years and the remaining units are the larger and newer units that have already undertaken cost-effective projects to maintain reliability/availability, and where possible, to improve efficiency. The commenter stated that there are no 2% efficiency improvement projects in the $0.78 million to $4.5 million range and any improvements achieved by routine maintenance are not sustainable and would start to degrade immediately after return to service. The commenter stated that the opportunity for lasting efficiency improvements are very limited, and potentially cost prohibitive.
Commenter 0157 stated that the presumed benefit from fuel savings has not been substantiated and EPA's assumption that heat rate improvements are economic at high cost EGUs because of fuel savings is incorrect. The commenter stated that if high cost EGUs could be converted to low cost EGUs by heat rate improvement projects, those projects would have already been done; the high cost units are also low capacity factor units by virtue of their high relative cost. The commenter stated that investing in a unit that runs little is not likely to result in it running more. The commenter stated that it must not just become more efficient; it must become so much more efficient that it displaces other EGUs, which were previously more cost effective. The commenter stated that such dramatic changes in the dispatch order do not result from modest heat rate improvements.
 Response 6.1-47: We note that the EPA is only finalizing standards for EGUs that conduct modifications resulting in an increase in potential CO2 hourly emissions of more than 10 %. Based on historical trends, we expect few, if any, EGUs to trigger that threshold and become subject to the finals standards. Those that do will do so only after taking actions  -  likely capital intensive actions  -  that trigger the modification provisions. Sources undertaking such capital-intensive projects can take steps to avoid triggering modification, such as measures to avoid increasing their emissions of pollutants  -  or can take measures at the time of the capital-intensive modification project to ensure that the final standard can be achieved. Sources with declining heat rates must conduct on-going maintenance and best operating practices to ensure proper operation of the facility. Affected modified units also have the option of co-firing with natural gas to meet the final standard of performance.
 The costs and benefits the commenter refers to are from an illustrative analysis presented in the RIA for the proposed rule. Because the EPA expects few units to trigger the NSPS modification provisions and has no data indicating a specific unit or type of unit might do so, the illustrative analysis was based on general information about a representative coal-fired unit. For the RIA supporting the final rule, the EPA considered the limited data available on past modifications and the diversity of existing units that could potentially modify and determined that it was not possible to conduct a representative illustrative analysis of what costs and benefits might result from this final rule in the unlikely case that a unit were to take an action that would be classified as a modification. However, the EPA anticipates that few EGUs will take actions that would be considered NSPS modifications and subject to the standards of performance finalized in this action during the period of analysis. For this reason, the standards will result in minimal emission reductions, costs, or quantified benefits in the period of analysis. Likewise, the Agency does not anticipate any impacts on the price of electricity or energy supplies.
EPA incorrectly used the Sargent & Lundy Study to Achieve Cost Estimates
Commenter 0242 stated that the S&L study on which the EPA based cost-effectiveness estimates, includes the following caveat: the costs should not be used as a basis for project budgeting or financing purposes. The commenter stated that the S&L study recommends the following: site-specific evaluations and cost analyses based on actual market conditions for any and all required equipment, material and labor at the time of the project should be performed. The commenter stated that costs presented in the S&L study were based on 2008 equipment purchases, when under this proposed rule many sources would be implementing these improvements after at an unknown specified point in the future. The commenter stated that they believe that this represents a further misuse of the S&L study and the data contained therein.
One commenter 0214 stated that the EPA does not provide a sufficient cost analysis to justify equipment upgrades as BSER for all potentially affected Da sources. The commenter stated that the EPA again uses the 2009 Sargent & Lundy report to justify equipment upgrades as being cost reasonable. The commenter stated that the EPA did not analyze site-specific characteristics (EGU designs, fuel types, age, size, ambient conditions, current physical condition, etc.) to determine the costs to all potentially affected subpart Da sources. The commenter stated that the 2009 Sargent & Lundy report estimated the costs of equipment upgrades for 200 MW, 500 MW, and 900 MW units, which do not encompass the range of units subject to EPA's proposed applicability criteria. The commenter stated that the EPA's use of one report to justify the cost of BSER, does not provide adequate support for its determination; EPA must provide adequate support to justify its BSER determination for all potentially affected subpart Da sources.
Commenter 0199 stated that EPA misinterpreted a Sargent & Lundy report and wrongly relied upon the report to estimate the cost impact on units when determining the BSER. The commenter stated that EPA relied on the report suggestions too strongly and drew too many assumptions; for example, EPA inappropriately concluded that all of the HRI measures could be used by each unit without degradation over time. The commenter stated that they defer to Sargent & Lundy's comments to the EPA clarifying its report.

As mentioned previously, critiques of the use of the Sargent & Lundy study have been addressed in the final Chapter 2 of the `GHG Mitigation Measures' TSD available in the rulemaking docket.
Cost-effective heat rate improvements already made
Commenter 0192 stated that EPA's implicit assumption that coal-fired power plant operators have failed to make cost-effective heat rate improvements defies economic reality. The commenter stated that power plant operators have strong incentives to make efficient and cost-effective heat rate improvement and the notion that coal-fired power plant operators throughout the United States have uniformly failed to make readily achievable improvements that would improve profitability is inherently implausible. The commenter stated that to the extent EPA is requiring that inefficient heat rate improvements should be made that are not economically justified only proves the agency has failed to take account of the cost of achieving emission reduction.
The EPA understands that some plant operators have made on-going investments in the plants to ensure efficient operations.  However, as provided in Chapter 2 of the "GHG Mitigation Measures" Technical Support Document for the CPP Final Rule (and available in the Carbon Pollution Standards (111b) rulemaking dockets: EPA-HQ-OAR-2013-0495 and EPA-HQ-OAR-2013-0603), analyses indicate that there is significant potential for heat rate improvement from the fleet of coal-fired EGUs, ranging from 4.0 to 6.6 percent nationally if coal-fired EGUs, on average, return to their best past performance between 2002 to 2012. Regarding comments about actions already taken, Section 2.6.1 of Chapter 2 of the `GHG Mitigation Measures' TSD discusses how EPA accounted for actions taken to improve and maintain heat rates. We also note that the EPA is only finalizing standards for EGUs that conduct modifications resulting in an increase in potential CO2 hourly emissions of more than 10%. Based on historical trends, we expect few, if any, EGUs to trigger that threshold and become subject to the finals standards. Those that do will do so only after taking actions  -  likely capital intensive actions  -  that trigger the modification provisions. Sources undertaking such capital-intensive projects can take steps to avoid triggering modification, such as measures to avoid increasing their emissions of pollutants  -  or can take measures at the time of the capital-intensive modification project to ensure that the final standard can be achieved. Sources with declining heat rates must conduct on-going maintenance and best operating practices to ensure proper operation of the facility. Affected modified units also have the option of co-firing with natural gas to meet the final standard of performance.
<IP_ADDRESS> Incentive for Technological Innovation
Commenter 0255 stated that the proposed standards for modified boilers may actually restrict efficiency improvement efforts. The commenter stated that EPA proposes that a boiler would be required to achieve a carbon dioxide intensity two percent better than the boiler's historic best carbon intensity, but not to be less than 1,900 lbs CO2/MWh-net. The commenter stated that if a plant has a cost effective opportunity to modify a boiler and achieve even a one percent improvement from current efficiency levels, the owner should be encouraged to make such a change. The commenter stated that relying on the historic best plant efficiency level ignores the fact that plant efficiencies are constantly degrading through normal wear on plant equipment and that owners continuously strive to restore efficiencies through the routine scheduled outages. According to the commenter, the proposed rule would create a perverse incentive for owners to allow plant efficiency to degrade until a group of modifications that can achieve the requisite two percent better than their best past efforts become cost effective - a goal for which EPA does not provide adequate technical justification. The commenter stated that requiring better than the best possible is not technically viable in this situation, has no place in regulatory programs without more thorough analysis and justification, and in the end may very well cause power plant efficiencies to degrade more than what would happen absent this rule.
Commenter 0271 stated that under the proposed section 111(b) rule for modified or reconstructed sources, units would already be subject to section111 (d) standards and the additional 2 percent reduction requirement will serve as a disincentive for facilities to make upgrades to existing units that would keep them operating at peak efficiency. The commenter stated that while the EPA's goal is to discourage units from operating beyond their useful life, the additional costs, resources, record keeping and reporting burdens introduced by this proposed rule will encourage units to operate inefficiently up to and possibly beyond their useful life.
Commenter 0242 stated that once units are designed, built and maintained to achieve the highest efficiency possible, little to nothing can be done. The commenter stated that EPA is penalizing responsible companies that operate as efficiently as possible, upgrade, and conduct maintenance as necessary to optimize the production of their units as these facilities will potentially be faced with requirements (between 2-6 percent) that are unachievable without large scale projects such as changing the type of boiler or equipment that extends beyond the EPA's original intent. The commenter stated that in a deregulated marketplace, these facilities are positioned at a distinct disadvantage due to the capital costs and inability to properly plan for these types of changes.
Commenter 0131 stated that they see little benefit to the proposed requirement to provide evidence of efficiency improvements prior to being subject to 111(d) and instead sees this as another EPA provision that incentivizes owners not to improve their generation performance and recommends that EPA should be attempting to provide real meaningful incentives for efficiency improvements.
We note that the EPA is only finalizing standards for EGUs that conduct modifications resulting in an increase in potential CO2 hourly emissions of more than 10 %. Based on historical trends, we expect few, if any, EGUs to trigger that threshold and become subject to the finals standards. Those that do will do so only after taking actions  -  likely capital intensive actions  -  that trigger the modification provisions. Sources undertaking such capital-intensive projects can take steps to avoid triggering modification, such as implementing simultaneous measures to avoid increasing their hourly emissions of pollutants  -  or can take measures at the time of the capital-intensive modification project to ensure that the final standard can be achieved. Sources with declining heat rates must conduct on-going maintenance and best operating practices to ensure proper operation of the facility. Affected modified units also have the option of co-firing with natural gas to meet the final standard of performance.
Determination of the Level of the Standard
2% HRI not achievable due to many factors
Commenter 0173 stated that EPA's proposed two-percent heat rate improvement is likely to be unachievable by most, if not all, modified EGUs and that in proposing this standard, EPA failed to consider many factors that will likely preclude the achievability of this standard, notable examples include that utility boilers tend to be more efficient when running at higher loads. EPA has proposed guidelines under section 111(d) which seek to increase natural gas and renewable generation and reduce electricity demand. Even if modified units were not subject to that rule, which is discussed more fully below, the decreased demand for generation from coal-fueled EGUs would have a negative impact on the ability of modified utility boilers to achieve a two-percent heat rate improvement. In addition, EPA has not taken into account efficiency improvements that historically have taken place at utility boilers. Power plants already have an economic incentive to operate as efficiently as possible, and many of the efficiency improvements envisioned by EPA are likely to have already been made by owners and operators and are unavailable options for further efficiency improvement. Furthermore, variability in heat rate at each specific EGU is based on site-specific factors that in some cases are beyond the control of the plant operator. As a result, EPA has incorrectly assumed that a unit can achieve its lowest heat rate since 2002, let alone a two-percent improvement from this lowest heat rate. Notable factors that are beyond the control of the unit operator include operation at lower capacity factors, ambient temperature, and temperature of the cooling water source. In addition, parasitic load requirements, such as from the operation of emissions control equipment, could have significantly increased since 2002, making improvement in efficiency to 2002 levels, much less lower, impossible. Commenter concluded that these factors, taken together, indicate that EPA's proposed standard for modified sources is unachievable.
Commenter 0182 stated that EPA's proposed standards of performance for modified and reconstructed fossil fuel-fired EGUs do not reflect the BSER nor has EPA demonstrated that these emissions can be achieved for the different types of affected fossil-fuel fired EGUs that may be modified or reconstructed in the future.
Commenter 0195 stated that EPA's proposed 2 percent heat rate improvement is likely to be unachievable by most if not all, existing modified EGUs.
Commenter 0161 stated EPA fails to take into consideration that startup/shutdown hours for coal-fired units are likely to increase dramatically due to redispatch requirements under building block 2 of the Existing Source Proposal. This impact of startup/shutdown periods on coal-fired units will likely be significant as a result of Section 111(d) requirements, and EPA should revise upward the emission standards for modified and reconstructed coal-fired units to account for this fact.
The EPA is not finalizing the proposed 2% additional reduction in CO2 emissions.
Commenter 0215 stated that the GHG Abatement Measures TSD contains a statistical evaluation of heat rates from the existing coal-fired fleet concluding that a minimum of 4 percent and up to 6 percent heat rate improvement is possible on a national average basis. EPA computed the heat rates from heat input values reported to EPA under the ARP using data from CEMS that are subject to Part 75 (specifically stack volumetric flow monitors and CO2 CEMS). Commenter believes the "analysis" in that TSD does not support EPA's claims. First, EPA's "model" assessing potential heat rate improvements via "best practices" is unfounded, arbitrary, and misleading. In this "model," EPA grouped hourly Part 75 heat input data into "bins" representing ranges of load and ambient temperature, then performed crude calculations to reduce the variation among observations in each bin by arbitrary increments of 10, 20, 30, 40, and 50 percent. See GHG Abatement Measures TSD at 2-30 to 2-31. The Agency used these adjusted values to calculate an adjusted heat rate for each unit, then compared the study population's average adjusted heat rate under each scenario to the population's actual average heat rate in order to determine the "improvement" under each scenario, with a roughly 30 percent reduction in each unit's variation corresponding to a 4.0 percent improvement in the overall study population's heat rate. Accordingly, EPA "conservatively" proposed to find that a 4 percent improvement in heat rate is achievable by applying "best practices" of EGU operation because that level "is in the middle of the range of options" EPA explored.
The heat rate improvement analysis in Chapter 2 of the `GHG Abatement Measures' TSD has been updated in response to public comments on the proposed methodology. As provided in Chapter 2 of the "GHG Mitigation Measures" Technical Support Document for the CPP Final Rule (and available in the Carbon Pollution Standards (111b) rulemaking dockets: EPA-HQ-OAR-2013-0495 and EPA-HQ-OAR-2013-0603), EPA used three different analytical approaches to calculate potential heat rate improvement based on EGUs' past performance. These analyses indicate that there is significant potential for heat rate improvement from the fleet of coal-fired EGUs, ranging from 4.0 to 6.6 percent nationally, on average, if coal-fired EGUs return to their best past performance between 2002 to 2012.
In setting standards, EPA incorrectly interpreted the 2009 Sargent & Lundy report in regards to improvements related to Building Block 1
Commenter 0173 stated that to set its proposed CO2 emission rate standard for modified EGUs, EPA appears to rely on an incorrect interpretation of a 2009 Sargent & Lundy engineering analysis of potential for heat rate improvements. The commenter stated that EPA makes the same incorrect interpretation in estimating the efficiency improvements available at existing coal-fueled EGUs as part of Building Block One in the proposed GHG emissions standards for existing sources; citing the Sargent & Lundy study, EPA concludes that a two-percent heat rate improvement over the best heat rate since 2002 can be achieved by reconstructed utility boilers. The commenter stated that the Sargent & Lundy analysis lists a series of actions that can be taken by plant owners or operators to improve their heat rate by a certain amount and at a certain cost. In order for EPA to conclude a two-percent improvement is possible, an analysis of the extent to which these heat rate improvements apply to the entire existing coal fleet would be needed and the Sargent & Lundy's study does not provide this type of analysis. The commenter stated that nowhere in the study do the authors attempt to conclude what types of improvements could be undertaken at specific units in the coal fleet, or that two percent would be representative of such an improvement. Rather, the Sargent & Lundy report presents only potential or hypothetical improvements that might be achievable based on a literature survey and vendor data, as opposed to actual operational experience. The commenter stated that another significant flaw with EPA's reliance on the Sargent & Lundy report is the fact that many of the potential heat rate improvements identified in the report are non-additive, temporal, and highly site specific. Commenter said based on these serious methodological shortcomings, EPA erred in concluding the Sargent & Lundy study supports a two-percent heat rate improvement for both modified sources and for existing sources as a part of Building Block One.
Commenter 0215 stated that their consultants evaluated a variety of heat rate improvement methods cited in the Sargent & Lundy 2009 study and concluded that EPA has exaggerated their short-term and long-term benefits. See the Cichanowicz Heat Rate Report. Commenter continued many of the payoffs are temporal; for example, steam turbine blades wear with time, revised and reconfigured heat exchangers accumulate deposits, and new condensers retrofit to provide clean and uncompromised surfaces for reliability may not deliver the same heat reduction due to material properties. As a result, the immediate impact of a heat rate improvement measure on a unit's CO2 emission rate may overstate the benefits of that heat rate improvement measure over its expected lifetime. For many heat rate improvement measures, a given estimate of heat rate improvement is merely a snapshot that changes with time. Moreover, while EPA assumes that heat rate-improving actions are additive, many are not. For example, heat from a boiler can be recovered only once, and projects that improve heat transfer within the boiler or refurbish the air heater are not cumulative. The Agency also fails to recognize that many of the actions suggested are routinely deployed as good maintenance practice, and their associated benefits are already accounted for in a unit's historical emissions performance, meaning that remaining opportunities for additional heat rate improvements are limited and highly site-specific. Some options such as refurbishing the condensers are in practice difficult to implement because they are typically located where access for construction is limited. In any event, condensers are not part of the affected facility and therefore cannot be regulated under this NSPS. See the commenter's attached Rasnic Memorandum.
Critiques of the use of the Sargent & Lundy have been addressed elsewhere in this RTC and in Chapter 2 of the `GHG Mitigation Measures' TSD. Further, the EPA is not finalizing the proposed additional 2% CO2 emission reduction.
Proposed standards of performance are not achievable and are therefore not lawful
Commenter 0187 stated that case law and section 111(b)(1)(B) require that performance standards be achievable and apply at the individual emission source, the boiler island, and based on the application of BSER. The commenter stated that in order to be lawful, a standard of performance must be capable of being applied by the source operator or owner to the individual emission unit and it must be achievable and the fact that the Agency's proposed standards are unachievable renders the proposal unlawful.
The final standards are achievable as they are based on a level of performance that has already been demonstrated / achieved by the affected EGU. The standard applies to emissions from the affected source and is based on the BSER, which has been determined to be the best potential performance of the affected unit.
Standards equivalent to reconstructed sources are not appropriate
Commenter 0260 stated that if EPA sets emission standards that are similar to the standards proposed for reconstructed utility boilers and IGCC units, it should be voluntary because it is inappropriate to require modified units to meet standards designed for reconstructed units.
The EPA has not finalized standards that are similar to those for reconstructed steam generating units. However, the EPA notes that there are other instances where the final standards of performance are the same for new, modified and reconstructed sources.
Commenter 0169 stated that an emission rate of 1900 lbs CO2/MWh-net is too low for a modified unit. The commenter stated that in the BSER Memo, EPA has shown that 2,100 lb CO2/MWh-net is the rate that can consistently be met by a "normalized" plant; certainly the CO2 emission rate for a modified unit should be something higher than the rate that a reconstructed plant can consistently meet.
Commenter 0222 stated that EPA's proposal that modified facilities would not have to meet an emission standard more stringent than the corresponding standard for reconstructed EGUs. The commenter stated that this assumes that the requirements imposed on modified EGUs, of all designs and fuel types, would be the same (or potentially more burdensome) than the limit proposed for units that have undergone reconstruction - a much more involved and expensive, and likely emissions reducing, process. The commenter stated that these limitations should not even be close to each other, let alone overlapping.
The final standard only requires a modified EGU to meet a standard consistent with that finalized for reconstructed sources if its best historical performance is below that level (i.e., would be more stringent that the reconstructed source standard) and thus the unit would have already demonstrated an ability to achieve the more stringent standard.
Modified/reconstructed source standards should not be same as standards for new sources
Commenter 0162 stated that new sources may have several inherent advantages over existing, yet-to-be-modified or reconstructed sources that would make less aggressive standards for modified and reconstructed sources reasonable. The commenter stated that new sources are constructed so that all component parts are integrated from the start whereas sources that undergo modifications or reconstructions, by contrast, must contend with the added expense and technical hurdles of adapting new technology to existing infrastructure. The commenter stated that the potential achievability, costs and energy impacts of the standards may differ dramatically for modified and reconstructed sources compared to new sources.
 The EPA has not finalized standards for modified or reconstructed sources that are the same as those for newly constructed sources.
Relationship with 111(d)
Commenter 0215 stated although EPA does not provide data and analysis to support its Proposed Standards for modified Subpart Da EGUs, the Agency does generally refer to theoretical information from its section 111(d) rulemaking. EPA does not explain how that analysis - prepared to support the Agency's assertions about the available average heat rate improvements over 2012 values for the existing fleet of coal-fired EGUs as a whole - supports its claim that individual modified Subpart Da EGUs can consistently replicate their "best demonstrated historical performance (in the years from 2002 to the time of the modification) with an additional 2 percent emission reduction." By contrast, the commenter's consultants analyzed historical emissions data from a subset of Subpart Da units likely to continue operating in future decades and found that the proposed NSPS would require the average unit to reduce emissions by 9 percent, with some units facing reductions as high as 25 percent.
Commenter 0251 stated that a third option should be included in Alternative #2, which would specifically exempt units from this standard that might be considered as modified only because of requirements to perform equipment upgrades to comply with a CAA 111(d) plan. The commenter stated that any equipment upgrades required by a CAA 111(d) plan must be subject only to the requirements of the CAA 111(d) plan and be exempted from this standard.
We note that the EPA is only finalizing standards for EGUs that conduct modifications resulting in an increase in potential CO2 hourly emissions of more than 10 %. Based on historical trends, we expect few, if any, EGUs to trigger that threshold and become subject to the finals standards. Those that do will do so only after taking actions  -  likely capital intensive actions  -  that trigger the modification provisions. Sources undertaking such capital-intensive projects can take steps to avoid triggering modification, such as implementing simultaneous measures to avoid increasing their hourly emissions of pollutants  -  or can take measures at the time of the capital-intensive modification project to ensure that the final standard can be achieved. Sources with declining heat rates must conduct on-going maintenance and best operating practices to ensure proper operation of the facility. Affected modified units also have the option of co-firing with natural gas to meet the final standard of performance.
Setting limits using EPA proposed ranges
Commenter 0253 responded to EPA's request for comment on where limits should be set within the proposed ranges. The commenter stated that they support limits set at the high end in each case because reconstructed and modified units are constrained by the existing unit's design and configuration, while newly built units are not so constrained; consequently, modified and reconstructed units cannot achieve as stringent a level of emission reductions. The commenter stated that EPA has consistently subjected existing sources to less stringent standards than new sources and applying standards at the high end of a reasonable range of emission limits for reconstructed and modified sources would provide the same leeway, recognizing that the technical and design constraints of existing sources limit options for reconstruction or modification. The commenter stated that as units get older, they do not run as efficiently as when they were new, which diminishes their ability to achieve as stringent emission levels as new units.
As we have noted, historically the EPA has be notified of very few EGU modifications and, based on that history, expects very few modifications in the future. The EPA is only finalizing standards for EGUs that conduct modifications resulting in an increase in potential CO2 hourly emissions of more than 10 %. Those that trigger modifications will do so only after taking actions  -  likely capital intensive actions  -  that trigger the modification provisions as just described. At the time of the modification, the sources undertaking such capital-intensive projects can take steps to avoid triggering modification, such as implementing simultaneous measures to avoid increasing their hourly emissions of pollutants  -  or can take measures at the time of the capital-intensive modification project to ensure that the final standard can be achieved. Affected modified units also have the option of co-firing with natural gas to meet the final standard of performance.
Commenter 0289 stated the proposed baseline emissions limits are too low, particularly for lignite units. EPA has essentially proposed a backstop emissions level that utility boilers and IGCC units cannot drop below. These emissions levels are far too low and would be extremely difficult to meet by even the newest supercritical coal-fired power plant burning the highest heat-rate fuel. For the vast majority of existing units, those that would be subject to modification requirements, would not be able to reach these targets even following a modification. It would take a completely different type of design and/or the reliance on a completely different fuel source. These problems are particularly acute for lignite-fired units. Given these limitations, EPA should set these backstop emissions levels at a much higher level. EPA should also create separate subcategories for regulated units.
The final standard only require a modified EGU to meet a standard consistent with that finalized for reconstructed sources if its best historical performance is below that level (i.e., would be more stringent that the reconstructed source standard) and thus the unit would have already demonstrated an ability to achieve the more stringent standard.
Standards are too lenient
Commenter 0282 disagreed that EPA can set any standard for modified and reconstructed sources other than the proposed 111(b) standard for new sources. The commenter stated that should EPA reject this position the proposed emission standards for modified or reconstructed coal-fired power plants are too lenient. The commenter stated that they agree that, for modified boilers and IGCCs, a best annual historical emission rate performance baseline is preferable to a best consecutive three- year average performance baseline. The commenter stated that a one-time reduction of 2 percent from the baseline performance is insufficiently stringent in light of the fact that EPA has identified that a 6 percent improvement, on average, can be achieved through a combination of best operating practices and equipment upgrades that improve heat rate performance and would be economically feasible based on the facilities' fuel savings alone. The commenter stated that because modified sources are new sources, EPA is required to ensure that its chosen standard for new sources reduces emissions to the "maximum practicable degree" in light of other statutory considerations, and that pollution is reduced through "maximum control of new major pollution sources." See Nat'l Asphalt Pavement Ass'n v. Train, 539 F.2d 775, 783 (D.C. Cir. 1976). The commenter stated that BSER was intended to be technology- forcing (see Sierra Club v. Costle, 657 F.2d at 325; see also id. at 346 n.174; ASARCO, 578 F.2d at 322 & n.6; Nat'l Asphalt Pavement Ass'n., 539 F.2d at 785-86; Portland Cement Ass'n v. Ruckelshaus, 486 F.2d 375 at 391) and while a standard must be achievable, it need not be already achieved by all or most existing sources. See Nat'l Lime Ass'n v. EPA, 627 F.2d 416, 431 n.46 (D.C. Cir. 1980). The commenter stated that "section 111 looks toward what may fairly be projected for the regulated future, rather than the state of the art at present, since it is addressed to standards for new plants." See Portland Cement Ass'n, 486 F.2d at 391. The commenter stated that once a system of emissions control is identified as adequately demonstrated, an achievable standard is merely one which is within the realm of the adequately demonstrated system's efficiency, regardless of whether it is routinely achieved in the industry prior to adoption. See Essex Chem. Corp., 486 F.2d at 433-34. The commenter stated that EPA need not base a standard for new sources on existing source test data at all, but may proceed based on reasonable extrapolations about what new facilities could achieve. See Portland Cement Ass'n, 486 F.2d at 401-02. Commenter said achievable standards may be imposed despite substantial costs so long as those costs are not excessive, exorbitant, or more than the industry could bear and survive. See Lignite Energy Council v. EPA, 198 F.3d at 933; Sierra Club v. Costle, 657 F.2d at 383; Portland Cement Ass'n v. Train, 513 F.2d 506 at 508.
Commenter 0282 stated that EPA also has failed to explain why it is proposing an automatic cap on a facility's performance level even though its achievable performance may well be below that cap. The commenter stated that because EPA's proposal to base a facility's emission reduction obligations on each facility's individual past performance is already keyed to and requires a detailed analysis of each facility's capability, there is no reason to impose a limit on this rulemaking's primary objective of reducing greenhouse gas emissions. The commenter stated that EPA might consider an emissions ceiling which no modified boiler/IGCC's emissions may exceed, but imposing a cap on achievable emission reductions is arbitrary, capricious and contrary to statutory intent. The commenter stated that based on information contained in the technical support document, EPA has concluded that the use of additional operating practices and equipment upgrades could allow a large EGU to meet an emissions standard of 1,700 lb CO2/MWh-net, and a small EGU to meet a standard of 1,900 lb CO2/MWh-net.
Commenter 0244 stated that modified units should be required to meet the standards proposed in EPA's new source standard under section 111(b): highly efficient boiler models equipped with partial CCS technology, which would reduce CO2 emissions by 30 to 50 percent relative to similar units without CCS systems. The commenter proposed that the actual best performance of an efficient coal-fired unit equipped with partial CCS is 1,200 lbs CO2/MWh and that modified steam EGUs be required to meet this standard as well. The commenter stated that since the advent of the NSPS program, EPA has frequently made identical BSER determinations, and established the same standards of performance, for new, modified, and reconstructed units within a regulated category and listed several examples. The commenter also listed examples of source categories where the performance standards were the same for new and modified units without referencing reconstructed units. Referring to their comments on the proposed new source rule, the commenter stated that CCS is an adequately demonstrated technology that can be easily integrated into EGUs and is well within the cost threshold contemplated by section 111(b). The commenter stated that the agency's analysis of CCS is equally applicable to a performance standard requiring partial CCS at modified steam EGUs and that CCS retrofits for existing steam EGUs, as well as sequestration options for the captured CO2, are adequately demonstrated, technically achievable, and economically reasonable. The commenter stated that EPA should consider partial CCS BSER for modified steam EGUs and should establish a performance standard no less stringent than 1,200 lbs CO2/MWh for these units, an emission limit that properly reflects the performance capabilities of this technology.
Commenter 0244 stated that BSER under section 111 must be "adequately demonstrated," but the D.C. Circuit has expressly held that this "does not mean that existing [sources] must be capable of meeting the standard; to the contrary, '(s)ection 111 looks toward what may fairly be projected for the regulated future, rather than the state of the art at present. . . .'" Nat'l Asphalt Pavement Ass'n v. Train, 539 F.2d 775, 785-86 (D.C. Cir. 1976) (quoting Portland Cement Ass'n v. Ruckelshaus, 486 F.2d 375, 391 (D.C. Cir. 1973)) (emphasis added). To establish BSER, "[t]he Administrator may make a projection based on existing technology, though that projection is subject to the restraints of reasonableness and cannot be based on 'crystal ball' inquiry." Id. at 391-92 (citing and quoting Int'l Harvester v. Ruckelshaus, 478 F.2d 615, 629 (D.C. Cir. 1973)). Moreover, EPA can "extrapolat[e] . . . a technology's performance in other industries", and look beyond domestic facilities to those used abroad. Lignite Energy Council v. EPA, 198 F.3d 930, 934 n.3 (D.C. Cir. 1999). The commenter stated that EPA need not show that each individual existing source can satisfy the BSER requirements; it simply needs to show that its selection is technologically feasible and is a reasonable projection of what may be available to the industry in the regulated future.
Commenter 0244 stated that as for cost considerations under section 111(b), the relevant inquiry is sector-wide rather than source-specific; that is, the cost element of a BSER determination serves simply to ensure that a performance standard does not impose costs that are "greater than the industry could bear and survive." Portland Cement Association v. Train, 513 F.2d 506, 508 (D.C. Cir. 1975) (emphasis added). See also Lignite Energy Council, 198 F.3d at 933 (EPA's choice [of BSER] will be sustained unless the environmental or economic costs of using the technology are exorbitant."). The commenter stated that, therefore, the economic impacts of the agency's BSER determination on any specific source are irrelevant; what matters is whether the regulated sector can bear the costs of compliance.
Commenter 0244 stated that sources that wish to make physical or operational changes can avoid triggering the standard by implementing engineering constraints that ensure that the units cannot increase their hourly emissions without an additional capital expenditure. Commenter added there is no valid reason why a source could not implement physical or operational changes while accepting a self-imposed constraint in its operating permit not to increase its emissions above prior levels, analogous to a synthetic minor limit in the PSD program. The commenter stated that, as Nat'l-Southwire Aluminum Co. makes clear, an operator always has the option of simply choosing not to modify the source, a decision that advances the goals of the Clean Air Act. See 838 F.2d at 841.
The EPA finds that the final standards are appropriate. As we indicated in the proposal and reiterate in the final preamble, the EPA has been notified of very few modifications for criteria pollutant emissions from the power sector to which NSPS requirements have applied. As such, we expect that there will be few NSPS modifications for GHG emissions as well. Even so, we also recognize (and we discuss in the preamble) that the power sector is undergoing significant change and realignment in response to a variety of influences and incentives in the industry. However, we have no way to predict which units may or may not implement projects that will result in an increase in hourly emissions of 10% or more and considering that the current fleet of fossil fuel-fired steam-generating EGUs varies considerably in terms of the age, location, size, technology, etc., it was most appropriate to finalize a standard that could be met by the affected modified EGU. The final standard, which is based on the best potential performance of the modified EGU, is achievable regardless of age, location, technology, or other unit-specific parameters.
Commenter 0215 stated that substantial portions of EPA's proposed NSPS for modified Subpart Da units are comprised of questions regarding fundamental issues that EPA should have assessed itself before proposing standards. EPA must terminate this proceeding and propose a new rule when it has developed an adequate basis for an NSPS.
The EPA has acknowledged that it does not have sufficient information about the types of modifications that will result in emissions increases of 10 % or less  -  nor about what types of units may conduct such modifications. We have no way to predict which units may or may not implement projects that will result in an increase in hourly emissions of 10% or more and considering that the current fleet of fossil fuel-fired steam-generating EGUs varies considerably in terms of the age, location, size, technology, etc., it was most appropriate to finalize a standard that could be met by the affected modified EGUs  -  those that implement modifications that are the result of more capital-intensive projects, resulting in larger emissions increases. The final standard, which is based on the best potential performance of the modified EGU, is achievable regardless of age, location, technology, or other unit-specific parameters.
6.2.1 Unit-specific Emission Limit
Unit-specific standards illegal
Several commenters (0144, 0150, 0152, 0183, 0195, 0199, 0201, 0214, 0215, 0249, 0268, 0282) stated that EPA does not have the authority under the CAA to regulate individual sources; rather the CAA authorizes the EPA to regulate categories or subcategories of sources.
Several commenters (0150, 0201, 0214) stated that the CAA authorizes EPA to establish uniform standards to regulate categories or subcategories of sources, not individual sources, under the NSPS provisions. Commenter 0150 stated that where Congress intended to authorize EPA to regulate individual sources, it has done so explicitly, such as in the Act's BACT and best available retrofit technology provisions, which authorize unit-specific, control technology-based emission limits. The commenter stated that section 111(b), on the other hand, contains no such unit-specific provisions; EPA cannot "rewrite clear provisions of the statute" to craft the rule it may prefer. UARG v. EPA, 134 S. Ct. 2427, 2446 (2014).
Commenter 0150 stated that the EPA's two proposals - a site-specific 12-operating month rolling average CO2 emission limit calculated as 2 percent lower than the best demonstrated annual historical operating performance for the affected facility using historical CO2 emissions data, and, as an alternative proposal, a unit-specific emission limit that would be determined based on the source's expected performance after implementation of identified unit-specific energy efficiency improvement opportunities - would require source-specific NSPS determinations not authorized by section 111(b).
Commenter 0144 also stated that the impractical nature of this approach invites protracted individual legal challenges to any effort to set such source specific standards. The commenter stated that the EPA's proposal provides no guidance on how such an approach would be structured, other than to state an audit would be based on a visual inspection, review of available engineering plans and operation and maintenance logs, and a comprehensive report detailing the ways to improve efficiency, the cost and benefits of improvements, and the time frames for recouping investments; absent specific criteria, what constitutes cost effective efficiency improvements is really left to a state regulator's whim. The commenter stated that where the NSPS promotes consistency, this approach will have the opposite result. The commenter stated that while the EPA's authority under the CAA to delegate its Section 111(b) authority to the States is questionable, it must, at a minimum, supply sufficient guidance to ensure that affected EGUs are regulated in a consistent manner.
Commenter 0282 stated that the alternative that would allow the state to set a facility-specific BSER standard based on an energy efficiency improvement audit deviates from the letter and spirit of the NSPS, which sets standards applicable to all new sources, and does so not based on the capabilities of individual facilities, but on the best system of emission reductions adequately demonstrated for the new sources in the category as a whole. The commenter stated that this standard would not only reject the statutory text of section 111(b), but also EPA's implementing regulations and a body of case law established over the last 30 years interpreting section 111(b); it would, moreover, contain no objective criteria against which the determination of the implementing authority could be measured, and would thus lack any enforcement mechanism.
Commenter 0195 stated that regarding whether modified utility boilers and IGCC units subject to a section 111(d) plan could be evaluated on a case-by-case basis to determine whether, as their section 111(b) standard, they should continue to be subject to the section 111(d) requirements to which they are already subject, nothing in section 111 authorizes EPA or a state permitting authority to establish unit-specific standards for modified EGUs.
Several commenters (0152, 0214, 0254) stated that section 111(b) authorizes EPA to list categories of stationary sources and to establish standards of performance for new [and by definition, modified] sources within such category. The commenters stated that EPA does not have the authority to issue standards for specific units and it can subcategorize, but not to the point of a separate standard for every unit in the country. The commenters stated that by requiring the standard to be based on a future energy audit, EPA has failed to set the standard, but rather established a procedure by which the standard will be set in the future on a unit-specific basis. The commenters stated that EPA's approach effectively delegates the setting of the standard to an auditor and a state implementing its 111(d) plan.
Several commenters (0152, 0214, 0254) stated that EPA's approach to setting unit-specific standards is not consistent with section 111(b) because it attempts to set unit-specific standards that would not be subject to public notice and comment.
Commenter 0183 stated that the EPA's proposal to establish a unit-specific evaluation at the time of modification as the BSER is flawed in that the case-by-case review proposed by EPA is simply not permitted by Section 111 (b). The commenter stated that a case-by-case standard is contemplated in the new source permitting process, where BACT is defined as a technology that the permitting authority determines on a case-by-case basis; there is no authority in the statute for EPA to subject an existing source to an undefined, "unit-specific" standard to be determined at the time of modification.
Several commenters (0243, 0268) stated that there is no record basis to support a two percent reduction from a source's best demonstrated historical performance level and that additional emission reduction at any source undergoing a modification depends on a number of facility-specific factors. The commenters stated that the EPA therefore should not attempt to finalize a modified/reconstructed source rule that makes a blanket determination about what any specific facility can achieve. The commenters stated that neither should the EPA finalize a rule that purports to authorize limit-setting through site-specific audits; under the plain terms of the statute, such emission limits must be set through notice-and-comment rulemaking proceedings.
Commenter 0215 stated that the Administrator shall publish proposed regulations, establishing Federal standards of performance for new sources within such category. The Administrator shall afford interested persons an opportunity for written comment on such proposed regulations. After considering such comments, he shall promulgate, within one year after such publication, such standards with such modifications as he deems appropriate. See CAA section 111(b)(1)(B). Congress has not authorized EPA to establish an energy efficiency audit process based on vague and amorphous standards so that at some future date a state authority - and not EPA itself - could undertake to establish a unit-specific emission limit that is not subject to advance notice and public comment.
Commenter 0215 said in order to rectify this propose that commenter believes to be illegal, the EPA could withdraw the Proposed Standards and determine that promulgating NSPS for modified sources is unnecessary. As EPA states, it "expects few units would trigger either the modification or the reconstruction provisions," 79 Fed. Reg. at 34,963, and any environmental benefits of this rule would therefore be negligible. As a result, the Agency's decision not to regulate would not only be easily justifiable, but would accord with its obligation under section 301(a) to regulate only when necessary. In this regard, the Supreme Court recently had to remind EPA that its decision in Massachusetts v. EPA "did not hold that EPA must always regulate [GHGs] as an 'air pollutant' everywhere that term appears in the statute, but only that EPA must 'ground its reasons for action or inaction in the statute.'" UARG v. EPA, 134 S. Ct. at 2440-41 (quoting Massachusetts v. EPA, 549 U.S. 497, 535 (2007)). Commenter said whatever EPA's difficulties may be in establishing NSPS for modified Subpart Da units, any procedural approach that includes "[t]he need to rewrite clear provisions of the statute should have alerted EPA that it had taken a wrong interpretive turn."
Commenter 0215 stated Section 111 is neither a section 169 process to establish BACT nor a section 407(d) proceeding to authorize an alternative emission limitation for NOx. Section 111(b) of the CAA does not authorize source-specific assessment and standard-setting for modified boilers. EPA's authority under section 111(b) is to propose and to establish uniform standards for source categories. Although EPA may subcategorize subsets of units that share common characteristics among the 955 or so coal-fired EGUs that UARG expects to be operating in 2015, to do so EPA must propose and justify emission limitations for each such subcategory. The Agency has historically subcategorized Subpart Da EGUs based on boiler size, coal rank, and similar characteristics. EPA's proposal to require an energy efficiency audit for each individual unit subject to NSPS is not a standard of performance for a source category or subcategory under section 111(b). Even EPA appears to recognize this, calling its proposed approach a procedure by which "a site-specific 12-operating month rolling average CO2 emission limit" will be "determined by the CAA section 111(d) implementing authority." Proposed 40 C.F.R. section 60.46Da(c)(3)(ii). This is not a CAA section 111(b) standard of performance.
 The standards that the EPA is finalizing are uniform. The methodology for determining the standard is the same across all affected units. However, as we indicated numerous times in the proposal and we reiterate in the final preamble, the EPA has been notified of very few modifications for criteria pollutant emissions from the power sector to which NSPS requirements have applied. As such, we expect that there will be few NSPS modifications for GHG emissions as well. Even so, we also recognize (and we discuss in the preamble) that the power sector is undergoing significant change and realignment in response to a variety of influences and incentives in the industry. However, we have no way to predict which units may or may not implement projects that will result in an increase in hourly emissions of 10% or more. Since we cannot predict which EGUs may implement such modifications, we must view all existing units as "potential modified EGUs". But, the current fleet of fossil fuel-fired steam-generating EGUs varies considerably in terms of the age, location, size, technology, etc. and, if the EPA were to try to finalize a numerical standard that was achievable by all "potential modified EGUs", then either the final standard would be so lenient that it would essentially be meaningless or the EPA would be faced with having to create multiple subcategories of units that may or may not ever modify. Ultimately, the best approach is to finalize a uniform methodology that allows sources that trigger the final threshold for modifications (i.e., those that result in an increase in potential hourly CO2 emissions of greater than 10%) to have a standard of performance that is achievable by the affected source.
Standards at each unit should be feasible based on a proven, operational, technological and economic standpoint
Commenter 0242 stated that consideration should be given to the significant operating differences between super-critical and sub-critical units and that performance standards under Section 111 should be based on the specifics of what is feasible at a specific unit. The commenter stated that the EPA's proposal in this regard is a step in the right direction and has some merit, but falls short of what is appropriate for Section 111 standards for CO2 from EGUs; that is, standards should be based on what is possible at each individual unit based on what is feasible from a proven, operational, technological and economic standpoint.
Commenter 0242 stated that a blanket standard for all modified utility boilers and IGCC units is inappropriate, and that BSER should be based on a unit-by-unit engineering study to determine what is actually achievable by each particular unit. The commenter stated that this study should take into consideration the source type, historical performance, recent maintenance, planned repairs, feasibility of upgrades, cost, site specific layout, etc.
Commenter 0242 stated that due to the wide variation of the overall efficiency of the many types of fossil fired EGUs, they do not believe that a specific value or percentage improvement is defendable. The commenter stated that a site-specific engineering study that measures possible avenues for efficiency improvements in a cost-effective manner is the only true mechanism to achieve actual reductions from units that may trip the modification definition. The commenter stated that they do not believe that a default 2 percent improvement should be applied as part of the standard, but rather based on a unit-specific study of what is feasible for that specific unit. The commenter stated that elsewhere in their comments, they comment on the flaws in the proposed 2 percent efficiency improvement, which is based on a flawed statistical analysis and the inappropriate use of the S&L study.
Commenter 0197 stated that they agree with the proposed approach of establishing a unit-specific performance standard based on the best historic performance of the modified or reconstructed unit. The commenter stated that they disagree with arbitrarily establishing any increment of additional stringency without conducting an analysis, which should use the emission rate, averaging the best three consecutive years, as the floor for the numerical emission standard. The commenter stated that this analysis should be performed by the owner or operator of the affected unit and approved by the state or local air pollution control agency following a process approved by the EPA. The commenter stated that this approach is also appropriate for existing units under Section 111 (d) that do not meet the definition of modified or reconstructed under this proposed rule.
Several commenters (0224, 0253)  stated that the second co-proposed option should be used regardless of whether the modification occurred prior to or after a section 111(d) plan because it would allow consideration of plant- and site-specific factors that affect efficiency; this option is also consistent with current practice that each unit is evaluated on its own merits. The commenters stated that as few modifications are anticipated, adopting this standard will not impose exorbitantly expensive or otherwise unduly burdensome costs on states or EPA. The commenters stated that given the size and scope of EGU modifications, an assessment can be done in a sufficiently detailed manner to serve the interests of pollution control and because EGUs routinely incorporate the most efficient generation technology, any modified EGUs will likely achieve a level of efficiency that is not currently achieved at existing EGUs.
The EPA proposed, as one of the alternative options, that standards should be determined following the performance of a unit-by-unit evaluation to determine the potential for efficiency improvements at the facility. However, commenters noted that there are no uniform procedures or guidelines for such evaluations and results can potentially vary from evaluation to evaluation. The EPA agreed and we are not finalizing unit-by-unit evaluations as part of the methodology for determining the unit's best potential performance. Rather, the EPA is finalizing that the affected modified unit will be required to meet a standard of performance consistent with its best historical performance (in lb CO2/MWh-g) during the years from 2002 to 2012. The standards that the EPA is finalizing are uniform. The methodology for determining the standard is the same across all affected units.
Commenter believes EPA has the ability to establish work practice standards, since there is not available information for an emission limit.
Commenter 0215 presented an alternative if the Agency does not have sufficient information to set emission limitations for every category or subcategory of boilers. Congress provided EPA with authority to promulgate work practice standards when it is "not feasible to prescribe or enforce a standard of performance." In such cases the Agency can "instead promulgate a design, equipment, work practice, or operational standard, or combination thereof . . . ." See CAA section 111(h)(1). Commenter said that although what EPA has proposed here cannot be construed to be a design, equipment, work practice, or operational standard, the Agency could withdraw the Proposed Standards and propose such an approach. Under a section 111(h) approach, rather than prescribing a numerical emission limit, EPA could promulgate design, equipment, work practice, or operational standards for the category or for subcategories of EGUs that are based on the implementation of specific measures reflecting the "best technological system of continuous emission reduction" that has been adequately demonstrated for the category or subcategory, considering cost and other factors. Although EPA would still be unable to promulgate unique standards for individual modified EGUs, the Agency could prescribe measures to improve efficiency (and therefore reduce emissions) that are cost-effective and available to all EGUs within the category or subcategory. Reliance on section 111(h) would be reasonable here because it is plainly "not feasible to prescribe or enforce a standard of performance." Commenter added it is "not practicable" to apply any measurement methodology to define or enforce standards of performance for CO2 emissions from EGUs. There is wide variation within the source category as to existing units' current efficiency and as to the cost-effectiveness of various efficiency-improving measures. EGU CO2 emissions depend on numerous factors beyond the unit's control, such as load duty and auxiliary loads. See J. Edward Cichanowicz & Michael C. Hein, "Evaluation of Heat Rate Improving Techniques for Coal-Fired Utility Boilers as a Response to Section 111(d) Mandates," at Section 2 (Oct. 13, 2014).
 The EPA agrees that it has the authority to set work practice standards when it is not feasible to prescribe or enforce a standard of performance. However, the EPA is able to prescribe and enforce final standards  -  as we have done in this final action. The final standards used a uniform methodology to determine an enforceable numerical standard for all affected units.
Compliance options
Several commenter (0178, 0260) stated that if EPA adopts the second proposed alternative, sources that modify after becoming subject to a Section 111(d) plan should have the option of meeting either (1) a unit-specific emission limit determined by the affected source's best demonstrated historical performance, or (2) a unit-specific emission limit based on the source's expected performance after implementation of identified unit-specific energy efficiency improvement opportunities; this would provide sources with flexibility to comply with the performance standards, while reducing CO2 emissions.
 The EPA is finalizing the sources that modify (with such modification resulting in an increase in potential hourly CO2 emissions of > 10%) must meet a unit-specific emission limit determined by the affected source's best demonstrated historical performance, and that the timing of the modification (i.e., whether it occurs before or after becoming subject to a Section 111(d) plan) does not matter.
Exemption from 2% additional emission reduction
Commenter 0162 stated that the proposed additional 2 percent emission reduction for individual units has no basis and is not supported by EPA's finding that coal-fired power plants can, on a fleet-wide basis, achieve a 6 percent heat rate improvement, which is also questionable. The commenter stated that restrictions such as tripping NSR have placed limitations on the extent of projects that could foster additional operating efficiency. The commenter stated that as equipment ages, efficiencies are harder to gain and believes that if an emission unit has done all it can within a reasonable cost consideration and within the realm of reason and that no additional CO2 emission reductions are possible to be achieved, the EPA should allow special circumstances in which the 2 percent additional emission reduction would not apply.
The EPA is not finalizing the proposed additional 2% emission reduction.
Commenter 0215 stated EPA lacks authority to establish a unit-specific emission standard that is based on the results of an energy efficiency audit. Any standard must be established through the notice-and-comment rulemaking process. Further, under the NSPS program, EPA may regulate only categories or subcategories of sources, not individual sources. Commenter added, because the Proposed Standards do not describe what an "energy efficiency audit" might entail, the process will be uncertain, costly, time-consuming, and result in virtually certain litigation.
Commenter 0215 continued that this proposed limit would likely dissuade any owner or operator of an EGU from voluntarily undertaking optional energy efficiency audits as suggested for Subpart KKKK units, 79 Fed. Reg. at 34,975, or Subpart Da units under certain circumstances, id. at 34,988. In the absence of a technical support document ("TSD") for modified units that might have explained in detail what an "energy efficiency audit" would entail, an owner or operator knows only that this approach must include, "at a minimum," a visual inspection of the facility to identify steam leaks or other sources of reduced efficiency; a review of available engineering plans and facility operation and maintenance procedures and logs; and a comprehensive report detailing the ways to improve efficiency, the benefits of specific improvements, the costs of those actions, and the time frame for recouping costs. The inclusion of the phrase "at a minimum" leaves this rule so open-ended that it cannot pass muster as a valid rule for this reason alone. Section 551 of the APA defines a rule as a statement of "future effect designed to implement, interpret, or prescribe law or policy." See U.S.C. section 551(4). An agency statement that fails to put regulated parties on notice of future legal obligations is not a "rule" under the APA, fails to meet basic due process standards, and is therefore neither valid nor enforceable. See Gen. Elec. Co. v. EPA, 53 F.3d 1324, 1328 (D.C. Cir. 1995) (citing Mullane v. Cent. Hanover Bank & Trust Co., 339 U.S. 306, 314 (1950)) ("Due process requires that parties receive fair notice before being deprived of property," including by requiring actions that entail the expenditure of significant amounts of money.). Commenter continued a rule that provides only "minimum" criteria, with others to be defined by the Agency without any guidance on an ad hoc, case-by-case basis, will not encourage owners or operators of EGUs to engage in this process to learn what other requirements EPA or others might impose. The preamble to the Proposed Standards sheds little additional light on what the requirements might be in practice but explains that EPA believes that "detailed engineering studies" could provide a wide range of opportunities to improve heat rate including improvements to the: (1) materials handling equipment at the plant, (2) economizer, (3) boiler control systems, (4) soot blowers, (5) air heaters, (6) steam turbine, (7) feed water heaters, (8) condenser, (9) boiler feed pumps, (10) induced draft (ID) fans, (11) emission controls, and (12) water treatment systems. See 79 Fed. Reg. at 34,986. Because this is the extent of the Agency's guidance, UARG suspects that the regulatory authority and the owner or operator of the EGU could be forced to engage in protracted negotiations concerning the scope of the assessment and how "detailed" any engineering studies must be. EPA provides no criteria by which projects would be required to be implemented, under what time frame, or what reasonable capital costs or costs in dollar per ton of CO2 avoided might be. Third parties such as the Sierra Club or activist states might seek to participate in such negotiations or file suits to challenge EPA's determinations. If such an issue were to arise in the context of enforcement litigation, the plaintiffs would surely urge the implementation of innumerable efficiency projects, whether or not efficacious or cost-effective. Although EPA requests comment on what the determining factors for requiring efficiency improvements should be, Id. at 34,988, this process seems calculated to require enormous time and expense with little or nothing in the way of environmental benefit. For all of these reasons, the Proposed Standards' requirement for energy efficiency audits is inconsistent with the CAA, the APA, and fundamental principles of due process.
The EPA is not finalizing the proposed requirement to establish a unit-specific emission standard that is based on the results of an energy efficiency audit.
EPA must set a numeric emission rate
Commenter 0192 stated that EPA's proposal to establish individualized standards of performance based on each facility's historic CO2 emissions is arbitrary and capricious and inconsistent with Section 111(b). The commenter stated that recently constructed coal-fired EGUs have incorporated heat rate improvements at the design phase, and many other facilities have implemented heat rate improvements as a means of improving their competitiveness; EPA would effectively be punishing them by requiring even more emission reduction at the modification stage. The commenter stated that a standard of performance based on heat rate improvements must include a numeric limit on the emissions reductions that it would demand of a modified facility. The commenter stated that under section 111(a)(1), the standard of performance established by EPA must reflect the degree of emission reduction achievable through the application of the best system of emission reduction. The commenter stated that given EPA's determination that a suite of heat rate improvements constitutes BSER, the two percent heat rate improvement EPA proposes as a standard of performance can only reflect BSER if a source has not implemented any heat rate improvements; it would be arbitrary and capricious to require a facility to achieve an additional two percent improvement in heat rate if it has already implemented all of the heat rate improvements that EPA has designated as BSER. The commenter stated that rather than speculating as to the percent improvement in heat rate that a modified facility might achieve, EPA should estimate the numeric emissions rate for a facility that implemented the full suite of heat rate improvements and use that as the applicable standard of performance.
Commenter 0214 stated that EPA must make a reasonable BSER determination and apply that BSER in such a way as to establish an achievable source category- or subcategory-wide standard of performance. The commenter stated that no industry-wide efficiency standard is possible due to the variability from unit to unit and each unit from year to year and, to the extent EPA insists on establishing a source category-wide standard, it cannot be defined by an individual unit's past performance. The commenter stated that EPA's standard must reflect a format similar to the standard it has proposed for newly constructed units---lb CO2/MWh---or some other form that can be applied across the industry. The commenter stated that to ensure that the standard is achievable by a reasonable number of modified and reconstructed units, the industry-wide standard required by section 111(b) would have to be sufficiently high to address the natural variability from unit to unit and at a single unit from year to year; therefore, based on this variability, source category-wide standards would need to be substantially higher than the currently proposed standards.
The EPA is finalizing a numerical standard. Sources that modify (with such modification resulting in an increase in potential hourly CO2 emissions of > 10%) must meet a unit-specific numerical emission limit determined by the affected source's best demonstrated historical performance (in lb CO2/MWh-g).
EPA proposed practicable emissions standard
Commenter 0166 stated that EPA established emission limits recognizing that unit-specific characteristics require unit-specific emission limitations; therefore, EPA's proposed requirement of a 2 percent reduction at each individual EGU through application of best operating practices and equipment upgrades is practicable. The commenter stated that, in contrast, EPA's January 8, 2014, 111(b) rulemaking establishes emissions limits that are simply not practically achievable for new coal-fired EGUs; likewise, in its rulemaking for existing sources under 111(d), EPA used a 6 percent heat rate improvement under the first building block that is not technically or economically achievable.
The EPA agrees with the comment that emission limits recognizing that unit-specific characteristics require unit-specific emission limitations. However, the EPA is not finalizing the proposed additional 2% emission reduction.
Commenter 0197 stated the proposed NSPS regulation for new sources, and consequently the modified and reconstructed NSPS and proposed Clean Power Plan, specifies that fossil fuel-fired units are affected facilities, and the definition of fossil fuel includes petroleum and natural gas. The proposed rule did not include specific standards for petroleum and natural gas-fired units. Commenter concluded that separate emission limits should be established for each type of EGU dependent upon the technology used, type of fuel fired, and the unit's role in providing electricity to the grid (i.e., the unit is base-load, load-following, or peaking).
The EPA is finalizing a numerical standard. Sources that modify (with such modification resulting in an increase in potential hourly CO2 emissions of > 10%) must meet a unit-specific numerical emission limit determined by the affected source's best demonstrated historical performance (in lb CO2/MWh-g). We do not believe that this uniform methodology allows all modified sources to determine an appropriate, achievable standard of performance  -  regardless of unit age, size, boiler type, fuel type, etc. and the EPA sees no need for fuel-specific subcategories.
6.2.2 Dependent on the Timing of the Standard
Standards based on timing of a modification are not lawful.
Commenter 0183 stated that EPA's reliance on the timing of the modification (i.e., before or after a Section 111(d) plan) to propose different standards for modified sources is arbitrary and capricious and contrary to the statute. The commenter stated that nothing in the CAA hints at linking an NSPS to the date that a State plan for existing sources becomes applicable. The commenter stated that this unlawful proposal is the result of two incorrect interpretations of the CAA: the first is EPA's imposition of a case-by-case unit standard under Section 111(b), and the second is EPA's attempt to make a source simultaneously subject to both Sections 111(b) and 111(d).
The EPA is not finalizing standards that are dependent on the timing of the modification.
Concern over date of state plan submittal and impact on utilities considering a modification or reconstruction.
Commenter 0242 stated that EPA is proposing the date for determining whether a unit is subject to a Section 111(d) plan under this co-proposed option is the date that the plan is initially submitted to U.S. EPA; that is whether the modification occurs before or after the promulgation of a Section 111(d) plan. The commenter has significant concerns with how these two Section 111 plans will function together; if alternative 2 is promulgated by U.S. EPA then a modified source will be subject to one of the two limits if the modification occurs before Ohio EPA submits their plan. The commenter stated that recognizing the time it takes for a plan to be developed, the state and sources would be working together and plans under Section 111(d) may be well underway. The commenter stated they have concerns that some changes that may be chosen by a utility necessary to comply with Section 111(d) may trigger a modification or reconstruction under this rule. The commenter stated that sources will be hesitant about making changes if they know it will trigger the modify or reconstruct applicability, particularly if U.S. EPA promulgates standards that are not achievable by certain types of coal-fired EGUs.
Commenter 0242 stated that they also have concerns about this date being based on a submittal date and not an approval date. The commenter stated that EPA has up to one year to approve the 111(d) state plan and a source that triggers the modify/reconstruct rule may find themselves in uncertain territory, as would the state. The commenter stated that assuming that elements of the Section 111(d) plan will be approved and can be used as elements for achieving compliance under this plan is risky at best. The commenter asked if EPA consider an interim plan to fall under this provision also; requirements the state intends to implement may not be known at that time under an interim plan.
The EPA is not finalizing standards that are dependent on the timing of the modification.
Alternative dates for compliance.
Commenter 0242 stated that the  EPA is taking comment on alternative dates, such as June 30, 2016 (the proposed required Section 111(d) plan submittal date), the date the state promulgates its rule, the date U.S. EPA approves the rule, and January 1, 2020 (the proposed initial compliance date for Section 111(d)). The commenter stated that each of these has their own separate issues; if a state submits an initial plan by June 30, 2016 and receives a one to two year extension, the operator will not have certainty of states intended requirements. The commenter stated that EPA should not assume states will have to promulgate a rule for all requirements under the proposed Section 111(d) plan that lead to a source's compliance. The commenter stated that January 1, 2020 will necessitate the source comply with the specified limits and additional 2 percent reduction under this proposal immediately if the modification/reconstruction occurs before January 1, 2020 and the source may have already implemented some or all changes in order to comply with Section 111(d). The commenter stated that this creates the exact scenario that EPA raised concerns about; as a result of implementation of Section 111(d) plans, an additional 2 percent efficiency improvement may not be achievable.
The EPA is not finalizing standards that are dependent on the timing of the modification.
Favors Alternative #2, but believes EPA provides little detail for these alternatives.
Commenter 0241 stated that the co-proposed alternative 2 is the preferred option because the source would be required to meet a unit-specific emission limit dependent upon when the modification occurs. The commenter stated that this is a clearer definition of applicability than the first alternative; the first alternative lists no timeframe for applicability. The commenter stated that the rule's discussion of these alternatives is very confusing; the EPA should offer clear distinct language so that there is no question as to when the rule actually applies to a modified or reconstructed unit.
The EPA is not finalizing standards that are dependent on the timing of the modification.
Favor Alternative #2 for sources that modify after becoming subject to 111(d) plan.
Commenter 0145 stated that they do not believe that sources can be simultaneously subject to the requirements of both 111(b) and 111(d); to the extent this is legally permissible, however, they favor the second alternative approach based on a unit specific assessment that identifies feasible and reasonable best operating practices and equipment upgrades. The commenter stated that it makes the most sense to allow actions taken to comply with a section 111(d) state plan that may result in improved performance at the source be credited and allowed as a way of demonstrating compliance with meeting the requirements for CO2 control under CAA 111(b) in the event that a modification occurs subsequent to becoming subject to a 111(d) plan.
Commenter 0145 stated that they favor the second approach - sources that modify after becoming subject to a CAA 111(d) plan would be required to meet a unit-specific emission limit determined by the 111 (b) implementing authority from the results of an energy efficiency improvement audit - as being more consistent with how BACT reviews (that apply NSPS standards as their floor) traditionally have been done.
The EPA is not finalizing standards that are dependent on the timing of the modification.
Problems with option 1 (modification occurs before state plan) under Alternative #2.
Commenter 0253 stated that in reference to proposed Alternative #2, sources modified prior to the 111(d) state plan must meet a limit determined by the affected source's best demonstrated historical performance (in the years from 2002 to the time of the modification) with an additional 2 percent emission reduction. The commenter stated that this proposal presents considerable difficulties, as suggested by EPA's own analysis: the Abatement Measures TSD delineates several efficiency improvements that an existing source could undertake, but even assuming a source undertook them all, it still might not achieve an additional 2 percent emission reduction.
The EPA is not finalizing standards that are dependent on the timing of the modification  -  nor is the EPA finalizing the proposed additional 2% CO2 emission reduction.
6.2.3 Historical Performance Data
Reducing emission rate by 2% below historical best performance not achievable.
Several commenters (0171, 0187, 0191, 0227, 0252) stated that a reduction of 2 percent below a units best annual performance from 2002 to the date of the modification is not achievable.
Commenter 0227 stated that by definition, a modification at any affected source is an increase in the emission rate to the atmosphere of any pollutant to which a standard applies that results from any "physical change or change in the method of operation to an existing facility. The commenter stated that detailed procedures for determining whether such an increase has occurred have been developed, but all are based on the highest past actual emission rate demonstrated at the unit during a recent representative period; assuming that physical or operational changes are planned at the source that will increase that rate, EPA has failed to explain how a decrease in emission rate below an EGU's lowest historic emission rate since 2002 is supposed to be achieved and sustained. The commenter stated that assuming that feasible and cost-effective measures could be identified to limit emissions below the highest past actual rate, they would be designed into the project from the beginning, and no modification would ever occur.
Commenter 0227 stated that utilization of such an extensive time period in a search for the lowest recorded emission rate for CO2 emissions at this time is also technically unsound, since EGUs within this source category have likely, during this same time period, been equipped with emission control equipment that by its design increases CO2 emission rates, either by actually producing additional CO2 emissions as a result of the chemical reactions that are essential to the control technology, or by increasing the amount of energy required to operate the motors, pumps, and other equipment that are an essential part of the controls, and that inherently reduce the unit's net output. The commenter stated that while the increases directly associated with these pollution control projects would themselves be categorically excluded from the definition of modification, nowhere does EPA explain how a controlled unit is expected to reduce emissions below it best pre-controlled performance. The commenter stated that their experience with emission control retrofits on its fleet of EGUs demonstrates that even when mitigating measures are incorporated into emissions control projects, pre-retrofit levels of CO2 emissions are not maintained, let alone decreased. As part of their submittal, the commenter attached as Attachment B a CO2 emission graph for the Mountaineer Plant in West Virginia, a single-unit 1,300 MW facility that has installed highly efficient controls within the period since 2002. The commenter stated that as shown in that attachment, CO2 emission rates have increased since the installation of new emissions controls, even though AEP has also utilized many of measures recommended in the EPA-referenced Sargent & Lundy report to mitigate the impact of the control installations, including upgrading turbines. The commenter stated that for all of these reasons, the proposed standard is infeasible, unachievable, and must be withdrawn.
Several commenter (0191, 0252) stated that here is also simply no record basis for the EPA's assumption that all modified sources can achieve a CO2 emission level two percent lower than the source's best demonstrated historical performance level. The commenters stated that the additional emission reductions that any particular source can achieve when making a modification depend on a number of facility-specific factors. The commenters stated that the EPA therefore should not attempt to finalize a modified/reconstructed source rule that makes a blanket determination about what any specific facility can achieve.
Commenter 0143 stated that there is no record basis for EPAs assumption that all modified sources can achieve a carbon dioxide emission level that is two percent lower than the sources best demonstrated historical performance level; the additional emission reductions that any particular source can achieve when making a modification depend on a number of facility-specific factors. The commenter stated that EPA therefore should not attempt to finalize a modified/reconstructed source rule that makes a blanket determination about what any specific facility can achieve. The commenter stated that neither should EPA finalize a rule that purports to authorize limit-setting through site-specific audits; under the plain terms of the statute, such emission limits must be set through notice-and-comment rulemaking proceedings.
Commenter 0171 stated that a review of their historic performance data since 2002, an interval with substantial emissions control installation, indicates that there are insufficient performance improvement opportunities remaining to allow achievement of proposed goal.
The EPA is not finalizing the proposed additional 2% CO2 emission reduction.
Proposal of Alternative #2 implies that Alternative #1 is not demonstrated.
Commenter 0183 stated that the proposal fails to provide justification that an emission rate based on a 2 percent reduction from a "best historical emission rate" is adequately demonstrated or achievable. The commenter stated that given that EPA is proposing a case-by-case standard (Alternative #2), which would be determined at the time of modification, EPA has failed to prove that the standard as a whole is demonstrated at all.
 The EPA is not finalizing standards that are dependent on the timing of the modification  -  nor is the EPA finalizing the proposed additional 2% CO2 emission reduction.
Heat rate is not a good measure for identifying the "best demonstrated historical performance."
Commenter 0226 stated that the EPA indicates how a unit's "best demonstrated historical performance" would be identified between 2002 and the date of modification of an affected unit. The commenter stated that, assuming EPA intended for this determination to be made by examining unit heat rate and/or CO2 emissions, they encourage EPA not to use total annual data to compare one year's performance to another. The commenter stated that heat rate (and as a result, CO2 emissions) can vary throughout a year's time depending on how the unit is operated; for example, heat rate increases as a unit is operated at rates below unit maximum and units will not necessarily have been operated at the same rate during each year that is considered. The commenter stated that it cannot be counted on that the operating-rate will be the same every year; therefore a comparison of annual unit performance cannot be depended on for identifying a time of best unit annual performance.
Commenter 0157 stated that the proposal does not square with fundamental power plant operations; heat rates, the measurement of efficiency, vary quite a bit, and usually because of factors outside the operator's control. The commenter stated that running at higher loads and more constant loads will improve efficiency; conversely, running less frequently, with more startups and shutdowns and at lower loads, will result in less efficient operation. The commenter stated that EPA has provided no basis to adequately demonstrate that it is possible to reproduce the efficiency, on a 12-month rolling average, of the best year out of the last 12. The commenter stated that EPA did not attempt to show that the source can replicate what would appear to be an uncommon collection of factors that happen only once in 12 years; and with each passing year, the likelihood that the "best year" is aberrational increases. The commenter stated that there is no clear way to define best historical CO2 emission rate; over what period of time would this rate be expressed: hourly, daily, monthly, yearly?
Commenter 0222 stated that in competitive markets, the number of hours a regulated EGU operates may vary depending on market and other factors such as the price of fuels; EPA's emissions limits and standards do not take these types of swings into account. The commenter stated that a unit's lowest emitting year, by rate, may be the unit's highest operating year, by hours, and historically, the more a unit operates the lower its emissions rate is on a per megawatt-hour basis. The commenter stated that a unit's lowest emitting year would also likely be a year with minimal shutdown and startups. The commenter stated that there will be some years that a unit will not be operating at maximum load, which will likely result in an increased emissions rate and will make compliance with a "best operating year" compliance target extremely difficult, and impossible in many years, even without the 2 percent reduction. The commenter stated that economic forces and other regulatory requirements, or both, are beyond the control of the electric utility and the ability of an operator of an EGU to comply with EPA's environmental regulations should not be dependent on market factors and should especially not be undermined by EPA's own regulations.
Commenter 0224 stated that, regarding EPA's alternative standards of performance depending on when a modification occurs, unless the facility at the time of its best historical performance is comparable to the facility at the time of modification, its best historical performance would not be representative of what the facility could achieve immediately prior to modification. The commenter stated that if the historical best performance is prior to the addition of control equipment, it would be extremely difficult to replicate that best historical performance, much less achieve an additional 2 percent emission reduction above it. The commenter stated that EPA should provide an adjustment to assure that comparable facilities are being measured when evaluating historical best performance. Commenter said a related point concerns EPA's proposal to change the definition of "steam generating unit" to include "any integrated equipment that provides electricity or useful thermal output to either the affected facility or auxiliary equipment." 79 FR at 34972/3. In light of this change, auxiliary boilers for thermal uses with limited operation should be exempt from this definition if such boilers are already under a permitted limit requirement of an annual capacity factor at less than or equal to 10 percent. Further, to the extent that an affected steam generating unit is run to provide building heat or for other thermal uses for comfort, that output should be excluded from the compliance calculations for determining the unit's CO2 lb/MWh rate. Unless the facilities are comparable, use of the best historical performance presents an unrealistic estimate of what the facility can currently achieve, and thus whether it can achieve the additional 2 percent reduction to meet this performance standard.
 First, the EPA notes that the additional 2% reduction that was suggested in the proposal has not been incorporated into the final requirements in the final standards of performance for modified steam generating units. Also, as provided in Chapter 2 of the "GHG Mitigation Measures" Technical Support Document for the CPP Final Rule (and available in the Carbon Pollution Standards (111b) rulemaking dockets: EPA-HQ-OAR-2013-0495 and EPA-HQ-OAR-2013-0603), analyses indicate that there is significant potential for heat rate improvement from the fleet of coal-fired EGUs, ranging from 4.0 to 6.6 percent nationally if coal-fired EGUs, on average, return to their best past performance between 2002 to 2012. We further note that the EPA is only finalizing standards for EGUs that conduct modifications resulting in an increase in potential CO2 hourly emissions of more than 10 %. Based on historical trends, we expect few, if any, EGUs to trigger that threshold and become subject to the finals standards. Those that do will do so only after taking actions  -  likely capital intensive actions  -  that trigger the modification provisions. Sources undertaking such capital-intensive projects can take steps to avoid triggering modification, such as measures to avoid increasing their emissions of pollutants  -  or can take measures at the time of the capital-intensive modification project to ensure that the final standard can be achieved. Affected sources also have the option of alternative compliance measures such as natural gas co-firing.
Prefer Alternative #1, but make historical performance period from 2002 to last full calendar year before modification expected construction start date.
Several commenters (0260, 0178) stated that if EPA finalizes emission standards based on the proposed BSER determination, they support the first proposed alternative, with the following revisions. The commenters stated that the period for the unit's best demonstrated annual performance should not be a single year between 2002 and the year the modification occurs. The commenters stated that if this period includes the year in which construction on the modification begins, owners and operators would not be able to calculate the appropriate modified unit emission rate until immediately prior to construction; this would make it difficult for owners and operators to decide whether or not to undertake a modification in the first place because they would be unable to determine the compliance obligations of the plant post-modification. The commenters stated that the owner/operator would have to estimate what the emission standard might be, then proceed with plans for construction, which likely would entail obtaining permits, entering into contracts, ordering equipment and preparing for an outage without full knowledge of the emission standard it would be required to achieve post-modification. The commenters stated that the cut-off for determining the end of the period of the unit's best demonstrated annual performance should be the last full calendar year prior to the proposed modification's expected construction start date.
 The final standard is based on the unit's best annual performance from the years 2002 to the date of the modification. While explicitly stated, the best annual performance should be interpreted to be a full calendar year and therefore the standard would be based on the historical performance period from 2002 to the last full calendar year before modification expected construction start date.
Prefer Alternative #1, but standard should be based on multiple years.
Multiple commenters (0260, 0178) stated that, in addition to making the cut-off for determining the end of the period of the unit's best demonstrated annual performance the last full calendar year prior to the proposed modification's expected construction start date, the unit-specific numerical emission standard should not be based on a single year but should use the best three years out of a five-year period; at a minimum, EPA should employ a three-year average, which will better account for natural variation inherent in unit operations, and anomalous events such as extreme weather events and unplanned outages.
Commenter 0145 stated that given the year-to-year variability on generator usage and the differences in heat rate efficiency of units under different loads, setting the baseline emission rate on the best annual average will make it difficult for certain units to meet the standards year-in and year-out. The commenter stated that this is especially true where there are significant hydropower resources, since in good years these resources will provide significantly more power than in bad years resulting in higher CO2 emission rates at these units due to operating at lower, less efficient loads. The commenter stated that to mitigate these effects, the final rule should use the best consecutive three-year average to account for year-to-year variability in usage and emission rates from fuel-fired generators.
Commenter 0257 stated that to the extent the final rule requires an additional two percent reduction in emissions below historical performance, then the baseline emission rate should be based on an average performance over multiple years; for example, the best three-consecutive-year average emission rate between 2002 and the year prior to when a source becomes subject to a section 111(d) plan. For sources that have installed pollution control equipment, the commenter requested that the look back period be modified to include only years after the installation of pollution control equipment. The commenter stated that a multi-year average is a better gauge of operating efficiency than any single year and that the average should not include emissions data prior to the installation of pollution control equipment.
Commenter 0157 stated that a better and more defensible approach would be to take the average heat rate over the period from 2002 until the time of the modification, and use that as the basis for the 2 percent improvement.
Commenter 0162 stated that if historic data were utilized for future emission standards, a multiple year approach is preferred to a single year, to account for operational variability of the unit. An average of three years CO2 emission rate data would give a better picture of the historical production of CO2 under varying conditions including weather and load patterns which impact actual unit operation. The commenter stated that in addition, significant changes in operation have occurred in the years since 2002 with the addition of renewable energy, including wind generation, and more recently the commenter's participation in the Southwest Power Pool (SPP) day-ahead integrated marketplace; both of these operational changes require sources to go through startup and shutdown more frequently or operate at lower load levels, neither of which results in optimum efficiency and will result in higher CO2 emissions on a rate basis. The commenter stated that historical look-backs when units were operating under different conditions do not predict what a source's best performance in the future will be.
Commenter 0242 stated that do not agree with using a single best year as the basis of the best historical performance as it is not representative of an achievable rate over the long term, even when all technical and economical improvements are made. The commenter stated that, for example, after a rebuild, equipment can degrade and increase the heat rate as much as 1percent in one year; rebuilds can only occur on limited frequencies due to reliability concerns and cost-effectiveness. On the question of whether the historical performance period should end when the modification occurs as proposed, or should end when the unit becomes subject to Section 111(d), the commenter stated that, although they believe that it is unlawful to include modified units into the Section 111(d) plan, this should be left to the state to determine based upon HRIs that the unit has achieved as part of Section 111(d). The commenter stated that a multi-year average determined by the state based upon historical information and unit-specifics is the only appropriate alternative.