Document ID: EPA-HQ-OAR-2013-0495-11820
Agency: epa
Document Type: Supporting & Related Material
Title: 
Posted Date: 2015-10-23T04:00Z

Chapter 6
 Modified Fossil Fuel-fired Utility Boilers and IGCC Units
6.1	Identification of BSER	4
Same BSER for modified and reconstructed sources	4
6.1.1 Efficiency Improvements Achieved Through a Combination of Best Operating Practices and Equipment Upgrades	5
Efficiency improvements can be made without triggering a modification	5
EPA Underestimates the Potential for Efficiency Improvements	7
6.1.1.1 Technical Feasibility	8
6.1.1.2 CO2 Reductions	42
6.1.1.3 Costs	43
6.1.1.4 Incentive for Technological Innovation	46
6.2	Determination of the Level of the Standard	47
2% HRI not achievable due to many factors	47
In setting standards, EPA incorrectly interpreted the 2009 Sargent & Lundy report in regards to improvements related to Building Block 1	49
Proposed standards of performance are not achievable and are therefore not lawful	50
Standards equivalent to reconstructed sources are not appropriate	50
Modified/reconstructed source standards should not be same as standards for new sources	51
Relationship with 111(d)	51
Setting limits using EPA proposed ranges	52
Standards are too lenient	53
6.2.1 Unit-specific Emission Limit	56
Unit-specific standards illegal	56
Standards at each unit should be feasible based on a proven, operational, technological and economic standpoint	59
Compliance options	61
Exemption from 2% additional emission reduction	61
EPA must set a numeric emission rate	63
EPA proposed practicable emissions standard	63
6.2.2 Dependent on the Timing of the Standard	64
Standards based on timing of a modification are not lawful.	64
Concern over date of state plan submittal and impact on utilities considering a modification or reconstruction.	65
Alternative dates for compliance.	65
Favors Alternative #2, but believes EPA provides little detail for these alternatives.	66
Favor Alternative #2 for sources that modify after becoming subject to 111(d) plan.	66
Problems with option 1 (modification occurs before state plan) under Alternative #2.	66
6.2.3 Historical Performance Data	67
Reducing emission rate by 2% below historical best performance not achievable.	67
Proposal of Alternative #2 implies that Alternative #1 is not demonstrated.	68
Heat rate is not a good measure for identifying the "best demonstrated historical performance."	68
Prefer Alternative #1, but make historical performance period from 2002 to last full calendar year before modification expected construction start date.	70
Prefer Alternative #1, but standard should be based on multiple years.	71
Prefer Alternative #1, but period of best historical performance should be years from 2002 to the time when the unit becomes subject to section 111(d).	74
Heat rates prior to a PCP should not be used in determining best historical CO2 emission rate.	74
Prefer Alternative #1, but implement in a way that does not penalize investments in heat rate improvements.	75
Establish limit based on expected future operations including lower operating loads levels due to greater use of renewables.	76
6.2.4 Energy Assessment: Similar to NESHAP for Industrial Boilers	78
Contrary to NSPS and CAA	78
Energy efficiency audit in not a standard of performance that reflects BSER for the source category as required under CAA 111(a).	78
Contrary to NSPS and CAA - Lack of details on procedures and demonstration of feasibility & fails the notice and comment obligations of CAA.	80
EPA's proposed site specific standard and failure to provide for notice and comment are unlawful.	81
There is no CAA authority for third party audit as basis of standard.	82
Lack of details and lack of support call into question the feasibility of audit approach.	82
Energy audit requirements not well defined, and, instead, support work practice standards.	83
Alternatives #1 and #2 are unachievable.	83
In absence of energy audit expert certification process, EPA should not require one.	84
Use of previous energy audits.	84
Instead of the proposed vaguely defined auditing process, EPA should use PSD programs pre-permitting BACT reviews.	84
Purpose of energy audits unclear as states would have to rely on methods other than unit-specific emission rates for modified units to meet their state goals.	85
Standard that allows states to determine on a case-by-case basis what emission reductions are possible and reasonable after consideration of site specific factors is reasonable alternative.	85
EPA should consider using the BACT process to set emission standards for modified and reconstructed units	87
6.2.5 Subjectivity to 111(d)	88
Support for being subject to the lower of the 111(d) plan instead of the unit's best performance since 2002	88
Heat rate improvement potential - an additional 2 percent efficiency improvement may be unachievable for sources that make efficiency improvements as part of a 111(d) state plan. There is simply no record basis for this.	88
Heat rate improvement potential - EPA is applying existing unit standards (aggregated data for older and newer units) with modified unit standards (unit level rates). This results in standards not shown to be achievable at unit level (not supported in the proposal) as required by 111(a)(1).	88
Reliance on the Sargent & Lundy study does not justify heat rate improvement potential.	90
Modified source emission standard should consider whether a modification occurs after or before the Section 111 (d) requirements are effective.	90
Sources subject to 111(d) guidelines should remain under 111(d) guidelines and not be subject to Section111 (b).	90
Modified sources subject to a 111(d) plan should be evaluated on a case-by-case basis to determine whether or not they should be subject to the 111(d) requirements.	92
If EPA requires the 2 percent reduction requirement, it should require that the reduction be off of a unit's heat rate at full load per, calculated pursuant to ASME performance test codes.	93
Existing unit reductions are not achievable, it is unrealistic to expect an additional 2% reduction for modified units, and reliance on hypothetical unit is overly simplistic.	93
Should uniform emission standards be available only to sources that modify before becoming subject to an approved 111(d) plan?	94
EPA lacks authority to require modified sources to remain subject to section 111(d) regulation after modification.	94

Identification of BSER
Commenter 0215 believed that EPA revealed an incomplete nature for its Proposed Standards for modified units by posing a long series of questions that seems calculated to shift the burden of developing a basis for the Proposed Standards to the regulated community. EPA's queries essentially showed that the Agency wasn't confident how its Proposed Standards might affect or apply to the approximately 955 coal-fired Subpart Da units that UARG expects will be operating in 2015. The Agency's failure to complete the necessary background work suggests that a more appropriate course of action at this time would have been an advance notice of proposed rulemaking designed to elicit information to use in formulating a proposal, rather than propose an approach that is both poorly-conceived and has not been analyzed. Commenter said they appreciates the Agency's interest in obtaining information necessary to develop a sound proposal, but the myriad questions posed here confirm that EPA has failed to collect the data and perform the technical analyses needed to identify and analyze the impacts of its Proposed Standards. Commenter said they can respond to some of EPA's inquiries, but many of EPA's questions cannot be answered without detailed analyses of emissions and other data that the Agency should have undertaken and placed in the docket as part of its basis and purpose of the Proposed Standards. See CAA section 307(d)(3). Commenter said the APA defines a rule as a statement of "future effect" designed to "prescribe law or policy." See 5 U.S.C. section 551(4). Because a rule is intended to prescribe the legal standards that govern the future conduct of regulated parties, a proposed rule must be more than a vague set of criteria for future applications with a series of questions regarding how the Agency might formulate a final rule. See Small Refiner Lead Phase-Down Task Force v. EPA, 705 F.2d 506, 549 (D.C. Cir. 1983) ("Agency notice must describe the range of alternatives being considered with reasonable specificity" to allow for adequate public comment and "better-informed agency decision-making"; unspecified, general notice is inadequate). Commenter said the Agency's Proposed Standards are entirely inadequate in this regard, and thus EPA should terminate this proceeding until it has had time to gather and analyze the data needed to formulate a proper proposed rule.
The EPA did provide appropriate and adequate specificity concerning the standards that were being considered in the proposed action. The well-developed and considered comments received on the proposed action  -  and summarized in this Response-to-Comment document  -  are testament to that specificity. 
Same BSER for modified and reconstructed sources 
Commenter 0263 stated that the EPA chose BSER for modified sources as the most efficient generation at the affected source achievable through a combination of best operating practices and equipment upgrades; however, for reconstructed sources, EPA proposed most efficient generating technology at the affected source as BSER. The commenter stated that EPA should choose the same BSER for modified and reconstructed sources, and BSER should be comprised of increased efficiency achieved through a combination of best operating practices and equipment upgrades. The commenter stated that CAA regulations mandate that BSER sets the floor for future BACT determinations, but EPA rules do not require a state to consider any control technology that would require a redesign of the proposed source. The commenter stated that the EPA's own guidance on GHG permitting states that a control technology can be excluded from a BACT analysis if the control strategy would disrupt the facility's basic or fundamental business. The commenter stated that if EPA were to select supercritical technology as BSER, it would force source redesign as BACT and would eliminate the states's ability to consider a source's primary business purpose when assessing appropriate emission controls. The commenter recommended that EPA maintain its proposed combination of best operating practices and equipment upgrades as BSER for modified utility boilers and IGCC units; they also recommended that EPA determine the combination of best operating practices and equipment upgrades as BSER for modified natural gas combined cycle (NGCC) and all reconstructed units as well.
The EPA has maintained its proposed combination of best operating practices and equipment upgrades as BSER for modified utility boilers and IGCC units as suggested by the commenter.  However, we have done so only for those EGUs that make modifications that result in an increase of potential hourly CO2 emissions of more than 10 percent. 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. We do not have sufficient information at this time, however, to anticipate the types of modifications, if any, that may result from these changes. In particular, for steam generating EGUs (utility boilers and IGCC units) we do not have sufficient information about the types of modifications, if any, that would result in hourly increases in CO2 emissions of 10 percent or less, and what the appropriate standard for such sources should be. Therefore, we conclude that it is prudent to delay issuing standards for sources that undertake small modifications (i.e., those resulting in an increase in CO2 emissions of less than or equal to 10 percent) and we have withdrawn the proposed standards for those sources in the final action.  
The commenter also recommended that EPA determine the combination of best operating practices and equipment upgrades as BSER for modified natural gas combined cycle (NGCC) and all reconstructed units as well. The EPA is not finalizing standards for modified stationary combustion turbines and in withdrawing those standards in the final action (see preamble sections VII, VIII, and XV.)
6.1.1 Efficiency Improvements Achieved Through a Combination of Best Operating Practices and Equipment Upgrades
Efficiency improvements can be made without triggering a modification 
Commenter 0244 stated that efficiency improvement projects can be undertaken without modifying an EGU for NSPS purposes. [The commenter lists several efficiency upgrades that have been identified for existing EGUs that include improvements on a number of operation and maintenance controllable variables.] The commenter pointed out that within the potential efficiency improvement options, only one upgrade option - turbine blade replacements - has been mentioned as a potential NSPS modification. The commenter stated that industry representatives have suggested that EPA should not establish rigorous standards for modified units because some potential projects that improve the plant's overall thermal efficiency may also increase a unit's hourly emissions rate of CO2. These representatives argue that projects of this nature should be encouraged to the greatest extent possible, and highlight in particular the example of turbine blade replacements. While individual blades or groups of blades may routinely be replaced with new blades of the original designs, the maximum generating capacity of the unit (in terms of megawatts) and the unit efficiency can be improved by replacing all of the blades in one or more of the three stages of a steam turbine with improved blade design, blade layout, and edge seals that more effectively convert thermal steam energy into electricity. For those operators seeking the maximum available capacity increase, the engineering solution is to add additional heat capacity to the boiler. If this choice is made, the unit produces more electricity per unit of fuel than it did previously, but now emits more CO2 and criteria pollutants per hour as well, in which case the unit may qualify as modified for NSPS purposes. The commenter stated that source operators can implement many of the potential efficiency upgrade options in a way that would constitute a NSPS modification, but only because those upgrades would result in capacity increases. The commenter stated that this is a choice that is available to owners for condensers, fans, burners, and other components, but under no circumstances is it necessary to select a larger capacity component in order to achieve greater efficiency. It is therefore incorrect to assert, as some industry representatives have done, that plant operators cannot improve their units' thermal efficiency without triggering the NSPS modification rules. 
The commenter stated that under the agency's current policy, turbine blade replacements by themselves do not constitute section 111 modifications and thus do not trigger applicability of a modified source performance standard because the agency has specified that steam turbines are not part of the existing affected facility for NSPS purposes. The commenter stated that EPA regulations at 40 C.F.R. 60.14(e)(2) specify that if an increase in production rate of an existing facility can be accomplished without a capital expenditure on that facility, then it does not constitute a modification under section 111. The commenter stated that under the agency's current policy, a turbine blade replacement project that does not entail capital expenditures to the boiler itself or some other piece of equipment that falls within the definition of electric utility steam generating unit does not qualify as a modification for the purposes of the NSPS program, even if the project increases the hourly emission rates of CO2 or other pollutants.
The commenter stated that the most appropriate limit for modified units is the new source standard, which we believe should be no less stringent than 1,200 lbs CO2/MWh on a net output basis, reflecting a BSER of efficiency generating technology with partial CCS. According to the commenter a number of successful turbine blade replacement projects have been undertaken over the years without associated capital boiler projects that increase hourly emissions and EPA has published at least one Applicability Determination confirming that turbine blade replacements can be done in a manner that does not constitute a modification under the NSR program. Commenter referenced a Siemens report and a letter from EPA region 5. The commenter stated that to their knowledge EPA has only asserted that the NSPS program applies to large life extension projects, in which a turbine blade replacement would be part of a larger project that included capital boiler upgrades. 
The EPA agrees with the Commenter that there are many efficiency / heat rate improvements that EGUs can make  -  and have made  -  that do not result in an increase in hourly emissions of CO2 and thus do not trigger the 111(b) modification provisions. However, the EPA does not provide specificity on exactly what projects or scenarios would or would not trigger 111(b) modification for GHG emissions as sources undertaking projects can take steps to avoid triggering modification, such as measures to avoid increasing their emissions of pollutants.
EPA Underestimates the Potential for Efficiency Improvements
Commenter 0244 summarized BSER for modified coal plants and noted that these units would remain subject to any applicable state plan under section 111(d) regardless of modification. The commenter stated that in the event a court found that existing units that undergo modifications cannot remain subject to the requirements of the (d) plan, EPA's proposal would be far less stringent than the proposed emission guidelines for unmodified existing units, and even if these sources are retained in 111(d) plans, modifications that extend the life of 50-year old plants should be discouraged by stringent 111(b) obligations. The commenter stated that EPA has provided no adequate rationale for not applying the new source standard, nor has it sufficiently justified its rejection of other BSER options for modified steam EGUs, including the use of combined heat and power (CHP), hybrid power plants, and reductions in generation associated with dispatch changes, renewable generation, and demand-side energy efficiency.
The commenter stated that a capital intensive modification that increases the emissions of an NSPS-regulated unit is and should remain rare; if such an investment is warranted because of the value of the unit, the modifying unit should incorporate the full suite of available efficiency improvement options. The commenter stated that the record does not support any threshold emission rate for existing units below which efficiency improvements are no longer feasible; EPA's unit-level emission data set included in its 111(d) Goal Computation TSD contains at least 25 coal-fired EGUs with reported emission levels of less than 1,900 lbs CO2/MWh (net), and many more smaller units with emission rates below 2,100 lbs CO2/MWh (net), belying any notion that emission limits of 1,900 and 2,100 lbs CO2/MWh represent a technological barrier for efficiency in existing units. The commenter stated that data maintained by EPA's Air Markets Program Division confirms that efficiency improvements below 1,900 lb CO2/MWh (net) are readily achievable. The commenter provided two examples (Rush Island Unit One and Belews Creek Unit One) that can be found in EPA's data to illustrate their point. The commenter stated that the agency has the means to evaluate these data fully and make a determination based on actual evidence rather than an unsupported, generalized assumption.
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.
6.1.1.1 Technical Feasibility
Not achievable and not demonstrated 
Several commenters (0144, 0150, 0152, 0156, 0153, 0157, 0170, 0179, 0183, 0187, 0192, 0195, 0203, 0208, 0215, 0218, 0221, 0222, 0223, 0226, 0229, 0231, 0235, 0242, 0249, 0254, 0276, 0278, 0284) stated that the EPA has not provided the required support and technical demonstration that the proposed BSER is technically feasible.
The EPA disagrees with this premise. As shown in responses to subsequent comments in this section of the Response-to-Comment document, the EPA has demonstrated the technical feasibility and achievability of the final standards for affected modified and reconstructed EGUs.
Commenter 0183 stated that an engineering firm conducted a preliminary analysis of potential heat rate improvement opportunities at the commenter's coal-fueled units and that analysis determined that EPA's 4 percent projection overstates the potential for heat rate improvements, which for the commenter's units showed a range of potential heat rate improvements of less than 0.5 percent. Thus, from all perspectives, EPA's projections are vastly overstated and unachievable. The commenter stated that even the modest improvements that may be possible cannot be sustained given that additional factors negatively impact heat rate efficiency, including the addition of environmental control equipment and their auxiliary load in response to other EPA rules. According to the commenter, assuming the remaining fleet will be required to implement these technologies as the EPA continues to lower the emission requirements for the existing coal fleet, the heat rate of the existing fleet would likely be increased over 1 percent. 
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 existing 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. The most conservative approach that is supported by the weight of evidence yields average potential heat rate improvements of 2.1 percent in the Western Interconnection, 2.6 percent in the Texas Interconnection, and 4.3 percent in the Eastern Interconnection.
Commenter 0221 stated that EPA's proposed standard for modified and reconstructed EGUs exceed its statutory authority since they are not achievable as required by section 111. The commenter stated that no existing subcritical unit has ever been converted to supercritical technology since it is economically impractical; therefore, conversion to supercritical technology has not been adequately demonstrated. The commenter stated that the emission limits proposed, 1,900 pounds of CO2 per megawatt hour (lb CO2/MWh) net or 2,100 lb CO2/MWh-net depending on heat input, have not been achieved by new units much less existing units undergoing reconstruction. 
See response to previous comment on the technical feasibility of the final standards for modified sources. With regard to the comment that "no existing subcritical unit has ever been converted to supercritical technology since it is economically impractical", the EPA points out that triggering the reconstruction provision is a significant economic hurdle  -  and it has only rarely been done. Per 40 CFR 60.15  -  `Reconstruction' means the replacement of components of an existing facility to such an extent that: (1) the fixed capital cost of the new components exceeds 50 percent of the fixed capital cost that would be required to construct a comparable entirely new facility, and (2) it is technologically and economically feasible to meet the applicable standards set forth in this part. The 50% of fixed capital cost that would be required to construct an entirely new EGU would almost certainly involve significant  -  and very costly investment (if not entire replacement of) the boiler. At that time, conversion from a subcritical boiler to a supercritical boiler can be done [or complete replacement with a new supercritical boiler]. However, if the owner/operator can show it is not "technologically and economically feasible to meet the applicable standards set forth in this part", then it would not trigger the reconstruction provisions. The EPA points out here  -  and in the preamble in section VII  -  that owners/operators can also consider the use of natural gas co-firing to achieve the final emission limitation without the need to convert the subcritical boiler to supercritical. Natural gas co-firing has long been recognized as an option for coal-fired boilers to reduce air emissions of criteria and hazardous air pollutants. EPRI sponsored a study to assess both technical and economic issues associated with natural gas co-firing in coal-fired boilers and determined that the largest number of applications and the longest experience time is with natural gas re-burning and with supplemental gas firing. Natural gas re-burning  -  which can introduce up to 20 percent total fuel heat input - has been used primarily as a NOx control technology. Higher levels of natural gas co-firing can be met by utilizing supplemental gas co-firing (either alone or along with natural gas re-burning). This involves the simultaneous firing of natural gas and pulverized coal in a boiler's primary combustion zone. Others have also evaluated configurations that would allow coal-fired units to utilize natural gas.  A 2013 article entitled "Utility Options for Leveraging Natural Gas" [10/01/2013 article in Power. Available at http://www.powermag.com/utility-options-for-leveraging-natural-gas/] noted that: Utility owners of coal-fired power stations that wish to balance their exposure to coal-fired generation with additional natural gas - fired generation have several options to consider. The four most practical options are co-firing coal and gas in the same boiler, converting the coal-fired boiler to gas-only operation, repowering the coal plant with natural gas - fired combustion turbines, or replacing the coal plant with a combined cycle plant. [...] Co-firing is the lowest-risk option for substituting gas use for coal. 
Commenter 0183 stated that the EPA has failed to demonstrate the achievability of a 1,900 lbs CO2/MWh standard for the source category, a value that is not sustainable even at an ultra-supercritical (and thus highly efficient) unit, much less by the existing fleet of coal plants in the country. According to the commenter, the only ultra-supercritical plant operating in the country, AEP's Turk unit was designed to emit approximately 1,940 lbs CO2/MWh. The commenter stated that while early data from the first year of operations showed that the Turk unit could, at times, operate below 1,900 lbs CO2/MWh, its efficiency will likely degrade over time, as with all coal plants, and would exceed 1,900 lbs CO2/MWh; the first year of operation will likely be atypical from a CO2 emissions standpoint. The commenter stated that EPA fails to address or account for these data; further, based on research by J. Edward Cichanowicz and Michael C. Hein, a reasonable standard must subcategorize sources to address the clear differences in CO2 emission rates from subcritical, supercritical, and ultra-supercritical units and from different coal types. The commenter stated that EPA has attempted to show that a value of 1,900 lbs CO2/MWh may be achievable in the short term at a new ultra-supercritical unit designed to meet that rate, but it has not identified any control technology or retrofit of an existing coal unit that could bring a supercritical unit, especially a lignite unit, into compliance with that rate.
According to EPA CAMD data (which is discussed in the TSD "Achievability of the Standard for Newly Constructed Steam Generating EGUs" available in the rulemaking docket), the best monthly rate for the AEP John W. Turk plant is 1,725 lb CO2/MWh-g. The unit's best 12-operating-month average rate is 1,753 lb CO2/MWh-g and its highest 12-operating-month average is 1,817 lb CO2/MWh-g. The commenter claimed that the Turk unit's first year of operation will likely be atypical from a CO2 emissions standpoint and that the performance will likely degrade over time. The figure below does not show that to be the case.  Since its startup the performance of the Turk facility has improved with time and its most recent emission rates are well below the 1,800 lb CO2/MWh-g final emission limitation for large reconstructed EGUs. Further, as the EPA has noted in the preamble in section VII, owners/operators can also consider the use of natural gas co-firing to achieve the final emission limitation.

Figure 6-1. Monthly CO2 emission rates (lb CO2/MWh-g) from the AEP John W. Turk plant

Commenter 0214 stated that EPA's proposed BSER determination for modified boilers and IGCC units is flawed because EPA failed to analyze the technical feasibility and cost reasonableness of equipment upgrades for all affected sources - that is - all fuel types, technologies, and sizes. The commenter stated that while EPA mentions equipment upgrades have been made at a "wide range of power plants," the Agency must provide real-world examples not just broad general statements; specifically, EPA must provide sufficient information regarding the equipment upgrades that EPA claims are capable of achieving compliance with EPA's proposed standards at all potentially affected sources, taking into account all different fuel types, combustion technologies, and size classes, which it has not done.
Commenter 0218 stated that the EPA failed to correlate their statistical study with actual case studies of base-load EGUs which employ such best practices to reduce heat rate variability relying instead on a 2009 Sargent & Lundy study, which determined a potential heat rate improvement range for each of the identified equipment upgrades based on a literature review. The commenter stated that based on the average of the study's ranges of potential heat rate improvements from equipment upgrades, and a determination that half of the equipment upgrade opportunities outlined in the study remain for existing units, EPA proposed the technical potential for heat rate improvements that could be achieved from equipment upgrades are on the average of two percent. The commenter stated that to account for facilities that have already implemented BSER, i.e., best practices and equipment upgrades, EPA proposed that modified facilities would not have to meet an emission standard more stringent than the corresponding standard for reconstructed facilities; EPA proposed a unit specific standard equal to a 2 percent reduction in the unit's historical CO2 emission rate, but not lower than the proposed standard for reconstructed units. The commenter stated that EPA did not provide any data to support this proposed standard. Therefore, it must be considered arbitrary and capricious.
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 existing 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. The most conservative approach that is supported by the weight of evidence yields average potential heat rate improvements of 2.1 percent in the Western Interconnection, 2.6 percent in the Texas Interconnection, and 4.3 percent in the Eastern Interconnection. Further, as the EPA has noted in preamble section VI, owners/operators can also consider the use of natural gas co-firing to achieve the final emission limitation for affected modified EGUs.
Commenter 0242 stated that they have concerns regarding a unit encroaching upon a low end cap rate that would be achievable by reconstructed units applying BSER and that this is why setting any fixed limits based upon energy efficiency potential that are technically and economically feasible outside of a source specific analysis is not appropriate. 
Commenter 0214 stated that the EPA's claim that a unit can consistently perform at its historical best demonstrated annual performance is unreasonable and unsupported and that the EPA does not consider that a unit's efficiency is variable over time due to uncontrollable factors, such as: shifting operating conditions (e.g., changing capacity and load factors), changes to parasite load due to environmental controls, natural efficiency degradation, prevailing weather conditions, availability of other units and resulting impacts to load profile, and fuel switches (e.g., bituminous to subbituminous coal), and other factors.
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. The most conservative approach that is supported by the weight of evidence yields average potential heat rate improvements of 2.1 percent in the Western Interconnection, 2.6 percent in the Texas Interconnection, and 4.3 percent in the Eastern Interconnection. In that Chapter of the TSD, EPA discusses the issues of variability and factors outside the operators' control, and provides additional information on heat rate improvement practices and equipment upgrades that might be available to coal-fired EGUs. Implementation of these best practices and equipment upgrades will allow units to maintain best potential performance. Further, as the EPA has noted in preamble section VI, owners/operators can also consider the use of natural gas co-firing to achieve the final emission limitation for affected modified EGUs. 
 
Commenter 0253 stated that EPA's proposed numerical range of potential emission limits for the several different source categories ignores that no economically viable, commercially available CO2 control technologies are available for existing units, thus calling into question whether the proposed standards can be achieved. The commenter stated that if no commercially viable CO2 control technology is available for installation on existing units that are modified or reconstructed, a proposed standard based on an assumption of availability is not achievable. The commenter stated that even if available, there is no degree of certainty that adding certain controls to existing EGUs within a category would necessarily result in a uniform (or close to uniform) emission reduction level within the category; rather, an existing unit's achievable efficiency and CO2 emission rate will depend largely on its underlying design and site-specific conditions.  
The EPA did not suggest that proposed or final standards for modified steam generating units should be met with CO2 specific control technologies, such as carbon capture and sequestration. The EPA proposed and is finalizing that the standards for affected modified steam generating EGUs can be met through unit efficiency improvements achievable through a combination of best operating practices and equipment upgrades. The commenter notes that "an existing unit's achievable efficiency and CO2 emission rate will depend largely on its underlying design and site-specific conditions". The EPA largely agrees  -  which is why the final standard of performance for affected modified steam generating EGUs is unit-specific and will depend upon that unit's own best potential performance  -  inherently taking into account its underlying design and site-specific conditions.
Commenter 0226 stated that the suggestion in the proposal that heat rates can be improved at existing units up to 2 percent through equipment upgrades is not adequately supported. The commenter stated that part of the proposed support is found in the docket in Chapter 2 of the document GHG Abatement Measures; section 2.5.9 of the document discussed that 16 EGU s were identified that reported a single year-to-year heat rate improvement of 3-8 percent. The commenter stated a search of the docket reveals, at EPA-HQ-OAR-2013-0602-0236, that a Cleco unit, Brame Energy Center Unit ID 2, is listed as one of the identified 16 units. The commenter stated that they are not aware of reporting heat rate data to EPA in the past and they calculated the annual heat rate for Brame Energy Center Unit ID 2 over the years 2002-2012 using measured fuel input and measured generated electricity (gross) and that none of the changes in heat rate from one year to another are as much as a 2 percent increase. The commenter stated that they are not aware of any upgrades taking place during the time period that would account for any heat rate improvements referred to in the TSD GHG Abatement Measures; the variation in heat rate is thought to be due to the way in which the unit was operated.
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) has been updated in response to comments received on this proposed action as well as the proposal, under CAA 111(d), for emission guidelines for existing sources. The analyses in the final document (Chapter 2) 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. Further, as the EPA has noted in preamble section VI, owners/operators can also consider the use of natural gas co-firing to achieve the final emission limitation for affected modified EGUs.
Commenter 0144 requested that the EPA provide the support and technical demonstration of the feasibility of requiring an additional 2 percent reduction in annual CO2 emissions, particularly when there is already a debate on whether the 6 percent heat rate improvement is achievable. The commenter stated that because the EPA intends for units to be subject to both Sections 111(d) and 111(b), they are interested in the technical review of how these requirements were evaluated together. The commenter stated that EPA has not provided the historical calendar year CO2 emissions data from 2002 to 2013 that would be the basis for this proposal, nor has it calculated the specific emissions limit that would have to be achieved for the EGUs subject to this proposal using its 2 percent methodology; without adequate record support, such requirements are arbitrary and capricious and contrary to the CAA.
The EPA is not finalizing the requirement of an additional 2% reduction as proposed.
Commenter 0150 stated that EPA's proposed BSER is each unit's own best potential performance based on a combination of best operating practices and equipment upgrades. The commenter stated that EPA has provided no analysis supporting this conclusion and, for this reason alone, the Modified/Reconstructed Proposed Rule for modified Subpart Da EGUs is unlawful. 
The EPA disagrees. The information provided in the GHG Abatement Measures Technical Support Document provided ample support for the proposed standards. The analysis provided in the final 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), 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 modified units also have the option of meeting the final standard of performance through the use of natural gas co-firing.
Commenter 0192 stated that EPA overestimates the potential for heat rate improvements at existing coal-fired EGUs by assuming that all of the heat rate improvements identified in studies cited in the GHG Abatement Measures Technical Support Document are additive when in reality, many of the identified heat rate improvements will have overlapping effects, meaning that if implemented together, the overall reduction in CO2 emissions would be less than what EPA projects by simply adding together their isolated impact on CO2 emissions. The commenter stated that EPA also does not establish that any single facility could implement each of the heat rate improvements identified by EPA; in some cases, due to design constraints and other technical issues, two or more of the heat rate improvements may be mutually exclusive and a facility would have to choose between them when seeking to reduce emissions through heat rate improvements. The commenter stated that EPA's failure to consider these impediments to emissions reduction through heat rate improvements is arbitrary and capricious.
Commenters on the 111(d) proposed emission guidelines also commented that many of the heat rate improvement equipment upgrades cited in the GHG Abatement Measures Technical Support Document might not be additive because many of the identified heat rate improvements will have overlapping effects. As noted in section 2.5 of the final `GHG Mitigation Measures' TSD, the EPA generally agrees with this point but does not agree that it improperly characterized or misused information from the cited studies (specifically the Sargent & Lundy study  -  "Coal-fired Power Plant Heat Rate Reductions", Sargent & Lundy LLC, January 2009. Available at http://www.epa.gov/airmarkets/documents/ipm/coalfired.pdf). Specific responses to commenter's criticisms of the EPA's statistical analysis are provided in Chapter 2 of the `GHG Mitigation Measures' TSD.
Commenter 0146 stated that although EPA has said that its proposed NSPS can be met through a combination of best operating practices and equipment upgrades, the rulemaking docket is utterly devoid of any TSD that provides any support for that assertion. The commenter stated that the Agency has completely failed to analyze whether its proposed standard is achievable for the units to which it would apply and has violated its obligation under section 111 to propose standards of performance that are achievable. The commenter stated that, more fundamentally, EPA has violated its obligation under section 307(d) of the CAA to provide the basis and purpose for the proposal, which is to include a summary of (A) the factual data on which the proposed rule is based; (B) the methodology used in obtaining the data and in analyzing the data; and (C) the major legal interpretations and policy considerations underlying the proposed rule. The commenter stated that, of particular note, the docket fails to include the annual historical operating performance for each affected facility using historical CO2 emissions data for the calendar years 2002 through the present that the Agency refers to in proposed section 60.46Da(c)(3)(i)(A) and that without such data, regulated EGUs cannot determine what numerical emission limits they would potentially be subject to upon modification, and cannot meaningfully comment on the proposed NSPS. The commenter stated that also missing from the docket are any EPA calculations using its proposed methodology and any estimates by the Agency of the range of emission limits that modified Subpart Da units might be expected to achieve; without such calculations, which logically would have been included in the TSD that is absent from the docket, EPA cannot have conducted a reasonable inquiry into whether those limits are achievable. According to the commenter, this is an egregious failure to comply with section 307(d)(3) and will render any final rule unlawful. Commenter 0146 stated that the EPA does not provide data and analysis to support its proposal for modified Subpart Da EGUs although the Agency does generally refer to theoretical information from its Proposed Existing Source Guidelines rulemaking for existing EGUs. The commenter stated that the EPA's analysis to determine opportunities for heat rate improvement (a total of 6 percent improvement, on average, from best operating practices and equipment upgrades) in the U.S. coal-fired utility power fleet does not explain how that analysis supports its claim that individual modified Subpart Da EGUs can consistently replicate their "best demonstrated historical performance with an additional 2 percent emission reduction. The commenter stated that the document EPA references (which was prepared to support the building block 1 analysis for its proposed Existing Source Guidelines) outlined emission requirements for existing EGUs that are radically different in form, applicability, and stringency from those proposed here, and it cannot reasonably be read to support EPA's claims regarding what emission-improving measures are available for individual modified Subpart Da units.
Claims that the rulemaking docket is "utterly devoid of any TSD that provides any support" for the proposed standard is completely false. At numerous times in the proposal, the EPA points to Chapter 2 `GHG Abatement Measures' TSD, which was placed in the rulemaking docket. Commenters also note that "the docket fails to include the annual historical operating performance for each affected facility using historical CO2 emissions data for the calendar years 2002 ...  and, that without such data, regulated EGUs cannot determine what numerical emission limits they would potentially be subject to upon modification, and cannot meaningfully comment on the proposed NSPS." The EPA disagrees. The regulated EGUs have been reporting numerical emissions data to the EPA under 40 CFR part 75 for some time and the CAMD data is commonly understood to be the best, most reliable, most complete data source to the industry. The proposal `GHG Abatement Measures' TSD was explicit about the source of the data noting "The EPA performed this study using hourly heat input (Btu), and electricity output (MWh) data from the Clean Air Markets Division" (p. 2-16 of the proposal TSD, EPA-HQ-OAR-2013-0603-0005). These data were included in the docket.
Commenter 0146 stated that the conclusions in the GHG Abatement Measures TSD that EPA cites are flawed and do not support the Agency's claims regarding potential heat rate improvements, either in the proposed NSPS for modified Subpart Da units or in the Proposed Existing Source Guidelines. The commenter stated that EPA's analysis does not consider certain limitations on the heat rate improvements available at any individual EGU including the fact that the availability and benefits of efficiency-improving measures are highly site-specific and that many EGUs have already implemented at least some of the measures EPA identifies, meaning that their associated benefits are already accounted for in a unit's historical emissions performance. The commenter stated that many of the efficiency improvements are temporal and 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 measure over its expected lifetime. The commenter stated that heat rate-improving actions are not additive, as EPA assumed.
The EPA proposed and is finalizing that the standards for affected modified steam generating EGUs can be met through unit efficiency improvements achievable through a combination of best operating practices and equipment upgrades. The commenter notes that benefits of efficiency-improving measures are highly site-specific and that many EGUs have already implemented at least some of the measures EPA identifies, meaning that their associated benefits are already accounted for in a unit's historical emissions performance. The EPA largely agrees  -  which is why the final standard of performance for affected modified steam generating EGUs is unit-specific and will depend upon that unit's own best potential performance  -  inherently taking into account its site-specific conditions. The EPA further notes that units can also utilize natural gas co-firing as an alternative means of meeting the final standard of performance. Moreover, sources undertaking projects can take steps to avoid triggering modification, such as measures to avoid increasing their emissions of pollutants.
 
Commenter 0178 stated that the data used for development of the existing source standards is not applicable to modified sources and should not be used. The commenter stated that any requirements associated with heat rate improvement in general are dependent on the original design of the unit and heat rate and the impact of heat rate improvements will vary along the load curve for each generation unit. The commenter stated that production at partial loads requires the majority of plant equipment to operate below design, or most efficient levels. The commenter stated that improvements that result in reducing heat rate at a high load point may result in marginal improvement or higher heat rates at a lower load point; thus, the average heat rate improvement will be less than the heat rate reported at the high load point depending on the unit capacity factors. 
The EPA disagrees the data used for development of the existing source standards is not applicable to modified sources and should not be used. Modified sources are existing sources that have undertaken modification (as defined in 40 CFR 60.14) and thus it is very appropriate to use existing source data.  Further, 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. We do not have sufficient information at this time, however, to anticipate the types of modifications, if any, that may result from these changes ... nor are we able to anticipate the types of units that may modify. 
Commenter 0178 stated that almost all forms of heat rate improvement will degrade over time, requiring ongoing maintenance efforts to return the unit to near design conditions. The commenter stated that opportunities to incorporate heat rate improvements at one load point are rare and are even less likely to carry that level of improvement across the load curve. The commenter stated that a significant driver of average heat rate is the capacity factor of a unit, and is unlikely that an average heat rate improvement could be achieved and sustained on coal units that may be dispatched at reduced load points in the future in order to meet an emission reduction goal, or because of increased utilization of NGCC units or increased renewable generation.
 Yes, the standards may require ongoing maintenance efforts to sure that the unit operates according to its best potential performance.
Commenter 0156 stated that it does not appear that EPA adequately considered the factors identified above that would impact the ability of a modified unit to meet the proposed performance standard. The commenter requests that EPA withdraw the proposed rule so that it can conduct a more detailed analysis of the CO2 emissions from all supercritical boilers and other efficient subcritical units and review the GHG BACT determinations that have been made to date; the EPA can then propose a performance standard that will be able to be met by modified units across a variety of potential operating scenarios. 
The final standards for affected modified steam generating EGUs (i.e., those conducting modifications resulting in an increase of hourly CO2 emissions of more than 10 percent) are achievable. Since the final standard is based on the modified unit's own historical performance, the standard represents an emission rate that the affected unit has already achieved. Sources have other options other than heat rate improvements to meet the final standards.  For example, sources can use natural gas co-firing as a way to meet the final standards. Moreover, sources undertaking projects can take steps to avoid triggering modification, such as measures to avoid increasing their emissions of pollutants.
Commenter 0156 stated that the CO2 emission rate for these units may decrease a bit at higher capacity factors, but an emission rate of 1,900 lbs CO2/MWh-net is not likely achievable on an annual basis. The commenter stated that in their experience, the dispatch of units is highly variable and the capacity factor of a unit affects the unit's heat rate, and correspondingly, its CO2 emission rate. The commenter stated that even the most efficiently designed unit cannot operate consistently at the capacity factor necessary to reduce its CO2 emission rate to the level in the proposed rule. The commenter stated that for efficiently designed and maintained units, like the ERGS units, there may be no additional economically reasonable actions that can be taken to further reduce an already low CO2 emission rate an additional 2 percent on an annual basis; if efficiency improvements had a reasonable rate of return, they likely have already been implemented. 
This comment involves the achievability of the final standards for reconstructed sources. First, as the EPA has noted numerous times, we are only aware of 1 EGU that has triggered the reconstructed standards and, as such, we expect very few, if any, units to do so in the future. Still, if a unit does trigger the reconstruction provisions (see 40 CRF 60.15), it would be the result of expending a very large amount of capital (more than 50 % of that needed to replace the unit with a new unit  -  and these are not cumulative expenses, but rather, from a single reconstruction investment). It is certainly reasonable for a reconstructed unit to meet the emission of the best performing generation available, which for larger units is 1,800 lb/MWh-g and for smaller subcritical units is 2,000 lb/MWh-g.  
Commenter 0214 stated that the EPA has justified the technical feasibility of equipment upgrades for modified boilers and IGCC units based on one fuel type - coal - and primarily on one technology - pulverized coal combustion; although EPA's BSER determination is applicable to the entire subpart Da source category. The commenter stated that the EPA has not provided sufficient evidence of the technical feasibility of equipment upgrades for all subpart Da sources. The EPA's acknowledgement that equipment upgrades may not be appropriate at every existing coal-fired EGU facility in the U.S. contradicts its BSER determination for coal-fired units while further eroding any justification for the equipment upgrades EPA cites as BSER for other subpart Da sources.
While all available equipment upgrades may not be available or appropriate for all types of utility boilers, the final standards are nonetheless achievable at all utility boilers and IGCC units. The standard is based on the affected unit's own historical performance  -  and thus the affected unit has already demonstrated that it can achieve the final standard.
Several commenters (0183, 0242, 0249, 0284) stated that the EPA recognizes that many units will already have made equipment upgrades and implemented the best operating practices that this standard contemplates and that, as a result, the EPA is concerned that some sources would be unable to undertake additional improvements to meet the highest level of efficiency plus the additional 2 percent reduction (based on equipment upgrades) being considered. Commenter 0183 stated that this concern should extend to EGUs that undertake efficiency improvements for any reason - whether to comply with a section 111(d) plan or for some other purpose - no matter when they are undertaken. Commenter 0284 stated that the level of additional emission reductions that can be obtained from a source undergoing a modification can only be determined on a case-by-case basis, depending on: (1) the current level of heat-rate efficiency at which the unit operates; (2) the nature of the modification being undertaken; (3) the nature of previous modifications made and the emission reductions achieved during such earlier modifications; (4) the cost and burden of obtaining additional emission reductions relative to the amount of additional emission reductions achievable; and (5) the effect of such additional reduction-related requirements on the continuing ability of the unit to provide a reliable source of power. The commenter stated that rather than specifying across-the-board numeric emission reduction goal to be obtained by EGUs undertaking a modification, EPA should instead adopt a standard that allows for a determination, on a case-by-case basis, of what emission reductions are possible and reasonable after consideration of the above five factors. Commenter 0242 stated that an additional 2 percent improvement is not appropriate because it would dramatically increase costs on the most efficient facilities as they invest more heavily to achieve a new 2 percent theoretical improvement target; in a deregulated market, like Ohio, these units become less likely to "clear" the capacity market and could have the effect of older, less efficient units that have not been upgraded being used more than the newly modified more efficient reconstructed units.
Commenter 0222 stated that a proper analysis would have shown that the proposed 2 percent reduction is not feasible, particularly in deregulated markets. The commenter stated that Texas' deregulated electricity market is extremely competitive, and the market demands that operators operate at peak efficiency and with the best operating practices; there is simply no ability to leave any potential megawatt-hours on the table, rather than putting that energy into the market for sale. The commenter stated that the types of "best operating practices and equipment upgrades" contemplated by EPA have already been made by Texas EGUs.
Commenter 0183 stated that they have implemented all projects that are technically practical, economical, and would not otherwise trigger additional federal permitting requirements in response to competitive market incentives and believes that other utilities in competitive markets have done the same. The commenter stated that within that set of projects, some are temporary, and the improvements degrade over time and others that have already been accomplished cannot be repeated for additional improvement; in sum, the achievable heat rate improvements on which EPA relies have already been implemented. The commenter stated that for these reasons, EPA's targeted emission (or heat rate) improvement of 2 percent beyond a historically low emission rate is unachievable and arbitrary. According to the commenter, EPA correctly identifies the types of upgrades that can be made to improve heat rate and is correct that these types of projects and others are routine at EGUs; the commenter stated that EPA misapplies that fact to justify its proposal.
Commenter 0204stated that it is inappropriate to apply the 2 percent additional emission reduction as EPA proposes for sources that have already implemented aggressive measures to improve operating efficiency. The commenter stated that EGUs in Wisconsin already implement equipment upgrades (including periodic overhauls) on a regular basis to return efficiency to near original heat rates. The commenter stated that the EPA should also recognize that new plants, particularly supercritical units such as Elm Road 1 and 2 and Weston 4 in Wisconsin, will likely not be able to improve their heat rates. 
The EPA is not finalizing the additional 2 percent emission reduction suggested in the proposal.
Commenter 0204 stated that as part of our review of EPA's concurrent 111(d) proposal for existing sources we performed an initial review of EPA's assumed HRI actions with many Wisconsin EGU operators. According to the commenter all of these utilities have operating and administrative programs in place to constantly maintain and improve coal-fired EGU heat rates. As part of their submission, the commenter provided a summary table of their review as an appendix. The commenter stated that the EGUs listed in the appendix generated approximately 95 percent of the electricity generated by the Wisconsin coal-fired EGU fleet in 2012. The commenter stated that the table contains the HRI actions that EPA associates with equipment improvements - turbine overhaul/maintenance, flue gas system improvements, economizer replacement, and acid dew point control. Referring to the table, the commenter stated that most EGUs in Wisconsin have already undertaken these improvements, if appropriate; this indicates that any one unit is not likely to be able to achieve EPA's assumed 2 percent HRI due to equipment improvements. The commenter stated that this also indicates that any EGU that becomes a modified source should instead be evaluated on a case-by-case basis to see what HRI equipment improvements are actually feasible at that unit, based on improvements completed to date.
The EPA is not finalizing the additional 2 percent emission reduction suggested in the proposal.
Commenter 0178 stated that emission control systems that have been installed or are expected to be installed will reduce heat rates (degrade) by approximately 1.5 percent to 1.75 percent. Each of the commenter's units has been subject to asset life cycle management based on maintaining unit performance for the duration of operation required to satisfy their generation needs. The commenter stated that major equipment for each unit is covered by a life cycle management which optimizes performance and expenses within the rate structure; overall, they had been very successful at maintaining performance of generation assets without material impacts to electric rates. The commenter stated that by virtue of this success the argument can be brought forth that improvements in O&M will be hard pressed to result in significant improvement in heat rate above current performance levels. 
Commenter 0178 stated that they are currently in the process of installing the ReACT emission control system on Weston Unit 3. Once the ReACT system is installed the commenter stated that they expect a 3.2 percent increase in full load heat rate for this unit; this degradation in heat rate compared to the existing EPA baseline creates additional concern regarding the treatment this unit will receive under this regulation.
Commenter 0263 stated that several EGUs in Wyoming have recently completed extensive turbine upgrades, which are recognized as the most effective way to increase energy efficiency; for example, beginning in 2007 authorizations were issued to PacifiCorp Energy and Basin Electric Power Cooperative for turbine upgrades at their Jim Bridger and Laramie River Station facilities, respectively. The commenter stated that most of these upgrades have been completed and an expectation that either Jim Bridger or Laramie River Station could automatically introduce a further 2 percent reduction in CO2 emissions from its best performing year since 2002 is unreasonable, even more so when considering the requirements that are proposed for 111(d).
The EPA is not finalizing the additional 2 percent emission reduction that was proposed. 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.
Commenter 0215 stated EPA did not provide any analysis to support the conclusion that NSPS can be met through a combination of best operating practices and equipment upgrades. Commenter said this violates section 307(d)(3) of the CAA. 
The EPA disagrees. The information provided in the GHG Abatement Measures Technical Support Document provided ample support for the proposed standards. The analysis 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), 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 modified units also have the option of meeting the final standard of performance through the use of natural gas co-firing.
Commenter 0242 stated that there has to be flexibility for states to determine the best rate that is economically and technically feasible for facilities that reconstruct or modify. The commenter stated that EPA suggests, as an example, a circumstance where "aggressive" measures were taken recently to improve efficiency. The commenter requested clarification on the term "aggressive". The commenter also urged the EPA to review the 2011 EPRI study, "Cycling and Load Following Effects on Heat Rate, 2011," which details the incorporation of "heat rate initiatives" at the unit examined in the study, including increased training of operators, enhanced coal sampling and analysis techniques, and excess air management measures. The commenter stated that the unit was able to manage and improve the initial heat rate degradation of 2.3percent to less than 1percent; however, these measures could not overcome the full impacts of cycling on the unit's heat rate. The commenter stated that they consider the measures taken in the above study to be extensive and aggressive, despite the modest heat rate improvement resulting from these efforts. The commenter urged the EPA to avoid vague terms such as "aggressive" when describing heat rate improvement measures, and to consider recognized past efficiency improvement measures when determining what additional measures a particular unit may implement.
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.
Commenter 0231 stated that it is unreasonable for EPA to assume that any specific level of emission reduction can be achieved across the board by EGUs that undertake a modification; the level of additional emission reductions, if any, that can be obtained from a source undergoing a modification can only be determined on a case-by-case basis. The commenter recommended that rather than specifying any across-the-board numeric emission reduction goal to be obtained by EGUs undertaking a modification, EPA should instead adopt a standard that allows for a determination, on a case-by-case basis, of what emission reductions are possible and reasonable after consideration of site-specific factors. 
The final standards for affected modified steam generating EGUs is determined on a case-by-case basis.  The final standards are determined by the affected EGU's own best potential performance.
Commenter 0231 stated that they are concerned that where a state imposes efficiency improvements on a source, or where a source undertakes efficiency improvements to comply with the state plan, it will have already attained the maximum level of efficiency improvement that is achievable for that unit; as a result, the source would be unable to undertake additional improvements to meet the highest level of efficiency plus the additional 2 percent reduction. 
Commenter 0256 stated that, under the proposed approach whereby efficiency improvements constitute a system of emissions reductions, the standard should not apply numerical CO2 limits to a modified or reconstructed unit, whether the numerical limit is given in the standard or based on historical operation. The commenter stated that the idea that a generating unit could achieve a 2 percent emission reduction through energy efficiency measures makes little sense for most units as any economically beneficial efficiency improvement would have already been implemented. The commenter stated that for years the EPA has pursued enforcement action against utilities for conducting routine maintenance, repair, and replacement projects under the claim that they would result in efficiency improvements and therefore constitute NSR modifications and it now appears that EPA is proposing to implement a rule that may require review and additional controls under a different regulation. And, according to the commenter, any controls implemented under NSR would most likely cause an increase in the CO2 emission rate for the unit, not allowing the unit to meet the proposed NSPS CO2 standard.
The EPA is not finalizing the additional 2 percent emission reduction that was proposed. 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.
Most stringent limits 
Commenter 0183 stated that EPA is soliciting comments on whether the heat-input based most stringent emission limits of 1,900 lbs CO2/MWh and 2,100 lbs CO2/MWh should take into account the current steam cycle of the facility. The commenter stated that the EPA erred in setting the lower limit for all modified units (of all fuel types) at a level established with reference to the operation of a supercritical steam generating unit burning subbituminous coal. The commenter stated that the limits cannot be extrapolated to all units, regardless of fuel type. The commenter stated that EPA assumes that lignite-fueled sources can meet this limit by using ultra-supercritical steam conditions, but provides no explanation as to why the emission limit should be transferrable between units using different types of fuel. The commenter stated that the EPA also fails to acknowledge the impossibility of operating a supercritical unit as an ultra-supercritical unit to achieve the emission limit. The commenter stated that based on their experience with coal-fueled units, particularly while firing lignite fuel, no amount of efficiency improvement projects, operational changes, or maintenance would allow a unit designed and built to operate as a subcritical or supercritical unit to operate with the efficiency and process conditions of an ultra-supercritical unit and at an emission rate of 1,900 lbs CO2/MWh. The commenter stated that the proposed numerical standard, based on a unit burning subbituminous coal, is not achievable by lignite-fueled boilers, regardless of the type of boiler.
Commenter 0142 stated that, regarding EPA's solicitation of comments on whether the most stringent standard for modified steam generating units should take into account the current steam cycle of the facility, the existing steam cycle should be considered only in understanding realistic limits for modified units in establishing standards. The commenter stated that, specifically, the EPA should not propose standards based upon one type of unit and then require a completely different type of unit to comply with those standards. The commenter stated that the difference in efficiency resulting from different steam cycles is inherent in the design and construction of the unit; no matter the adjustments made, a subcritical unit cannot approach the efficiency of a supercritical boiler. The commenter stated that modifications tend to be more incremental adjustments to a unit's design than a complete unit redesign that would be required to convert a subcritical unit to a supercritical unit. For these reasons, the commenter stated that they not believe that the EPA's proposed unit-specific 1,900 lb CO2/MWh-net standards are appropriate BSER for subcritical units. 
The EPA points out that triggering the reconstruction provision is a significant economic hurdle  -  and it has only rarely been done. Per 40 CFR 60.15  -  `Reconstruction' means the replacement of components of an existing facility to such an extent that: (1) the fixed capital cost of the new components exceeds 50 percent of the fixed capital cost that would be required to construct a comparable entirely new facility, and (2) it is technologically and economically feasible to meet the applicable standards set forth in this part. The 50% of fixed capital cost that would be required to construct an entirely new EGU would almost certainly involve significant  -  and very costly investment (if not entire replacement of) the boiler. At that time, conversion from a subcritical boiler to a supercritical boiler can be done [or complete replacement with a new supercritical boiler]. However, if the owner/operator can show it is not "technologically and economically feasible to meet the applicable standards set forth in this part", then it would not trigger the reconstruction provisions. The EPA points out here  -  and in the preamble in section VII  -  that owners/operators can also consider the use of natural gas co-firing to achieve the final emission limitation without the need to convert the subcritical boiler to supercritical. Natural gas co-firing has long been recognized as an option for coal-fired boilers to reduce air emissions of criteria and hazardous air pollutants.
Commenter 0204 disagreed with the proposed "most stringent" standard for modified units, which accounts only for the size of a unit; instead, they agree with the alternative option that the "most stringent" standard should also take into account the current steam cycle of the facility. Commenter said this is based on the BSER limit that EPA proposes for a reconstructed fossil fuel-fired boiler, which EPA determined based on their review of emission rate information submitted by owners/operators of coal-fired EGUs to EPA's CAMD. The commenter stated that under this alternative option, EPA first suggests an emission standard for supercritical boilers of 1,900 lb CO2/MWh-net for units with a heat input rating of greater than 2,000 MMBtu/h; EPA then suggests a higher (i.e., less stringent) standard for all modified subcritical sources and for modified supercritical sources of 2,100 lb CO2/MWh-net with a heat input rating of 2,000 MMBtu/h or less. The commenter agrees with this alternative option, with an exception: the 1,900 lb CO2/MWh-net standard for supercritical units with a heat input rating of greater than 2,000 MMBtu/h is too stringent. 
Commenter 0178 stated that, regarding EPA's soliciting comment on whether the most stringent standard for modified steam generating units should take into account the current steam cycle of the facility, they agree that the current steam cycle of the facility should be taken into account. The commenter stated that because of the design differences between subcritical and supercritical units, it is not reasonable to subject a subcritical unit to standards based on supercritical unit performance. The commenter stated that EPA has asserted that reconstructed units must use the most efficient generation technology available regardless of the original design of the unit prior to the reconstruction; because EPA goes further by identifying that supercritical pulverized coal or a supercritical circulating fluidized bed boiler technology represents the most efficient generation technology, the requirements would dictate that a unit without this design initially would be required to achieve the efficiencies from these advanced boiler designs. The commenter stated that a subcritical boiler can't achieve supercritical performance without essentially requiring that the unit is rebuilt nearly in its entirety. The commenter stated that the EPA analysis requires not only alteration of the boiler and steam cycle but also requires units to use different coal and install different cooling systems; these assumptions regarding the feasibility of making these wholesale changes to a unit are unsupportable and have the effect of making reconstruction impossible. The commenter stated that extra energy is required to move a unit from low to higher loads to overcome inertia in the system and the more frequently a unit must move up and down the load curve, the more excess energy will be required to produce the desired load and, thus, the unit will be less efficient on average thereby resulting in a degraded overall heat rate. The commenter stated that because the proposed Clean Power Plan is expected to impact heat rates in this manner, EPA should finalize higher standards for modified and reconstructed sources. 
The EPA finds the final standards of performance for both affected modified steam generating EGUs and for reconstructed EGUs to be appropriately stringent as discussed in preamble sections VI and VII.
Commenter 0231 stated that EPA's alternative to the 2 percent better than the best historical performance, an emission standard no more stringent than the corresponding standard for reconstructed EGUs is unreasonable because it assumes that all coal-fired EGUs can obtain the level of emissions achievable by a facility undergoing a complete reconstruction, even if those EGUs have already undertaken the equipment upgrades and implemented the best operating practices contemplated by the standard.  
Commenters 0154, 0204 stated that EPA should evaluate emission rates that modern units are actually achieving. Commenters referred to the Elm Road Generating Station (ERGS) in Wisconsin that is powered by supercritical boilers firing bituminous and sub-bituminous coal, began operation in 2010 and is one of the most modern and efficient coal fired power plants operating in the country. Commenters said based on available data, this proposed emission rate isn't achievable on these units, let alone sustainable across a range of capacity factors or as the heat rate efficiency degrades between maintenance activities. The commenters stated that the Elm Road plant is only demonstrating a CO2 emission rate of 2,061 lb/MWh-net. This was based on 2014 CAMD operating data for Elm Road, which operated at a 63% capacity factor during this period. The commenters stated that based on this example, EPA needs to reevaluate the proposed "most stringent" limits for supercritical coal-fired units.
Commenter 0291 stated EPA recognized that many (if not most) units will already have undertaken the equipment upgrades and best operating practices that this standard contemplates, and offers what it sees as a limitation, that modified facilities would not have to meet an emission standard more stringent than the corresponding standard for reconstructed. EPA assumes that all coal-fired EGUs can obtain the level of emissions achievable by a facility undergoing a complete reconstruction, even if those EGUs have already undertaken the equipment upgrades and implemented the best operating practices contemplated by the standard. Commenter believed that EPA tacitly admits the unreasonableness of their proposal in text relating to a unit's implications with 111(d) state plan implementation. The EPA showed concern over a unit's ability to achieve an additional 2% efficiency improvement, as the unit may have already attained the maximum level of efficiency improvement achievable. Commenter said this concern should extend to EGUs that undertake efficiency improvements for any reasons, not just compliance with 111(d).
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 return, on average, 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.
EPA's suggested equipment upgrades are not part of the affected unit.
Commenter 0215 stated that many of the operating practices and equipment upgrades that EPA asserts will improve the heat rate at a Subpart Da unit are not part of the affected facility, and EPA lacks authority to regulate them under section 111(b). Moreover, EPA has exaggerated the short-term and long-term benefits of the heat rate improvement methods described in the Proposed Standards by relying on flawed analyses and unverified assumptions. Commenter said the affected facility is limited to the boiler island. See commenter's attached Rasnic Memorandum. The following equipment is specifically beyond the purview of section 111(b): water purification equipment; water-supply systems; air cleaning and cooling apparatus; condensers; main exhaust and main steam piping; water screens, motors, and moisture separator for turbine steam.
Commenter 0187 disagreed that a modified Subpart Da EGU could achieve an emission rate determined by the unit's best annual performance, plus an additional two percent efficiency improvement. The commenter stated that: the affected facility is limited to the steam boiler unit; many of the practices and equipment upgrades suggested by the EPA are not part of the affected steam boiler unit; and the EPA lacks authority to require them. The commenter stated that other auxiliary equipment, such as condensers, main exhaust and main steam piping, and moisture separators are not directly a part of the steam boiler and, therefore, cannot be relied upon pursuant to 111(b) for EGU efficiency improvements.
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. Regarding comments about what is the affected facility  -  the EPA is not regulating any emissions from the facility components listed, nor is the EPA requiring in any way that the affected modified EGU conduct specific actions. The owner/operator is free to meet the final standard in the way that is best for the facility. For example, an affected modified EGU can meet the final standard through the use of natural gas co-firing.
Past HRI not a demonstration of possible future HRI 
Commenter 0153 stated that EPA's analysis of past heat rate improvements at existing EGUs does not demonstrate that future heat rate improvements can be performed to reduce CO2 emissions. According to the commenter, the remaining available plant efficiency improvement for EGUs is closer to 1 percent and the proposed Clean Power Plan will force those improvements to be made.
Commenter 0278 stated that the six percent heat rate improvement EPA proposes as Building Block 1 is unachievable for existing fossil fuel-fired EGUs and without adequate technical justification and the proposed modified unit rates assume heat rate improvements beyond Building Block 1's six percent. The commenter stated that EPA provides no justification or technical support for this assumption and there simply are not efficiency projects that EGUs can perform to achieve a six percent improvement in heat rate. The commenter stated that the fact that EPA's analysis of past heat rate improvements at existing EGUs has shown that EGUs work to improve heat rates, does not demonstrate that future heat rate improvements can be performed to reduce CO2 emissions; the remaining available plant efficiency improvement for EGUs is closer to 1 percent, and the proposed Clean Power Plan will force those improvements to be made.
Commenter 0257 stated that the assumption that a unit can feasibly replicate its lowest heat rate since 2002 is questionable, 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; for example, the installation of scrubbers, selective catalytic reduction 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 retrofit may increase auxiliary power by 1-2 percent, depending on coal type. The commenter stated that since 2002, about 140,000 MW of SCR and 120,000 MW of FGD have been installed on EGUs and they have installed seven of their eight SCRs and four of their seven wet scrubbers post 2002.
Comments specifically on provisions of the Clean Power Plan (111(d)) are out-of-scope for this Response-to-Comments and will not be responded to. 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. Regarding comments about factors beyond the plant operator's control, Section 2.5 of Chapter 2 of the `GHG Mitigation Measures' TSD explains how EPA controlled for several of those factors. 
Inappropriate reliance on 2009 Sargent & Lundy report 
Several commenters (0157, 0183, 0187, 0199, 0214, 0215, 0242, 0257, 0278) stated that EPA's reliance on the 2009 Sargent and Lundy report, to determine the type and degree of heat rate improvements that are possible to be achieved nationwide is not appropriate.
Commenter 0215 stated that the GHG Abatement Measures TSD relies heavily on a 2009 Sargent & Lundy study purportedly showing that existing EGUs are "theoretically capable" of achieving sufficient heat rate improvements to comply with the Proposed Guidelines and EPA's statistical analysis of data from existing Subpart Da EGUs. Commenter attached technical reports discounting EPA's analysis in the GHG Abatement Measures TSD, showing the analysis to be deeply flawed, and not supporting the Agency's claims regarding potential heat rate improvements, either in the Proposed Guidelines under section 111(d) or in the Proposed Standards for modified Subpart Da EGUs. See Cichanowicz Heat Rate Report; J. Edward Cichanowicz & Michael C. Hein, "Critique of EPA's Use of Reference Units to Select Heat Rate Reduction Targets" (Oct. 13, 2014).
Commenter 0215 stated EPA relies on a 2009 Sargent & Lundy study that they misused. Commenter noted that Sargent & Lundy has responded that it did not conclude that any individual coal-fired EGU, or any aggregation of coal-fired EGUs, can achieve the 6 percent heat rate reductions that are a primary basis of EPA's proposal.
Commenter 0242 stated that the EPA's use of one study, the S&L study, to determine the type and degree of heat rate improvements that are possible to be achieved nationwide is not sound science. After reviewing the S&L study, the commenter determined that the purpose was to examine potential heat rate improvement opportunities and potential heat rate reductions over a wide range of sources and that the methodology and results of the study are very general and cannot be applied to every EGU. The commenter stated that the study does not present an analysis of the application of the recommended improvement opportunities, nor does the study present measured heat rate reductions after the application of suggested/proposed improvement methods and there is no empirical data demonstrating the real-world application of such measures; such an undertaking was simply not the purpose of the study. The commenter stated that the use of the S&L study as a foundation for demonstrated HRIs is an over-simplification of the complexities and variability in power plant design and function. The commenter stated that in many cases, the potential projects referenced for HRIs are not functionally applicable to specific units; for example, replacing economizers for better performance could cause additional problems such as: fouling issues can arise in finned tube designs depending on type of coal used; corrosion, ash deposition and increased use of preheaters are needed for reduced exit temperatures which increase heat-rate; and lower temperatures sent to SCRs can sacrifice SCR efficiency.
Commenter 0242 stated that the S&L study alone was used to estimate the ability for sources to achieve HRIs through equipment upgrades. The commenter stated that the EPA used the estimated ranges of potential heat rate improvement achievable through a variety of equipment upgrades from the S&L study, which were screened into a subset to identify what the EPA considers to be a reasonable subset of equipment upgrades that would generally be beyond the scope of investments they would expect to be made for purposes of achieving the best-practices heat rate improvements. The commenter stated that based on the average of the study's ranges of potential HRIs from implementation of this full subset of HRIs, it is expected any single EGU could achieve an aggregate HRI of 4 percent from equipment upgrades alone. The commenter stated that, because EPA recognized that this may overstate the opportunity across all EGUs where some EGUs may have already implemented some of these upgrades, the EPA therefore proposed on average across the fleet of affected EGUs, the technical potential for a 2 percent HRI improvement opportunity due to equipment upgrades (modification). The commenter stated that they disagree with this assessment stating that the EPA did not perform any analysis to determine if there is a true technical potential of 2 percent HRI from equipment upgrades that is cost-effective for each individual EGU; the EPA is assuming technical potential at each individual unit based on using an assumed average from one inappropriately applied study.
Commenter 0242 stated that the EPA acknowledges that the S&L study's wide ranges of estimated BTU reductions and capital costs are indicative of the wide range of real differences in the many details of site specific EGU designs, fuel types, age, size, ambient conditions, current physical conditions, etc.; yet, the EPA chose to use an average to determine the level of the standard. The commenter stated that considering unit-specific data is being used to determine a best historical performance rate and the EPA is requesting an additional 2 percent reduction, there may be some units that will not be able to achieve this if these units are on the wrong end of the wide ranges.
Commenter 0157 stated that EPA uses the Sargent & Lundy study to support a 4% heat rate improvement if all improvements were applied on an EGU that has not made those upgrades. The commenter stated that given the study is five years old and is based on data even older, it is not realistic to assume that every regulated EGU has not already made some of those upgrades. The commenter stated that promulgating a uniform standard based on an assumption that is not uniform is arbitrary; if an EGU had already undertaken numerous efficiency improvements, it would nonetheless be penalized under EPA's proposal for making improvements early. The commenter stated that the standard would be even lower for such a unit, and potentially unattainable; on other hand, a unit that has made no improvements could comply more easily. The commenter stated that EPA's approach in this proposal punishes those who acted early, before they were required to do so.
Several commenters (0278, 0153) stated that EPA relies on a 2009 Sargent & Lundy (S&L) study that was never intended to predict the technical feasibility of a six percent heat rate improvement across the entire fleet of fossil fuel-fired EGUs. The commenters stated that in a October 15, 2014 letter to Rae Cronmiller at NRECA (the commenters attached the letter to their submittal), S&L clarified that the 2009 Report does not conclude that any individual coal-fired EGU or any aggregation of coal-fired EGUs can achieve 6 percent HRI or any broad target, as estimated by the EPA and that the only technically appropriate method to properly evaluate potential HRI is to conduct a unit-by-unit evaluation. The commenters stated that EPA's reliance on the S&L study cannot form the technical basis for its modification rule BSER finding. The commenters stated that S&L also notes that many of the options for HRI listed in the 2009 Report have triggered NSR actions by EPA and others. The commenters stated that EPA provides no NSR relief in the proposal and suggested that EPA clarify that all of these HRI projects should be treated as routine maintenance, repair and replacement. The commenters stated that if the projects are also evaluated to determine whether there is a reasonable possibility that they will result in a significant emissions increase, a potential NSR carve out would be for the NSPS emissions rate test to apply; this test is only triggered by increases in the maximum achievable emissions rate before and after the physical change.
Commenter 0199 stated that since their report's publication in 2009, Sargent & Lundy have performed unit-specific HRI potential studies and has yet to encounter a single unit that can achieve a six percent HRI; a more realistic figure is a 2 percent HRI or less, realizing that all units will experience degradation over time from its initial HRI. 
Commenter 0187 stated that the projects cited in the Sargent & Lundy 2009 study over-estimate the potential heat rate improvements and the length of time they have been effective as many of the improvements are short-term and any estimate is only for a given point in time, and the effectiveness degrades over time. The commenter stated that, for example, the best year may not be representative of the entire unit's outage cycle; the unit may operate most efficiently the year after the outage and degrade until the next outage.
Commenter 0214 stated that EPA did not consider the technical feasibility of equipment upgrades across the size classes of potentially affected sources; EPA's proposal covers facilities constructed for the purpose of supplying more than one-third of its potential electric output and more than 219,000 MWh as net-electric sales on an annual basis. The commenter stated that the EPA, in establishing equipment upgrades as BSER, referenced studies that removed units with capacity factors under 50 percent, low pressure subcritical units, and 0 to 200 MW subbituminous units. The commenter stated that by eliminating certain units, these studies do not justify the technical feasibility of equipment upgrades at all potentially affected size classes. The commenter stated that EPA relies heavily, if not exclusively, on a 2009 Sargent & Lundy study that only analyzed three sizes of coal-fired power plants - 200 MW, 500 MW, and 900 MW. The commenter stated that the report fails to analyze the technical feasibility of equipment upgrades at all potential affected size classes. The commenter stated that the EPA must provide information that directly proves equipment upgrades are technically feasible for all potentially affected subpart Da sources.
Commenter 0214 stated that the EPA's exclusive reliance on the 2009 Sargent & Lundy report to justify the achievability of a two percent net CO2 emission rate reduction is misplaced. The commenter stated that the potential four percent heat rate improvement EPA used (based on four upgrade methods, if all were applied on an EGU that had not already made such upgrades, which was then adjusted to two percent to account for unknown details of current actual unit configurations), could be zero if a unit has already implemented them. The commenter stated that EPA, however, dismisses this possibility while providing no basis for its arbitrary conclusion. The commenter stated that the Agency also ignores Sargent & Lundy's 850 MW EGU case study which depicts a potential heat rate reduction lower than two percent. The commenter stated that, moreover, the 2009 Sargent & Lundy report does not provide any insight on the long-term sustainability of heat rate improvements.
Commenter 0257 stated that all of EPA's rationale is based upon extrapolations and assumptions from data EPA uses to support entirely different emission standards for existing fossil fuel-fired EGUs including a 2009 study by Sargent & Lundy regarding heat rates as the basis for its assessment of heat rate improvement potentials from equipment and system upgrades. The commenter stated that the EPA presents no independent data addressing modified utility boilers and IGCC units to support the proposed standards; missing from the docket are any calculations using the EPA's proposed methodology and its emissions database to provide the source-specific numerical standards that it would expect modified EGUs to achieve. The commenter stated that in its use of heat rates, the EPA does not appear to recognize the difficulties in their measurement that affect how applicable they are to actual emissions. The commenter stated that it has long been recognized that heat rates must be measured at a standard set of conditions to limit the number of variables that can obscure the conclusions and that these variables are in play during actual operation, with the result that the calculated heat rate does not fully correlate to emissions integrated over time; thus anticipated improvements may not be fully realized when trying to achieve permit compliance.
Commenter 0257 stated that EPA has exaggerated the short- and long-term benefits of some of the heat rate improvement methods cited in the Sargent & Lundy study. The commenter stated that many of the payoffs are temporal - for example, steam turbine blades wear with time, revised and reconfigured heat exchangers accumulate deposits, and new condensers retrofitted 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 measure over its expected lifetime, i.e., a given estimate of heat rate improvement may be merely a snapshot that changes with time. The commenter stated that EPA assumes that heat rate improving actions are additive, and 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 commenter stated that the Agency also fails to recognize that many of the actions 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.
Commenter 0183 stated that the EPA also misuses the Sargent & Lundy 2009 Study and the National Energy Technology Laboratory studies; for example, EPA wrongly extrapolates that each of the heat rate improvement methods identified by the S&L Study can be combined in practice to achieve a greater improvement, an assumption that is flawed. The commenter stated that many of the heat rate improvement methods that EPA identifies cannot be combined and are not cumulative; in other words, once the improvement is achieved by one method, another method cannot achieve the same or similar improvement. The commenter stated that, for example, Intelligent Sootblowers (S&L) would reduce the benefits realized by reducing boiler slagging (NETL); in this way and others, EPA overstates the potential for heat rate improvements. 
Commenter 0215 stated a 2014 analysis by Sargent & Lundy ("S&L") (prepared in support of NRECA's comments) is highly critical of the Agency's use of its 2009 report and concludes that EPA greatly exaggerated the amount of heat rate improvements that can realistically be expected at coal-fired EGUs. The report emphasizes many of the issues noted by this commenter's consultant, including the fact that actual benefits from many heat rate improvement methods are non-additive, temporal, and highly site-specific. Among other things, the NRECA S&L Report Study Conclusions specifically disavows EPA's use of the earlier report by stating the "Sargent & Lundy's 2009 report does not conclude that any individual coal-fired EGU or any aggregation of coal-fired EGUs can achieve 6% [heat rate improvement] or any broad target, as estimated by the EPA." Sargent & Lundy also note that the potential benefits cited in their 2009 report "were estimated at a conceptual level, and were not based on detailed site-specific analyses." These conclusions are confirmed by EPRI and the National Coal Council, a U.S. Department of Energy advisory group. See EPRI, "Range and Applicability of Heat Rate Improvements" at 5-1, 6-1 (Apr. 2014); National Coal Council, "Reliable & Resilient-The Value of Our Existing Coal Fleet: An Assessment of Measures to Improve Reliability & Efficiency While Reducing Emissions" at 69-70 (May 2014). Commenter said as a result, the 2009 Sargent & Lundy report does not support a conclusion that any individual coal-fired EGU or any aggregation of coal-fired EGUs can achieve 6% [heat rate improvement] or any broad target, as estimated by the EPA.
Responses to criticism of the use of the Sargent & Lundy study ("Coal-fired Power Plant Heat Rate Reductions", Sargent & Lundy LLC, January 2009. Available at http://www.epa.gov/airmarkets/documents/ipm/coalfired.pdf) are provided in the final Chapter 2 of the `GHG Mitigation Measures' TSD in the rulemaking docket.
Compliance will require many units to operate in a manner that will reduce their efficiency
Commenter 0187 stated that many boilers may operate in a load-following mode for at least a portion of their operation and the efficiency of a boiler decreases when the unit is operated at reduced loads. The comment included a figure showing the typical impact to efficiency when boilers are operated at reduced loads. According to the commenter, compliance with the proposed standards for existing units will require many units to operate.
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 simultaneously implementing 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. Further, an affected modified EGU can meet the final standard through the use of natural gas co-firing.
Perceived HRI actually result of CEMS reporting 
Commenter 0187 stated that in the EPA's GHG Abatement Measures TSD, EPA points to large heat rate improvements via equipment upgrades that could be replicated on other EGUs. According to the commenter, in many of the cases where EPA believed an efficiency improvement occurred, the perceived efficiency improvement was actually the result of a change in continuous emission monitoring system reporting methodology and not the result of an equipment or operational change to lower heat rate. See Critique of EPA's Use of Reference Units to Select Heat Rate Reduction Targets, J. Cichanowicz and M. Hein, October 2014. Commenter said a more accurate assessment of air flow through the stack caused the units to report an apparent improved heat rate.
Commenter 0257 stated that the EPA's discussion in the GHG Abatement Measures TSD also relies heavily on 16 reference units that purportedly achieved large heat rate improvements via equipment upgrades that EPA assumed could easily be replicated elsewhere. The commenter stated that in nearly every case, the owners stated that the reported heat rate improvement was related to a change in CEMS reporting methodology and not the result of an equipment or operational change that was undertaken to lower heat rate. The commenter stated that the actual heat rates did not improve; rather a more accurate assessment of air flow through the stack caused the units to report an apparent improved heat rate; other units did attain modest improvements in heat rate through equipment upgrades, but these improvements were more than offset by decreased unit efficiency due to retrofit of environmental controls. 
Commenter 0215 stated EPA's discussion in the GHG Abatement Measures TSD relies heavily on 16 reference units that purportedly achieved large heat rate improvements via equipment upgrades that EPA assumed could easily be replicated elsewhere. Commenter indicated that EPA didn't question the cause of the HRI, but het commenter did. In virtually every case, the owners stated that the EPA calculated heat rate improvement was due to a change in stack flow monitor calibration, or other unrelated source of variability in CEMS measurements, and not the result of an equipment or operational change that was undertaken to lower heat rate. Commenter attached documentation for this information. The actual heat rates did not improve, rather, in many cases, routine annual changes in stack gas flow monitor calibration to better equate to manual reference methods, and changes in flow methods used in flow monitor calibrations to compensate for stack flow characteristics resulted in an apparent improved heat rate. Other units did attain modest improvements in gross heat rate through equipment upgrades, but these improvements were more than offset by decreased unit efficiency due to retrofit of environmental controls, which increased the units' net heat rates. In a few cases, projects were undertaken that did improve gross heat rates, and those tended to have involved the steam turbine, which is not part of the affected facility. Commenter said these results indicate that CEMS-derived gross heat rate data are an inadequate basis for assessing modest changes in heat rate due to equipment upgrades given that reported values can vary for a number of unrelated reasons including the allowed error inherent in all CEMS measurements, stack flow monitor and other CEMS recalibrations, physical changes in flue gas handling systems, changes in CEMS and CEMS technologies, and other factors. 
Chapter 2 of the `GHG Mitigation Measures' TSD discusses the impact that relative accuracy of CEMS might have on the results (Section 2.5.1) and the impact that changes in flow measurement might have (Section 2.6.6). EPA disagrees the measurement errors and/or method changes are primarily responsible for the significant differences in heat rate performance at coal-fired EGUs. Regarding the comment about offsetting decreases in efficiency from retrofit of environmental controls, EPA's analysis, as discussed in Chapter 2 of the `GHG Mitigation Measures' TSD, is based on EGUs' gross heat rates which is not affected by auxiliary power requirements of retrofit controls. 
Measurement of heat rate improvement 
Commenter 0178 stated that an issue with the demonstration of heat rate improvement is the method by which measurement of the improvement is accomplished. The commenter stated that usually, heat rate tests are conducted using calibrated equipment; however, on-line testing would use installed equipment which is not as accurate. The commenter stated that clarity is needed regarding the demonstration of a two percent heat rate improvement because online instrumentation would have a two percent instrument error associated with heat rate measurement. 
The commenter stated that any requirements associated with heat rate improvement in general are dependent on the original design of the unit - for example, a sub-critical pressure, coal-fired Rankine cycle plant will not be able to achieve the efficiency of a natural gas combined cycle plant because of inherent physical design considerations. The commenter stated that heat rate and the impact of heat rate improvements will vary along the load curve for each generation unit. The commenter stated that production at partial loads requires the majority of plant equipment to operate below design, or most efficient levels. The commenter stated that improvements that result in reducing heat rate at a high load point may result in marginal improvement or higher heat rates at a lower load point; thus, the average heat rate improvement will be less than the heat rate reported at the high load point depending on the unit capacity factors. 
The commenter stated that almost all forms of heat rate improvement will degrade over time, requiring ongoing maintenance efforts, such as a turbine overhaul, to return the unit to near design conditions; opportunities to incorporate heat rate improvements at one load point are rare and are even less likely to carry that level of improvement across the load curve. The commenter stated that a significant driver of average heat rate is the capacity factor of a unit, and is unlikely that an average heat rate improvement could be achieved and sustained on coal units that may be dispatched at reduced load points in the future in order to meet an emission reduction goal, or because of increased utilization of NGCC units or increased renewable generation.
The commenter stated that emission control systems that have been installed or are expected to be installed will reduce heat rates (degrade) by approximately 1.5% to 1.75%. The commenter stated that each of the their units has been subject to asset life cycle management based on maintaining unit performance for the duration of operation required to satisfy their generation needs. According to the commenter, the major equipment for each unit is covered by a life cycle management which optimizes performance and expenses within the rate structure. The commenter stated that overall, they had been very successful at maintaining performance of generation assets without material impacts to electric rates. The commenter stated that by virtue of this success the argument can be brought forth that improvements in O&M will be hard pressed to result in significant improvement in heat rate above current performance levels. The commenter stated that through current maintenance practices they are already realizing the "cost effective" improvements through O&M best practices. 
Commenter 0215 stated EPA's analysis incorrectly assumes that the existence of variation in heat rate at individual units means there is significant variation in the operation of EGUs" indicating that "significant potential for heat rate improvement is available through the application of best practices, because heat rate variability at individual units is driven by the design, duty cycle, fuel type, size, and location of each unit, and it cannot be ameliorated by changes in operating practices. Commenter said EPA did not assess differences in variability based on these factors or control for these factors in its achievability analysis. Commenter continued that EPA uses the best net heat rate since 2002 as the basis for determining a required heat rate improvement. It is arbitrary and capricious to use any year prior to retrofit of energy-consuming pollution control equipment as the baseline for net heat rate. Similarly, EPA has not accounted for the impact of load duty on net heat rate or provided any technical analysis supporting this element of its proposal.
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. Regarding comments about actions to improve and maintain heat rates, Section 2.6.1 of Chapter 2 of the `GHG Mitigation Measures' TSD discusses the effect of actions undertaken by EGUs to improve and maintain heat rates during the study period, and Section 2.6.8 discusses the impact of equipment degradation.
BSER Unsupported by Data 
Commenter 0183 stated that EPA's proposed BSER for modified units is unsupported by the data resulting from numerous data errors including EPA's assumed heat rate improvements. The commenter stated that EPA failed to recognize that the heat rate improvements in the TSD (9% from 2002-2004 and 2% from 2010-2012) are likely tied, not to actual heat rate improvements, but to a conversion to different CEMS and that EPA mistakenly attributed an improvement (via calculation) in heat rates that was seen in the acid rain database to actual heat rate improvement. The commenter stated that EPA must reconsider its analysis of emissions data to take into account the change in calculation methodology, which will demonstrate that this decrease occurs on paper only and not in the real world. The commenter stated that EPA cites a wide range of studies regarding unit heat rate improvement potential but fails to consider how these studies may or may not apply in ERCOT or even more generally to units in a competitive market like ERCOT. According to the commenter, EGUs operating in a competitive environment such as ERCOT have a strong incentive to operate as efficiently as possible and, as a result, cost effective heat rate improvements have already been implemented by the generating units; once these improvements have been made, they are essentially complete and in most cases cannot be replicated at the units again. The commenter stated that EPA is effectively penalizing early adoption of efficiency improvements by disregarding the fact that heat rate improvements have already been made in the competitive market. The commenter stated that EPA's error in assuming that a 2% improvement in emissions is possible is exacerbated by the requirement that the 2% be calculated from the best historical emission rate and, without an understanding of what factors may have contributed to the historical low emission rate for a particular unit, it is impossible to say whether it can be repeated, much less improved upon. According to the commenter, unit heat rates consistently degrade following improvements and by requiring a 2% improvement over a unit's best year's emission rate, EPA is by definition establishing an impossible heat rate improvement.
Commenter 0242 stated that they have a particular concern with the EPA's claims that there are a wide range of studies and detailed engineering studies to support the proposed heat rate improvement potentials. The commenter stated that the studies cited by the EPA appear limited to a very small sample size from EPA Region 7, which presents the results of a heat rate improvement study provided by EPA Region 7 for seven coal fired units with details on capital upgrades and maintenance activities and measured heat rate improvements. See GHG Abatement Measure TSD. The commenter stated that examination of these data reveals that the majority of demonstrated, measured heat rate improvements at the seven coal fired power plants are characterized directly by Region 7 as returning unit performance to original design performance; thus, these measures are maintenance activities, which degrade over time, and cannot be adequately characterized as permanent heat rate improvements. The commenter stated that they understand via stakeholder outreach that the regular maintenance during a planned boiler/generator outage is done to restore, as much as possible, the unit to its original design performance and the assumption that these activities are not already occurring universally across the existing coal fired fleet is simply not appropriate. The commenter stated that the Region 7 study also reveals that capital improvements were limited to turbine efficiency upgrades and variable frequency drives; the largest heat rate improvement resulting from these capital expenditures was 1.83percent. The commenter stated that thus, the contention that a utility boiler or IGGC unit wishing to modify would be required to achieve an additional 2 percent heat rate efficiency improvement has not been adequately demonstrated. The commenter stated that if a well-designed efficient plant is maintained and is operating at near design efficiency, an additional 2 percent improvement in efficiency will not be possible and the small subset of units examined by EPA Region 7 is not representative of coal-fired units nationwide and should not be relied on for such an important rulemaking. 
Commenter 0215 stated the EPA did not include the results of any analysis in the docket showing that is true. Commenter was unable to locate any TSD in the docket that provides a justification for EPA's proposed standards for modified Subpart Da units, even though UARG has requested the analyses referred to in the preamble. See Emails from Craig S. Harrison, Hunton & Williams LLP, to Robert Wayland, EPA OAQPS, Re: Modified and Reconstructed Proposal (June 18 & 19, 2014). Commenter said this is unlawful and must be withdrawn, according to CAA Section 307(d)(3). Under this section, EPA is required to provide the basis and purpose for the Proposed Standards. The basis and purpose must include "a summary of . . . (A) the factual data on which the proposed rule is based; (B) the methodology used in obtaining the data and in analyzing the data; and (C) the major legal interpretations and policy considerations underlying the proposed rule." Id. The docket fails to include the "annual historical operating performance for [each] affected facility using historical CO2 emissions data for the calendar years 2002 through [2013]" that the Agency refers to in Proposed Section 60.46Da(c)(3)(i)(A). Commenter said also missing from the docket are any EPA calculations using its proposed methodology and its emissions database to provide the source-specific numerical standards that it would expect modified EGUs to achieve. Without such information, the commenter wasn't able to comment meaningfully on the source-specific standards that the Agency proposes that the units, if modified, could achieve. Without such calculations, which logically would have been included in the TSD that is absent from the docket, EPA cannot have conducted a reasonable inquiry into whether those limits are achievable. Commenter said EPA is "play[ing] hunt the peanut with technical information, hiding or disguising the information that it employs," and is "treat[ing] what should be a genuine interchange as mere bureaucratic sport." See Conn. Light & Power Co. v. Nuclear Regulatory Comm'n, 673 F.2d 525, 530 (D.C. Cir. 1982). 
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.
6.1.1.2 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.
6.1.1.3 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.
6.1.1.4 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.
Commenter 0169 stated that they do not support EPA's first co-proposal. The commenter stated that using a unit's best historical one year average is unreasonable, illogical, and arbitrary; a unit may have one year where heat rate is optimized based on ambient temperature, water temperature, electricity demand, equipment operation or availability, etc., but it is unreasonable to believe that these same conditions will be sustainable year after year. The commenter stated that recommended using an annualized CO2 emission rate that is based on a 10-year average would account for major and minor outage years, and heat rate degradation that occurs between outages. The commenter stated that it is also unreasonable to presume that any given unit can achieve a 2 percent HRI and that EPA should normalize data to determine what emission rate is possible, but discourages using every theoretical heat rate improvement possible to make this determination. 
The commenter stated that the proposal for modified units to not have to meet an emission standard more stringent than the corresponding standard for reconstructed EGUs is so stringent that it would take reconstruction to actually meet it and a modified unit may still not be able to be 2 percent better than its best year due to external factors such as weather, water temperatures, operating duty, and auxiliary load requirements; other factors that affect HRI include dispatch and whether pollution control equipment has been installed in response to regulatory requirements.  The commenter stated that for these reasons, it is not appropriate to require that the best historical emission rate be made 2 percent more stringent than best operating practices recorded since 2002; in other words, best should be defined with reference to current operating conditions, not past conditions that are no longer representative of an EGU's current operations. The commenter recommended a ten consecutive year average to determine the best historical emission rate and if EPA insists on a shorter time period, they recommended that the period of best historical performance should not be determined at the time of modification because unit may have already completed energy efficiency projects in anticipation for compliance with the ESPS. The commenter stated that using the best 10 consecutive year average emission rate without the automatic application of the 2 percent reduction during the years 2002 to the year the modification occurs is potentially more achievable than any one best year's performance.
Commenter 0142 stated that basing a proposed standard upon a historic emission rate is problematic, unfair, and does not appropriately reflect the inherent nature of electric generation. The commenter stated that selection of the baseline year is critical, because CO2 emission rates vary over time and there must be room for a 2 percent reduction in CO2 emissions below that baseline year, given the limited range of technically feasible and economically reasonable optimization methods that are available. The commenter stated that historic variability has little to do with add-on controls, but rather how the unit was dispatched, weather conditions, temperature of cooling water, type and blend of fuel fired, normal wear and tear, degradation of equipment over time, etc. The commenter stated that because the CO2 emission rate varies over time, any applied standard of performance based upon the lowest CO2 emission rate over that time period would be expected to increase, since it was the lowest emission rate selected; there is evidence that factors beyond the control of the unit operators will cause a modified unit's CO2 to creep up over time. The commenter recommended that if the EPA follows this approach, that a three year average from historic emission rates be utilized and that CO2 emission limits remain in effect until the next modification or for a period of five years, whichever comes first.
Commenter 0204 stated that BSER standard should not be the best historical annual emissions rate, since this does not factor in variables that can affect a unit's performance and CO2 emissions, such as load, fuel quality, and temperature; at a minimum, the best three consecutive year average emission rate is more appropriate in order to account for these variables. The commenter stated that EPA should consider allowing an averaging period up to five years, which is the period allowed for evaluating a modification under NSR air permitting requirements and should also accommodate cases where there is insufficient historic operation data to reflect recent physical or operational changes at a source, such as switching from bituminous to sub-bituminous coal or adding on air pollution control equipment. The commenter stated that these types of operational changes would result in a higher net heat rate at the source, and EPA should ensure that the BSER emission limit reflects those higher heat rates.
Commenter 0187 stated that the interval between major outages at coal-fired EGUs is typically three to four years, they support using the unit's best performance based on a three-year average longer (e.g., four-year average); it should not be based on an annual average.
Commenter 0192 stated that if EPA proceeds with a standard of performance based on historical emissions, they urge EPA to base the standard on the facility's emissions over a three-year period rather than a one-year period. The commenter stated that expanding the measurement period to three years will mitigate the risk of basing the standard on a narrow and unrepresentative time frame that reflects unique conditions that are unlikely to occur with regularity. The commenter stated that a three-year period will be more likely to encompass a wide range of operating conditions that more accurately reflects the conditions that a facility will experience in the future after a modification occurs; a longer measurement period will also be more likely to account for the declining performance of heat rate improvements over time and reflect a broader portion of cycle over which routine maintenance activities occur.
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. The EPA believes that a final standard of performance based on the units best historical single year adequately captures the expected operational variation and that the resulting standard is achievable via a combination of equipment upgrades and best operating practices  -  or using alternative compliance options such as natural gas co-firing.
Prefer Alternative #1, but period of best historical performance should be years from 2002 to the time when the unit becomes subject to section 111(d).
Commenter 0178 stated that they while they support EPA's first proposed alternative, if EPA finalizes a rule under which units are subject to requirements under both Sections 111(b) and 111(d), EPA should ensure that units are not required to make unreasonable heat rate improvements pursuant to Section 111(b) if they already have made improvements subject to a Section 111(d) plan. The commenter stated that, for example, under the first alternative, the period of best historical performance should be the years from 2002 to the time when the unit becomes subject to the CAA Section 111(d) plan, rather than to the time of the modification. According to the commenter, this would address the concern that sources that make improvements to their CO2 emission rate as a result of a CAA Section 111(d) plan would have lower baseline emissions from which to calculate their required rate. The commenter stated that, further, modified utility boilers and IGCC units that already have become subject to a CAA Section 111(d) plan should not be required to meet the two percent additional emission reduction based on equipment upgrades where the state plan requires heat rate improvements for such sources, or where the source has recently implemented measures to improve its operating efficiency. The commenter stated that in these circumstances, the additional two percent improvement would be unreasonable; this will avoid creating a perverse incentive under which plants would have no reason to invest in heat rate improvements if they anticipate making a future modification that will trigger Section 111(b).
 The EPA is not finalizing standards that are dependent on the timing of the modification.
Heat rates prior to a PCP should not be used in determining best historical CO2 emission rate.
Several commenters (0192, 0239) stated that since 2002, many units have installed pollution control equipment to meet federal air pollution requirements with the result that boiler unit heat rates (e.g. efficiency) are degraded due to the parasitic power load of the pollution control equipment. The commenter stated that this addition of parasitic load makes it challenging for a unit to even meet its best historical CO2 emission rate since 2002. The commenter stated that while pollution control projects (PCPs) are exempt from the definition of modification, other boiler modifications performed after a PCP could cause a unit to become subject to the proposed rule, making it difficult to achieve a pre-PCP heat rate.
 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. The EPA believes that a final standard of performance based on the units best historical single year adequately captures the expected operational variation and that the resulting standard is achievable via a combination of equipment upgrades and best operating practices  -  or using alternative compliance options such as natural gas co-firing.
Prefer Alternative #1, but implement in a way that does not penalize investments in heat rate improvements.
Commenter 0260 stated that if EPA finalizes emission standards based on the proposed BSER determination, they support the first proposed alternative, with revisions. The commenter stated that for units that already have made significant heat rate improvements, they do not support an approach under which the time period for best historic performance would be from the year of the first heat rate improvement to the date of the modification as this would penalize units that already have invested in improvements. The commenter stated that the percentage of required emissions reductions from the unit's best demonstrated annual performance should take into account past efficiency improvements. Commenter 0260-14285 provided the following example: equipment upgrades are being conducted at two EGUs to improve heat rates that, when completed, will increase efficiency by approximately four percent overall; because these units already are performing the majority of best work practices that EPA recommends for improving heat rate, significant additional heat rate improvements are not possible; and if the units subsequently made modifications, they would not be able to reduce their emissions by an additional two percent. The commenter stated that EPA also should take into account the fact that, as existing NGCCs are dispatched more frequently pursuant to state Section 111(d) plans, modified and reconstructed coal-fired units will be dispatched less, resulting in the degradation of units' heat rate due to more frequent cycling.
Commenter 0178 stated that they support EPA's first proposed alternative, but it should be implement in a way that does not penalize investments in heat rate improvements. The commenter stated that for units that already have made significant heat rate improvements, they do not support an approach under which the time period for best historic performance would be from the year of the first heat rate improvement to the date of the modification; this would penalize units that already have invested in improvements. The commenter stated that the percentage of required emissions reductions from the unit's best demonstrated annual performance should take into account past efficiency improvements; if a unit subsequently makes modifications, it would not be able to reduce emissions by an additional two percent. The commenter stated that EPA also should take into account the fact that, as existing NGCCs are dispatched more frequently pursuant to state Section 111(d) plans, modified and reconstructed coal fired units will be dispatched less, resulting in the degradation of units' heat rate due to more frequent cycling.
The proposed additional 2% CO2 emission reduction is not being finalized. 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. Investments in heat rate improvements should not trigger the 10% threshold  -  actually heat rate improvements normally do not result in any increase of potential CO2 hourly emissions as they are actions that result in increased efficiency not in increased fuel-input capacity. 
 EGUs that do trigger the modification standards will do so only after taking actions  -  likely capital intensive actions. 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. The EPA believes that a final standard of performance based on the units best historical single year adequately captures the expected operational variation and that the resulting standard is achievable via a combination of equipment upgrades and best operating practices  -  or using alternative compliance options such as natural gas co-firing.
Establish limit based on expected future operations including lower operating loads levels due to greater use of renewables.
Commenter 0162 stated that a modified source's new emission limit will need to be within the realm of what the unit's actual performance capabilities are at the load levels it will be called upon to operate. The commenter stated that the proposed GHG regulations emphasize a significant increase in the quantity of renewable energy being placed on the nation's grid and as more renewable energy is utilized, fossil fuel-fired electric generating units will increasingly be called on at lower load levels. Using the best historic numerical annual emission rate, as proposed, in order to determine the CO2 emission limit will not represent the emission rate that can be achieved by an affected unit; the historic operating data could represent primarily base-load (full-load) operating conditions. The commenter stated that to get a realistic picture of an affected source's CO2 emissions from fossil-fuel fired generating units for the purpose of determining emission limits, the source should be tested at the lower operating load levels required given the amount of expected renewable energy required by the proposed rule.
Commenter 0216 stated that if EPA chooses to adopt a unit-specific emission standard based on the unit's best historical emission rate, EPA should define best historical performance as the best rolling annual average emission rate from 2002 until the date the source undergoes modification, even if this date is after the source became subject to a 111(d) plan. The commenter stated that a standard of performance employing this alternative definition would be contrary to the requirements of 111, because it would not limit a modifying source's emission rate to the lowest rate adequately demonstrated for that source. 
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. The EPA believes that a final standard of performance based on the units best historical single year adequately captures the expected operational variation and that the resulting standard is achievable via a combination of equipment upgrades and best operating practices  -  or using alternative compliance options such as natural gas co-firing. Regarding the impact of greater renewable energy on operating levels, Section 2.6.5 of Chapter 2 of the `GHG Mitigation Measures' Technical Support Document discusses future capacity factors at coal-fired EGUs.
If total annual unit performance were to be used in attempting to identify a unit's best historical annual CO2 emission rate, CEMS data should not be applied in estimating the heat input.
Commenter 0226 stated that, although they oppose the use of total annual data to determine best year of operation in a particular time-period, if it were to be done in that way, the data should not come from a unit's CEMS. The commenter stated that the regulations in 40 CFR 75 for managing the quality of data from a CEMS allow a certain amount of variation in the CEMS data accuracy, which could lead to significant variation in calculated heat input which would lead to inaccurate heat rate calculations or inaccurate CO2 emission rate data.
Commenter 0226 stated that there have been issues in the past for sources that were attempting to measure heat input through CEMS data. The commenter stated that after installing CEMS as required by the Acid Rain Rule, many utilities noted that the CEMS were recording consistently higher heat input than conventional methods (input/output and output loss). The commenter stated that in the mid 1990's, to better understand the problem, EPRI studied the cause(s) for the high heat input and S02/CO2 emissions measurements. The commenter stated that the report, The Electric Power Research Institute Continuous Emissions Monitoring Heat Rate Discrepancy Project An Update Report- December 1996, indicated that Reference Method 2 had been found to be biased high. The commenter stated that instead of using CEMS data, they suggest that heat rate could be used as a performance indicator and that the total annual heat rate performance could be determined through measured fuel input and measured electricity production.
Chapter 2 of the `GHG Mitigation Measures' Technical Support Document discusses the impact that relative accuracy of CEMS might have on the results (Section 2.5.1) and the impact that changes in flow measurement might have on the results (Section 2.6.6). EPA believes the measurements from CEMS are the most accurate and most reliable measure to assess CO2 emissions rates and heat rates. 
Commenter 0215 stated EPA requested comment on whether it should select a year prior to or subsequent to 2002 for purposes of determining the best historical emission rate. Commenter said some of the problems described above that are inherent in EPA's proposed approach might be alleviated to some extent by using the calendar year just before a modification as the baseline year. But this step would not account for the impact of future control retrofits, changes in fuels, changes in duty cycle, and other factors. Moreover, in the absence of any TSD and EPA's emissions database, it is not possible to analyze this issue in any detail. As discussed above, there are innumerable other factors that cause heat rate to deteriorate over time, including operations at lower capacity factors, operating more time at low loads, and normal wear and tear of the hundreds of components that comprise a boiler. Changes in loading order can result from variations in the price of natural gas, the availability or unavailability of other units in a system, and literally whether the sun shines or the wind blows with respect to renewable sources. Similarly, changes in the coal or coal blends burned, especially burning more Powder River Basin than bituminous coal, degrades efficiency. It would be arbitrary for any EPA rule to require that operational changes that occurred before the Agency proposed this rule should dictate the CO2 rate that a modified unit must achieve under the entire range of potential unit operations that affect heat rate. And it would be arbitrary to select any specific heat rate figure as reflective of future potential for improvement for the industry generally, given the numerous site-specific and temporal factors that affect unit heat rate.
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. The EPA believes that a final standard of performance based on the units best historical single year adequately captures the expected operational variation and that the resulting standard is achievable via a combination of equipment upgrades and best operating practices  -  or using alternative compliance options such as natural gas co-firing.
6.2.4 Energy Assessment: Similar to NESHAP for Industrial Boilers
Contrary to NSPS and CAA
Commenter 0144 stated that the EPA proposal allowing source specific emissions limits be set based on an energy efficiency audit is contrary to the CAA Section 111(a)(1) and (b)(2); they are not aware of any precedent under the NSPS program for source specific emission limits.
The EPA is not finalizing a standard based on the result of an energy efficiency audit.
Energy efficiency audit in not a standard of performance that reflects BSER for the source category as required under CAA 111(a).
Commenter 0187 stated that section 111(b) of the CAA directs EPA to develop categories of stationary sources and promulgate regulations establishing standards of performance for new sources within such categories. The commenter stated that in establishing such standards, the Agency may distinguish among classes, types, and sizes within categories of new sources; the statute speaks strictly in terms of source categories and subcategories. The commenter stated that nowhere does it authorize development of the kind of source-specific energy efficiency audits EPA proposes; accordingly, the Agency lacks authority to require individual source owners to inspect their affected facilities to identify sources of reduced efficiency and detail ways to improve efficiency to allow the permitting authority to develop a unit-specific emission limit. The commenter stated that an energy efficiency audit is not a standard of performance that reflects application of BSER to the source category as required under the Act. 
Commenter 0203 stated that EPA exceeds its authority under the NSPS program by proposing the implementation of source-specific assessments for modified Da (and, should it use the same approach, for KKKK) units. The commenter stated that where appropriate, Congress authorized EPA to establish source-specific emission limitations; examples include BACT determinations for the PSD program, or NOx limits that can under certain circumstances be established in the acid rain program. The commenter stated that nothing in 111(b) authorizes EPA to establish a process whereby performance standards for modifications are to be derived or calculated on a source-specific basis, which could be construed as an attempt to subcategorize each EGU down to the individual unit level. The commenter stated that energy efficiency audits are not performance standards within the meaning of 111 and cannot be used by EPA to bypass the detailed work required to properly establish NSPS for classes of similar sources. The commenter stated that finally, EPA fails to address the requirement that it adopt 111 standards through proper notice and comment. The commenter stated that 
Commenter 0203 stated that if EPA is unable to set performance standards for properly subcategorized utility boilers, so that it is infeasible to prescribe or enforce a performance standard, it can set design, equipment, work practice or operational standards for source categories under 111(h); alternatively, it could determine that reconstructed or modified source NSPS are unnecessary, a conclusion arguably admitted as an appropriate outcome in the proposal. The commenter stated that although EPA states that it expects the rule to result in reductions in potential CO2 emissions, the Regulatory Impact Analysis concludes that no significant costs or benefits are anticipated; a rule that provides no benefits exceeds the Agency's authority under the CAA.
Commenter 0146 stated that the proposed provision that allows the section 111(d) implementing authority to determine a unit-specific emission standard that is based on the results of an energy efficiency audit is not lawful. The commenter stated that if EPA wishes to establish a NSPS, it must do so through notice-and-comment rulemaking so that regulated entities learn precisely what standards of performance EPA is proposing and can meaningfully comment; EPA cannot do so by providing for an energy efficiency audit that defers decisions about the numerical emission limit a source may have to meet until a later date. The commenter stated that this approach is arbitrary and capricious. The commenter stated that the NSPS program does not include the authority to establish a procedure by which another entity will determine the standards of performance for individual units on a case-by-case basis. The commenter stated that the proposed alternative contrast with section 111 provisions for prevention of significant deterioration whereby the Agency is authorized to set case-by-case unit-specific limits based on BACT for construction of a major source or major modification of such a source; or under the Act's Title IV Acid Rain Program, whereby section 407(d) authorizes EPA to establish source-specific emission limits for nitrogen oxides (NOx) under certain circumstances. The commenter stated that if EPA believes that it is not feasible to promulgate a standard of performance for the broad and diverse category of Subpart Da units or for subcategories of those units, there are at least two possible solutions: section 111(h) authorizes the Agency to promulgate a design, equipment, work practice, or operational standard, or combination thereof, when it is not feasible to prescribe or enforce a standard of performance; or, EPA could simply withdraw the proposal and determine that promulgating NSPS for modified sources is unnecessary.  
Commenter 0211 stated that they do not object to providing additional compliance flexibility to sources subject to section 111 standards; however, EPA cannot transform a CAA program that imposes national standards determined through a notice and comment rulemaking process into a new (and potentially duplicative) CAA permitting program. The commenter stated that a determination of BSER based on individual energy efficient assessments would, by its very nature, be subject to varying state-level determinations and changing standards over time. Such a program does not conform to the CAA statutory directive that BSER reflect the degree of emission limitation achievable and adequately demonstrated after taking into account various factors, including the cost of emission reductions. The commenter stated that while performing a valuable service, an energy efficiency audit, on its face, may not consider or fully weigh the costs of achieving emission reductions, nonair quality health and environmental impacts and energy requirements - all of which are mandatory factors to be considered in section 111(a)(1) standard-setting; also, the fact that this determination would be made at the state or federal level, depending on who the implementing authority is, renders such a process plainly contrary to the statute, which specifies that NSPS for new sources are established and revised only periodically (i.e., within every eight years) by the Administrator. The commenter stated that the fact that EPA seeks comment only with respect to an elective determination by a source to seek such a standard, versus the standard's application to the source by rule, does not cure this defect; under EPA's described alternative, BSER would be determined outside of the statutory process.
Commenter 0173 stated that the options under alternative #2 are illegal and should be withdrawn.
The EPA is not finalizing a standard based on the result of an energy efficiency audit. Comments regarding the establishment of a work practice standard have been addressed in an earlier response.
Contrary to NSPS and CAA - Lack of details on procedures and demonstration of feasibility & fails the notice and comment obligations of CAA.
Commenter 0150 stated that the proposal is too vague with respect to what an energy audit might entail; without any further explanation, use of such a procedure would not be practical. The commenter stated that the lack of detail, moreover, is inadequate to satisfy EPA's notice and comment obligations under the "CAA.
Several commenters (0191, 0249, 0252) stated that the EPA cannot finalize a rule that establishes site-specific emission 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.
Several commenters (0153, 0278) stated that the proposed rule does not explain the energy efficiency audit process for determining the applicable CO2 emissions rate limit or put in place any criteria that must be met as the limit is set, nor does EPA provide technical background for these types of audits and their potential effectiveness in improving EGU heat rates. The commenters stated that this is an unprecedented approach to performance standards under section 111 whereby an emissions limit will be determined later.
Commenter 0195 stated that to rely on the results of an energy efficiency audit as the basis for the unit-specific standard is without foundation in section 111, which does not authorize EPA or a state to establish a unit-specific performance standard including one based on the results of an energy efficiency audit. The commenter stated that where Congress intended for EPA to have authority to set unit-specific or case-by-case standards, the statute is very clear. The commenter stated that EPA's references to the energy assessment required in the Boiler MACT is intended to show that EPA has required other sources to perform an energy audit but it is unclear how the one-time energy assessment requirement in the Boiler MACT supports EPA's proposed use of an energy audit to serve as the basis for performance standards for modified EGUs under section 111. The commenter stated that the energy assessment required in the Boiler MACT was not used by EPA in any way to set the MACT standards for the affected boilers; furthermore, the Boiler MACT does not require industrial boilers to implement any of the measures identified in the energy assessment. The commenter stated that what EPA required in the Boiler MACT in terms of a one-time energy assessment does not serve as relevant precedent here for a performance standard for modified EGUs.
Commenter 0195 stated that if EPA could legally use an energy audit to serve as the basis for a performance standard, the proposed elements for the energy audit are so broad and expansive that the proposed elements generate more questions than provide concrete guidance with regard to how such an audit would work in practice. The commenter stated that the proposed elements of the energy audit reach beyond the affected source that would be regulated by section 111; an energy efficiency audit as the basis for a performance standard for an individual EGU is not a standard of performance for a source category or subcategory under section 111(b). 
The EPA is not finalizing a standard based on the result of an energy efficiency audit.
EPA's proposed site specific standard and failure to provide for notice and comment are unlawful.
Commenter 0157 stated that the energy efficiency assessment a site-specific, source-specific standard rather than a standard of performance for a category of sources and, therefore, is not a lawful proposal under section 111. The commenter stated that requiring third-party energy efficiency assessors to create ad hoc, source-specific limits is a refusal to articulate a known proposed standard and to take comment on it.
Commenter 0222 stated that EPA does not have the authority to employ energy efficiency audits to set source-specific standards that would be determined at a future date and subject sources to a regulation without an opportunity to provide meaningful comments on that future regulation. The commenter stated that EPA has no authority to subject an existing source covered by a Section 111 (d) plan to an undefined, "unit-specific" standard to be determined at the time of modification.
Commenter 0284stated that EPA cannot evade notice-and-comment rulemaking by employing energy efficiency audits to set source-specific standards in the future; if the Agency wishes to establish an NSPS, it must do so during a notice-and-comment process through which regulated entities can learn precisely what EPA is proposing and can meaningfully comment on that proposal. The commenter stated that Congress has not authorized EPA to establish an energy efficiency audit process with vague and amorphous standards such that a Section 111(d) implementing authority would determine a unit's emission limit.
Commenter 0183 stated that EPA's co-proposal that a unit-specific emission standard (to be determined by the Section 111 (d) implementing authority) be developed based on the result of an in-depth energy study (an energy efficiency audit) is unlawful; the EPA lacks the authority to employ energy efficiency audits to set source-specific standards that would be determined at a future date. The commenter stated that a Section 111 (b) standard must undergo the appropriate rulemaking process including notice-and-comment; to do otherwise leaves sources potentially subject to the regulation without an opportunity to provide meaningful comments on that future regulation.
The EPA is not finalizing a standard based on the result of an energy efficiency audit.
There is no CAA authority for third party audit as basis of standard.
Commenter 0149 stated that subjecting units to a third-party audit to determine what level of additional improvement, if any, is possible is not appropriate. The commenter stated that state agencies should have the discretion to set unit-specific standards that recognize already-achieved efficiency improvements as demonstrated by unit owners and operators, but EPA cannot force states to adopt the conclusions of third-parties with no CAA authority. 
Commenter 0249 stated that CAA section 111(b) does not authorize source-specific assessment and standard-setting for modified EGUs; EPA's authority under NSPS is to propose and establish uniform standards for source categories. The commenter stated that Congress has not authorized EPA to establish an energy efficiency audit process with vague and amorphous standards such that a CAA section 111(d) implementing authority would determine a unit's emission limit. 
The EPA is not finalizing a standard based on the result of an energy efficiency audit.
Lack of details and lack of support call into question the feasibility of audit approach.
Commenter 0144 stated that the EPA asks for comment on whether there should be a certification system and whether there are organizations that provide certifications of specialists in evaluating energy systems. The commenter stated that given the scope of this proposal, we find it surprising that the EPA would not have performed a cursory investigation as to whether such certification organizations exist, and as a result question whether adequate support for the energy assessment approach has been established.
Commenter 0162 stated that in the proposal the alternative #2 111(b) standard would be based on the source's expected performance after implementation of identified unit-specific energy efficiency improvement opportunities; however, the EPA does not elaborate on what the identified opportunities might be, or whether cost or technical feasibility would be considered.
Commenter 0162 stated that the emission limit for a modified source, as required by the plan, must be feasible for the unit; in addition, the assessment or audit for the modified unit must be feasible for the unit.
The EPA is not finalizing a standard based on the result of an energy efficiency audit.
Energy audit requirements not well defined, and, instead, support work practice standards.
Commenter 0226 stated that the co-proposed Alternative #2 energy improvement audit appears to be a work-standard and is a much more sensible approach to meeting the requirements of Clean Air Act 111 (b) than any of the other proposed standards. The commenter stated that the work standards should be applied in lieu of emission limits to comply with all of section111 with respect to CO2 emissions.
Commenter 0226 suggested that the implementing authority be the State and have authority for approving what should ultimately be a state specific program along with the final results of the standard on any particular unit. The commenter also suggested that any recommendations resulting from the energy audit not be mandatory but should be considered by the State and the respective unit owner/operator in coming to an agreement on how to respond to the audit findings.
Commenter 0239 stated that without well-defined standards and protocols for identifying an emission standard following the completion of an efficiency audit, this method of determining an emission limit is too broad and general to meet the requirements of Section 111(b) for specific performance standards for modified units. The commenter supported instead, work practice or operational standards to be implemented for sources that modify after becoming subject to a Section 111(d) plan.
Commenter 0187 stated that following the alternative #2 energy audit, if the Agency believes additional standards should be implemented at EGUs that have become subject to CAA Section 111(d), then the rule should only require work practice standards, but not energy efficiency projects. The implementing authority has considerable flexibility when developing a compliance plan to meet the requirements of CAA Section 111(d), and this plan may or may not include unit efficiency projects at Subpart Da EGUs. Therefore, if other approaches have been taken to meet CAA Section 111(d) requirements, the EGU should not also then be subject to additional efficiency improvement requirements.
The EPA is not finalizing a standard based on the result of an energy efficiency audit. Comments regarding the establishment of a work practice standard have been addressed in an earlier response.
Alternatives #1 and #2 are unachievable.
Commenter 0209 stated that EPA overestimated available heat rate improvements in co-proposed Alternative #1 by assuming that the opportunities listed in the Sargent & Lundy study are widely available. The commenter stated that they are concerned that EPA considers Alternative #1 to be a good benchmark for Alternative #2, since EPA stated "we anticipate that the audit process that we are considering will result in an emission rate consistent with the highest level of efficiency plus 2 percent (based on equipment upgrades) that we are considering for sources that modify prior to becoming subject to a state plan." (pg 34988). Commenter said because Alternative #1 is unworkable, Alternative #2 should not be presumed to achieve improvements similar to Alternative #1.
The EPA has addressed the achievability of the final standards in previous responses. The EPA is not finalizing a standard based on the result of an energy efficiency audit. 
In absence of energy audit expert certification process, EPA should not require one.
Commenter 0242 stated that the EPA is requesting if certification should be required and if so, what the basis of the certification should be and whether any organizations provide this type of certification. The commenter stated that if there currently is no certification process, the EPA should not be promulgating a requirement for such. The commenter stated that to require the assessment be conducted by energy professionals or engineers that have expertise in evaluating energy systems alone should surely be enough specificity without requiring a certification process that does not even currently exist; states would have the ability to determine if a chosen professional is sufficient.
The EPA is not finalizing a standard based on the result of an energy efficiency audit.
Use of previous energy audits.
Commenter 0242 stated that EPA is requesting comment on whether recent energy efficiency audits (e.g., within 3 years of the modification) that meet the requirements of this rule would satisfy the audit requirement or whether facilities that operate under an energy management program compatible to ISO 50001 can be used to satisfy the audit requirement. The commenter stated that any final rule should provide flexibility that recent energy audits, regardless of time, may satisfy the requirements for the energy audit under this proposal upon review by the state. The commenter stated that this flexibility is needed; the state would review the previous audit along with the history of the facility to determine if it is still accurate and appropriate for use under this rule.
Commenter 0169 stated that with regards to the use of previous energy audits, 3 years is too short of a time; a 5 year interval between audits is more realistic. According to the commenter, during a 5 year period some degradation in equipment will occur, but not to a point where the degradation would require replacement; 5 years would allow equipment degradation trending and analysis of cost-benefit to replace, repair or upgrade.
The EPA is not finalizing a standard based on the result of an energy efficiency audit.
Instead of the proposed vaguely defined auditing process, EPA should use PSD programs pre-permitting BACT reviews.
Commenter 0171 stated that the motivation behind energy audit co-proposal is sound, insofar as the ability of a unit to achieve additional heat rate improvements is inherently a unit-specific analysis of which improvements have already been made, among a range of other factors. The commenter stated that, instead of a vaguely-defined auditing process, EPA should use the PSD program's pre-permitting BACT reviews, a process with which state regulators and unit operators have considerable experience. The commenter stated that because the PSD program's modification test requires an increase of mass emissions over minimum thresholds instead of an increase in maximum hourly emissions, many more units trigger PSD requirements than regulation as modified units under section 111. The commenter stated that EGUs that would trigger 111(b) requirements as modified or reconstructed sources are already subject to PSD and must go through a BACT review. 
Commenter 0171 stated that section 111 performance standards often establish the BACT floor for a source category and, given that EGU operators are familiar with and subject to the BACT process, EPA could opt to make a determination that standards for modified and reconstructed sources should be the unit-specific BACT process in CAA section 169. The commenter stated that a standard mandating a unit-by-unit review, which units are already familiar with and obligated to undertake, could be a reasonable alternative for setting achievable and workable standards for modified and reconstructed sources.
 The EPA is not finalizing a standard based on the result of an energy efficiency audit.
Purpose of energy audits unclear as states would have to rely on methods other than unit-specific emission rates for modified units to meet their state goals.
Commenter 0142 stated that the proposed rule is unclear about what the energy audit will actually achieve, given EPA's proposal that existing sources subject to section 111(d) remain subject to state plans under section 111(d) after modification or reconstruction. According to the commenter, only four states have final state goals above 1,700 lb CO2/MW, and the EPA acknowledges limited opportunities exist for decreasing CO2 emissions for modified units when the EPA proposes a lower end value of 1,900 lb CO2/MWh. The commenter stated that states would already have to rely upon methods other than a unit-specific emission rate for modified units in order to meet their state goals.
The EPA is not finalizing a standard based on the result of an energy efficiency audit.
Standard that allows states to determine on a case-by-case basis what emission reductions are possible and reasonable after consideration of site specific factors is reasonable alternative.
Commenter 0249 stated that EPA cannot reasonably assume that any specific level of emission reduction can be achieved across the board by EGUs undertaking a modification as the level of additional emission reductions, if any that can be obtained from a source undergoing a modification can only be determined on a case-by-case basis, depending on several factors. The commenter stated that rather than specifying any across-the-board numeric emission reduction goal to be obtained by EGUs undertaking a modification, EPA should instead adopt a standard that allows for a state determination, on a case-by-case basis, of what emission reductions are possible and reasonable after consideration of the factors unique to each unit.
Commenter 0242 stated that they do not feel that meaningful comments can be formed because EPA has introduced so many variables to evaluate as possibilities against the different standards, within the different alternatives, and given the different ranges presented and all compounded by the multitude of changes being considered regarding applicability. The commenter stated that while it is apparent the lower end of the range is not achievable, it may be possible the higher end of the range could be achievable for some types of units; but EPA has not provided enough specificity to provide meaningful comments to determine achievability of the proposed standards of performance. The commenter stated that regardless, they believe that the only option with potential for success is alternative 2, although they believe it has been misapplied in this proposal. The commenter stated that the only portion of alternative 2 that is viable is the setting of an emission limit that would be determined by the implementing authority from the results of an energy efficiency improvement audit; in addition, the commenter is unsure if under this proposal, the energy efficiency audit would be limited to efficiency improvements inside-the-fence or if states would be able to consider outside-the-fence projects that improve efficiency for achieving a specified emissions limitation. The commenter stated that the EPA cannot require an emissions limit be set considering programs like end-use energy efficiency potential under the Section 111(b) source oriented control program.
Commenter 0242 stated that the alternative 2 proposal that an emission limit would be determined by the Section 111(d) implementing authority based on the sources expected performance after implementing unit-specific energy efficiency improvements taking into account what is technically feasible is the exact provision that should be occurring under this plan and under Section 111 (d) and nothing more.
Commenter 0242 stated that regarding the EPA's request for comment on whether a unit that modifies prior to becoming subject to Section 111(d) should also be allowed to meet an emission limit determined from the results of an energy audit and if it should be limited to sources that may have voluntarily, or for any other reason, implemented energy efficiency measures between 2002 and the modification (and if they should be required to provide evidence), the commenter stated that this type of flexibility is what is necessary in order to address issues that will arise as states develop and implement Section 111(d) plans. The commenter stated that the only method that should be used for determining emission limits under this provision and under Section 111(d) itself, is through the state's determination (such as an energy audit) of what is technically and economically feasible at a particular unit given the history of what efficiency improvements have already been completed. The commenter stated that approaches under this plan, of setting a limit and requiring an additional 2 percent, or under Section 111(d) of assuming 6 percent can be achieved on average, based upon inappropriate application of studies and averaging historical rates without any consideration for unit-specific feasibility is wrong, unworkable and can lead to individual facilities in some cases having requirements imposed that are beyond the best system of emission reductions.
Commenter 0256 stated that if EPA is going to implement a rule that presumes that energy efficiency projects can constitute BSER, then the rule needs to allow for a case-by-case assessment. The commenter stated that if a project triggers the NSPS modification or reconstruction provisions, the rule should require an energy assessment, which would be used to determine whether there are any cost-effective energy efficiency improvements that could be implemented. The commenter stated that to allow for a fair process, the EPA should certify that any cost effective energy efficiency improvement that is to be implemented under the modification and reconstruction rule will not be subject to NSR requirements. The commenter stated that the implementation of the energy assessment should not result in numerical limits for the unit; a demonstration that the change is made should suffice to demonstrate compliance with the NSPS.
Commenter 0197 commended the EPA for its realization that existing sources that undergo modification or reconstruction should have a limit determined by technical and economic feasibility from an engineering analysis as this allows the maximum emission reductions to be obtained without exerting undue pressure on the marketplace. The commenter stated that it gives all fuels and technologies the opportunity to compete and ensures that the energy industry is able to pursue economic opportunities and preserve fuel diversity; this, in turn, will ensure that all people will be provided with an affordable and reliable electric system and create a scenario where the environment, consumers, and industry all benefit. The commenter stated that the only additional action that EPA would need to undertake is to remove the obstacle of NSR, which has been cited by both the EPA and the National Energy Technology Laboratories as an impediment to improving the efficiency of fossil fuel-fired EGUs.
Commenter 0165 stated that EPA's BSER is flawed because EPA does not take into account that some of the affected units have already implemented the best operating practices to improve heat rate by 4 percent and equipment upgrades to improve heat rate by 2 percent and will not be available for future modifications. The commenter stated that because each utility boiler and IGGC unit are operating in different ways by different operators, the BSER for modifications should be determined on a case-by-case basis and established by the state, the implementing authority under 111(b), and would be accomplished by requiring the owner or operator of the affected unit to submit an energy assessment or audit of the unit as part of the application to modify or reconstruct the unit and specify a carbon dioxide emission rate. The state can then review the proposal as it would a BACT analysis under the, PSD program and establish the emission rate. 
The EPA is not finalizing a standard based on the result of an energy efficiency audit.
EPA should consider using the BACT process to set emission standards for modified and reconstructed units 
Commenter 0189 agreed that EPA should consider using the best available control technology (BACT) process for setting emission standards for modified utility boilers, IGCC and natural gas-fired combustion turbines. The BACT process takes into account emission rates that are achievable on a case-by-case basis, which is especially important considering unique limitations when modifying and reconstructing existing units. This is also important considering there is no add-on pollution control feasible to install on EGUs, as is the case for other pollutant.
The EPA is not finalizing a standard based on the result of an energy efficiency audit or any other unit specific analysis such as a BACT determination. The final standards  -  based on the affected unit's best historical performance  -  are achievable on a case-by-case basis.
6.2.5 Subjectivity to 111(d)
Support for being subject to the lower of the 111(d) plan instead of the unit's best performance since 2002
Commenter 0131 stated that, regarding EPA's request for comment on the issue of modified units being subject to the lower of the 111(d) plan or the best performance since 2002 less 2 percent, they support the 111(d) standard. The commenter stated that a single reasonable standard is best and makes the planning and execution of the modification achievable and economically viable.
The EPA is not finalizing this option.
Heat rate improvement potential - an additional 2 percent efficiency improvement may be unachievable for sources that make efficiency improvements as part of a 111(d) state plan. There is simply no record basis for this.
Commenter 0236 stated that there is no record basis for EPA's assumption that all modified sources can achieve a carbon dioxide emission level that is two percent lower than the source's best demonstrated historical performance level from 2002 to the date of the modification. The commenter stated that EPA even admits its concern that as a result of implementation of state plans, the additional 2 percent efficiency improvement may be unachievable for a substantial number of sources that make efficiency improvements as part of a 111(d) plan.
Commenter 0195 stated that under the section 111(d) plan, coal-fired EGUs will be operating at lower capacity factors, which will make further heat rate improvements very difficult to achieve. Commenter added even if modified units were not subject to that rule, the decreased demand for generation from coal-fueled EGUs would have a negative impact on the ability of modified utility boilers to achieve a 2% heat rate improvement.
 The EPA is not finalizing the proposed additional 2% additional emission reduction.
Heat rate improvement potential - EPA is applying existing unit standards (aggregated data for older and newer units) with modified unit standards (unit level rates). This results in standards not shown to be achievable at unit level (not supported in the proposal) as required by 111(a)(1).
Commenter 0226 stated that there isn't a great deal of historical information regarding the CO2 emission rates that are achievable by units undertaking section 111 modifications and reconstructions. The commenter stated that, however, in the GHG Abatement Measures TSD which supports both the 111(d) proposal and this proposal, it is suggested that an industry-wide six percent heat rate improvement is possible for existing sources, which appears to have been arrived at through use of average data to determine the heat rate improvement potential available through O&M practices and equipment upgrades at existing units for the purpose of developing state-specific goals (under the proposed 111(d) guidelines). The commenter stated that, for the proposal, this approach results in applying existing-unit standards (which are in the form of statewide emission rates based on old and newer units) with the modified-unit standards (in the form of individual, unit-level rates), without explaining how the data is equally applicable to both types of units. The commenter stated that these are aggregated data at the state level being applied as standards that must be achieved at the unit-level that haven't been shown to be achievable at the unit-level (not adequately supported in the proposal) as required by section 111(a)(l).
Commenter 0149 stated that based on its assessment in the proposed section 111(d) guidelines (and the related Abatement Measures TSD) that a fleet-wide six percent heat rate improvement is possible for existing sources, EPA concludes that the unit-specific emission limit based on historical best performance (which captures the good O&M practices at the unit) coupled with an additional two percent reduction (which captures minimum opportunities for additional heat rate improvements from equipment and system upgrades) can be achieved at reasonable cost. The commenter stated that EPA cannot rely on this existing source analysis in support of the proposed standards for modified units.
Commenters (0149, 0229) stated that EPA used average data on the heat rate improvement potential available through O&M practices and equipment upgrades at existing units for the purpose of developing state-specific goals, whereas a recently modified unit would be more likely to operate with the most efficient practices.  The commenters stated that EPA, therefore, recognizes that the data used to set the state-specific goals under section 111 would not be suitable for setting achievable unit-level standards;  despite this, EPA attempts to compare the existing source standards (which are in the form of statewide emission rates based on old and newer units) with the modified source standards (which are in the form of individual, unit-level rates), without explaining how the data are equally applicable to both types of units. The commenters stated that further, EPA's prescription of an additional two percent emission reduction has no basis and is not supported by EPA's finding that coal-fired power plants can, on a fleet-wide basis, achieve a six percent heat rate improvement. The commenters stated that EPA has attempted to take aggregated data at the state level and apply it to standards that must be achieved at the unit-level, which has resulted in standards that EPA cannot demonstrate are achievable at the unit-level, as required by CAA section 111(a)(1). 
The analyses described 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) has been updated in response to comments received on this proposed action as well as the proposal, under CAA 111(d), for emission guidelines for existing sources. The analyses in the final document (Chapter 2) 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. Further, as the EPA has noted in preamble section VI, owners/operators can also consider the use of natural gas co-firing to achieve the final emission limitation for affected modified EGUs.
Reliance on the Sargent & Lundy study does not justify heat rate improvement potential.
Commenter 0157 stated that EPA's assessment of heat rate improvement potential is significantly flawed and that reliance on the Sargent & Lundy study - the report is from 2009 and the data supporting it are even older - is not justified. The commenter stated that the report fails to consider the impact of significantly reduced capacity factors that will result from EPA's 111(d) proposal and that increasing gas output to an average 70 percent capacity factor will reduce coal capacity factors.
 Concerns with the use of the S&L study have been addressed elsewhere in this RTC and in Chapter 2 of the final `GHG Mitigation Measures' Technical Support Document. 
Modified source emission standard should consider whether a modification occurs after or before the Section 111 (d) requirements are effective.
Commenter 0169 stated that regarding co-proposed alternative #2, any modified source emission standard should consider whether a modification occurs after or before the Section 111(d) requirements are effective. The commenter stated that as EPA notes, a source which has already undertaken efficiency improvements to meet the highest level of efficiency may not have additional improvements available.
Commenter 0195 stated that EPA has not taken into account efficiency improvements that historically have taken place at utility boilers as they already have an incentive to operate as efficiently as possible, and many of the efficiency improvements envisioned by EPA as available are likely to have already been made by owners and operators. In addition, EPA points out in the preamble that a modifying source is likely part of a section 111(d) plan. Commenter said this would mean that the source already will have implemented extensive efficiency improvements to meet the state goals under the first building block outlined in EPA's section 111(d) proposal.
The final standards are not dependent upon when the modification occurs.
Sources subject to 111(d) guidelines should remain under 111(d) guidelines and not be subject to Section111 (b).
Commenter 0271 stated that the EPA's proposed rule for modified and reconstructed facilities under Section 111(b) would subject the same group of affected sources under Section 111(d) to additional standards above and beyond those required of an existing source and be more stringent than what the EPA determined BSER to be for the same group of affected sources under Section 111(d). The commenter stated that additionally, this proposed rule would require states to achieve emission reductions above and beyond their Section 111(d) defined goal. The commenter stated that based on its definition of BSER and the CO2 goals outlined under Section 111(d), states should not be obligated to seek further reductions from sources subject to 111(d). The commenter stated that affected facilities are likely to have to implement significant modifications to sources in order to meet the Section 111(d) guidelines. The commenter stated that because 111(d) requirements already represent the BSER, they are concerned that it may not be feasible for some facilities to meet an additional 2 percent reduction, and if so, certainly not in a cost effective manner. The commenter recommended that sources subject to Section 111(d) guidelines should remain under 111(d) guidelines, and not be subject to Section 111(b) NSPS.
As previously mentioned, the EPA is finalizing requirements only for steam generating units that conduct modifications resulting in an increase in hourly CO2 emissions (mass per hour) of more than 10 percent as compared to the source's highest hourly emission during the previous five years. With respect to modifications with smaller increases in CO2 emissions (specifically, steam generating units that conduct modifications resulting in an increase in hourly CO2 emissions (mass per hour) of 10 percent or less compared to the source's highest hourly emission during the previous 5 years), the EPA is not finalizing any standard or other requirements, and is withdrawing the June 2014 proposal with respect to these sources (see Section XV below). The effect of the EPA's deferral on setting standards for sources undertaking modifications resulting in smaller increases in CO2 emissions and the withdrawal of the June 2014 proposal with respect to such sources is that such sources will continue to be existing sources and subject to requirements under section 111(d). This is because an existing source does not always become a new source when it modifies. Under the definition of "new source" in section 111(a)(2), an existing source only becomes a new source if it modifies after the publication of proposed or final regulations that will be applicable to it.  Thus, if an existing source modifies at a time that there is no promulgated final standard or pending proposed standard that will be applicable to it as a modified "new" source, that source is not a new source and continues to be an existing source.  Here, because the EPA is not finalizing standards for sources undertaking modifications resulting in smaller increases in CO2 emissions and is withdrawing the proposal with respect to such sources, these sources do not fall within the definition of "new source" in section 111(a)(2) and continue to be an "existing source" as defined in section 111(a)(6).
EPA should ensure units will not be required to make unreasonable HRI under 111(b) if already made under 111(d) and the period of best historical performance should be the years from 2002 to the time when the unit becomes subject to the section 111(d) plan, rather than to the time of the modification.
Commenter 0260 stated that if EPA finalizes a rule under which units are subject to requirements under both Sections 111(b) and 111(d), EPA should ensure that units are not required to make unreasonable heat rate improvements pursuant to Section 111(b) if they already have made improvements subject to a Section 111(d) plan. The commenter stated that under the first alternative, the period of best historical performance should be the years from 2002 to the time when the unit becomes subject to the section 111(d) plan, rather than to the time of the modification. The commenter stated that this would address the concern that sources that make improvements to their CO2 emission rate as a result of a section 111(d) plan would have lower baseline emissions from which to calculate their required rate. The commenter stated that modified units that already have become subject to a CAA Section 111(d) plan should not be required to meet the two percent additional emission reduction based on equipment upgrades where the state plan requires heat rate improvements for such sources, or where the source has recently implemented measures to improve its operating efficiency; in these circumstances, the additional two percent improvement would be unreasonable. The commenter stated that this will avoid creating a perverse incentive under which plants would have no reason to invest in heat rate improvements if they anticipate making a modification that will trigger Section 111(b).
The final standards are not dependent upon when the modification occurs.
Modified sources subject to a 111(d) plan should be evaluated on a case-by-case basis to determine whether or not they should be subject to the 111(d) requirements.
Commenter 0162 stated that modified sources subject to a 111(d) plan should be evaluated on a case-by-case basis to determine whether or not they should be subject to the 111(d) requirements. The commenter stated that, for example, they have already undertaken a project to convert a combustion turbine to a natural gas combined cycle unit at a plant with two coal-fired units that recently transitioned to natural gas. The commenter stated that in general, the EPA recognizes that reductions in CO2 emissions from individual existing EGUs can be achieved by implementing either of two basic approaches: (1) making emission rate improvements at affected EGUs (e.g., by improving heat rates or switching to lower carbon fuels), and/or (2) reducing utilization of GHG-emitting EGUs (e.g., by reducing the overall demand for electricity or by shifting dispatch from higher-GHG-emitting EGUs to lower-GHG-emitting and non-emitting units). The commenter stated that although they has already retired one coal-fired unit and will soon be retiring the second coal-fired unit, they will not be recognized as complying with the regulation until the new unit is further limited by the 111(d) requirements. The commenter stated that the EPA states that this regulation will impact very few sources, but the few that are impacted should not be penalized for modifications that will ultimately reduce overall CO2 emissions.
As previously mentioned, the EPA is finalizing requirements only for steam generating units that conduct modifications resulting in an increase in hourly CO2 emissions (mass per hour) of more than 10 percent as compared to the source's highest hourly emission during the previous five years. With respect to modifications with smaller increases in CO2 emissions (specifically, steam generating units that conduct modifications resulting in an increase in hourly CO2 emissions (mass per hour) of 10 percent or less compared to the source's highest hourly emission during the previous 5 years), the EPA is not finalizing any standard or other requirements, and is withdrawing the June 2014 proposal with respect to these sources (see Section XV below). The effect of the EPA's deferral on setting standards for sources undertaking modifications resulting in smaller increases in CO2 emissions and the withdrawal of the June 2014 proposal with respect to such sources is that such sources will continue to be existing sources and subject to requirements under section 111(d). This is because an existing source does not always become a new source when it modifies. Under the definition of "new source" in section 111(a)(2), an existing source only becomes a new source if it modifies after the publication of proposed or final regulations that will be applicable to it.  Thus, if an existing source modifies at a time that there is no promulgated final standard or pending proposed standard that will be applicable to it as a modified "new" source, that source is not a new source and continues to be an existing source.  Here, because the EPA is not finalizing standards for sources undertaking modifications resulting in smaller increases in CO2 emissions and is withdrawing the proposal with respect to such sources, these sources do not fall within the definition of "new source" in section 111(a)(2) and continue to be an "existing source" as defined in section 111(a)(6).
If EPA requires the 2 percent reduction requirement, it should require that the reduction be off of a unit's heat rate at full load per, calculated pursuant to ASME performance test codes.
Commenter 0193 is concerned with the interplay of the proposed alternatives with the Agency's proposed 111(d) rule, specifically with the relationship between the proposed 2 percent reduction requirement for modified units under Alternative #1 and the proposed Building Block 1 in the CAA Section 111(d) proposal, which assumes for purposes of establishing state emission rates that existing coal-fired EGU can achieve, on average, a 6 percent efficiency improvement. The commenter stated that the Agency acknowledges that units that make efficiency reductions as the result of a 111(d) plan may not reasonably be able to achieve an additional 2 percent reduction following a modification; nor is there support in the record that a limit of 1900 lb CO2/MWh is achievable by existing, large coal-fired boilers, and for these reasons, EPA should not adopt Alternative #1.
Commenter 0193 stated that Alternative #2 is also problematic because units that modify before promulgation of a CAA Section 111(d) plan would be required to improve efficiency by 2 percent. The commenter stated that many existing EGUs have already made the efficiency improvements identified by EPA, and thus an additional 2 percent improvement may not be possible regardless of when the modification occurs; for this reason, EPA should not adopt a standard that requires a 2 percent reduction from a unit's pre-modification baseline emission rate; instead, sources should only be required to achieve reductions that are reasonably achievable. The commenter stated that Alternative #2 also erroneously assumes that existing coal-fired EGU's can achieve a limit of 1900 lb CO2/MWh, and there is no record support for this conclusion.
Commenter 0193 stated that if despite the concerns addressed above EPA nevertheless moves forward with a 2 percent reduction requirement, then at the very least it should modify the requirement to require that the reduction be off of a unit's heat rate at full load, calculated pursuant to applicable American Society of Mechanical Engineers performance test codes, not its actual annual emission rate. The commenter stated that this approach would provide a more objective measure of efficiency improvement than relying on actual annual emission rates, which may be more of a function of dispatch than actual efficiency.
The EPA is not finalizing the proposed 2% additional CO2 emission reduction.
Existing unit reductions are not achievable, it is unrealistic to expect an additional 2% reduction for modified units, and reliance on hypothetical unit is overly simplistic.
Commenter 0263 stated that the proposed standards for affected units are impractical when considered in conjunction with the requirements of 111(d) and EPA should consider allowing affected sources to meet a unit-specific emission limit determined by the implementing authority based on the results of an energy efficiency improvement audit. The commenter stated that the justification provided in this proposal is not sufficient to determine otherwise; however limited the instance of modifications or reconstructions may be, EPA cannot ignore the inability of these units to meet the standards as proposed in this rule. The commenter stated that the EPA intends for existing units to be regulated under the proposed 111(d) state plan and expects that existing units could achieve a six percent emission reduction attributed to energy efficiencies while our evaluation shows that such a blanket reduction in emissions is not achievable for existing units, and it is unrealistic for the EPA to expect that these same units can then further reduce emissions by another two percent should they become modified or reconstructed units.
Commenter 0263 stated that the EPA's reliance on a hypothetical 500 MW coal-fired unit as the basis for assessing the costs and benefits of the proposed rule and emission limits is overly simplistic and results in unrealistic conclusions. The commenter stated that the use of a hypothetical unit does not account for unique variables that would greatly add to the cost of compliance. According to the commenter, in Wyoming, the structure of coal contracts can require a utility to pay for unused fuel, which would negate the savings a utility could realize. The commenter stated that for mine-mouth power plants, the boilers are subject to the fluctuations in the quality of the live feed of coal that cannot be reasonably mitigated through the use of a coal blending; fuel switches or the unexpected need to blend coal could greatly add to the cost of compliance, and these types of factors have been omitted in this proposal.
The EPA is not finalizing the proposed 2% additional CO2 emission reduction.
Should uniform emission standards be available only to sources that modify before becoming subject to an approved 111(d) plan?
Commenter 0242 stated that the EPA is requesting comment on a compliance option of a uniform emissions standard of 1,900 lb CO2/MWh for large units and 2,100 lb CO2/MWh for small units and whether this should be available to only sources that modify before becoming subject to an approved Section 111(d) plan. The commenter stated that if this option is incorporated, they are unsure why the EPA would necessitate it be available only for sources under an "approved" Section 111(d) plan when EPA is proposing "submitted" Section 111(d) plans qualify as being "subject" under alternative 2 above.
The final standards are not dependent upon when the modification occurs.
EPA lacks authority to require modified sources to remain subject to section 111(d) regulation after modification.
Commenter 0173 stated that the proposed requirement for an existing power plant to remain subject to section 111(d) regulation even after that plant undergoes a modification and triggers the CO2 NSPS for modified power plants is contrary to section 111(a)(2) definitions of   "new source"  and "existing source." The commenter stated that the definitions of "new source" and "existing source" are mutually exclusive. The commenter stated that the definition of "new source" addresses the precise question of whether an existing source that undergoes a modification can still be considered an existing source: under section 111(a)(2), any existing source that undergoes a modification after the publication of a NSPS proposal for such sources becomes a "new source;" and, under section 111(a)(6), such a source cannot also be an existing source because that section defines an existing source as any source "other than a new source." The commenter stated that, consequently, under the statute, a stationary source cannot be regulated under section 111 as both a "new" source and an "existing" source; a source commencing construction prior to issuance of the relevant NSPS proposal for that source is an existing source unless (and until) it undergoes modification, at which point it becomes a "new source" and can no longer be an "existing source" under the very terms of the definition of "existing source." 
Commenter 0173 stated that, furthermore, section 111(d) clearly prohibits application of section 111(d) performance standards to new sources. The commenter stated that under section 111(d), plans established by the states apply only to existing sources and because the term "existing source" means any stationary source "other than a new source," standards under section 111(d) may only apply to stationary sources "other than" new sources. The commenter stated that consequently, because modified sources are clearly "new sources" under section 111, section 111(d) performance standards cannot apply to them and EPA's interpretation to the contrary is thus contradicted by the clear terms of the statute. 
Commenter 0173 stated that if, for the sake of argument, the statute were ambiguous on the question of whether EPA may continue to regulate modified sources under section 111(d), EPA's interpretation is not entitled to deference by the courts. The commenter stated that it is a well-established rule of construction that a statute's failure to prohibit a federal agency from regulating a certain entity does not mean that the agency may regulate that entity. The commenter stated that as the D.C. Circuit has reiterated, "if we were to presume a delegation of power from the absence of an express withholding of such power, agencies would enjoy virtually limitless hegemony". The commenter stated that to suggest that an agency may claim an administrative power "any time a statute does not expressly negate the existence of a claimed administrative power...is both flatly unfaithful to the principles of administrative law...and refuted by precedent." According to the commenter, the EPA is not entitled to deference on the question of whether it may regulate sources that are modified after becoming subject to a state or federal plan under section 111(d). The commenter stated that, in sum, section 111 is clear that performance standards under section 111(d) apply exclusively to existing sources, and that modified sources cannot also be "existing sources" and EPA's interpretation is directly contradicted by the statute. 
EPA is not finalizing an interpretation under which existing sources continue to be subject to requirements under section 111(d) after they become subject to requirements under section 111(b).  This issue has been addressed in Chapter 2 (Legal Issues) of this RTC.