Document ID: EPA-HQ-OAR-2013-0495-11819
Agency: epa
Document Type: Supporting & Related Material
Title: 
Posted Date: 2015-10-23T04:00Z

Chapter 5
Reconstructed Fossil Fuel-fired Utility Boilers and IGCC Units
Contents
5.1	General	3
5.2	Identification of BSER	5
Efficient IGCC unit as BSER	5
5.2.1 Technical Feasibility	7
Disagree that BSER is a SCPC or SC CFB boiler for large sources, and the use of the highest available subcritical steam conditions for small sources	10
Too many conditions to provide meaningful comments	14
Coal refuse CFB	15
5.2.2 Costs, Structure of the Energy Sector	16
Reduced fuel costs for supercritical units not enough to make cost of generating electricity less compared to a subcritical EGU	16
To evaluate cost of BSER, EPA should consider conversion cost from a subcritical to a supercritical boiler	16
Proposal would necessitate costly conversion from subcritical to supercritical unit and create a disincentive for upgrades	17
Required conversion from subcritical to supercritical means emission standard is not economically viable and would cause early retirement of coal-fired units	18
EPA solicited comment on having an upper capital cost threshold for reconstruction	19
5.2.3 Incentive for Technological Innovation	20
EPA's objective is reducing air pollution, not incentivizing sources to avoid the purpose of the CAA	20
5.3	Determination of the Level of the Standard	21
Limits not achievable	21
More stringent standard for existing sources is backwards	23
Unreasonable to apply standards of performance for reconstructed sources to modified sources	24
Emissions standards are too lenient	24
Support mass-based standard	25
5.3.1 Large Units Standard of 1,900 lb CO2/MWh; solicited comment on range of 1,700-2,100 lb CO2/MWh	25
Limit is unachievable	25
Performance standards are not supported by an adequate technical analysis	26
EPA reliance on information from one unit, Weston Unit 4, to support the proposed 1,900 lbs CO2/MWh standard is inappropriate	26
For the possible range of 1700 to 2100 lb CO2/MWh-net emissions for large units, a limit of 2100 lb CO2/MWh-net is more reasonable	27
Technical justification for CO2 emission standards at the lower end of the range EPA is considering for reconstructed sources is not sufficient	28
5.3.2 Small Units Standard of 2,100 lb CO2/MWh; solicited comment on range of 1,900-2,300 lb CO2/MWh	28
Standard does not reflect BSER and is not achievable	28
5.4	Subcategories	29
Additional subcategorization is warranted based on IGCC and utility boilers, boiler type and coal rank	29
Subcategory for lignite	33
Subcategory for coal refuse	33
Support for a case-by-case assessment for each utility boiler	34
Applying national averages to individuals units rather than case-by-case basis	36
Need for subcategories	37
Subcategorize by fuel type and boiler configuration	38
Identify appropriate BSER for modified/reconstructed sources and apply to determine standards of performance achievable by the source category	39

General
Commenter 0215 stated that given the rarity of EGU reconstructions, EPA should withdraw the Proposed Standards and decline to set a standard. Commenter suggested EPA should explicitly deem this proposal economically infeasible - and therefore not a reconstruction - any situation where the imposition of the NSPS would result in an EGU shutting down.
Yes, EGU reconstructions are rare. 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 decide to conduct a reconstruction. Therefore, it is appropriate to finalize standards in the event of such an occurrence.
Commenter 0215 stated that the reconstruction rule, which is codified in the generally applicable provisions of 40 C.F.R. part 60, applies to all of the nearly 100 NSPS source categories. Commenter quoted that "[a]n existing facility, upon reconstruction, becomes an affected facility, irrespective of any change in emission rate." 40 C.F.R. section 60.15(a). Commenter said the NSPS modification rule applies only to projects at existing facilities that "result[] in an increase in the emission rate to the atmosphere of any pollutant to which a standard applies." Id. section 60.14(a). Under the reconstruction rule, a reconstruction analysis is triggered when an owner or operator replaces the components of an existing facility to such an extent that "[t]he 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." Id. section 60.15(b)(1). Commenter pointed out that a unit is not considered to be reconstructed, however, even if it meets the 50 percent threshold when meeting the applicable NSPS would be "technologically and economically" infeasible. Id. section 60.15(b). 
Commenter 0215 stated that EPA notes that "[h]istorically, few EGUs have undertaken reconstructions." 79 Fed. Reg. at 34,971. Commenter agreed with the Agency's observation. Commenter referred to the Pennsylvania v. Allegheny Energy, Inc, (No. 05-885, 2014 WL 494574 (W.D. Pa. Feb. 6, 2014)) which rejected the reconstruction cost methodology applied by EPA's enforcement arm, and found that the projects at Armstrong Units 1 and 2 were not "reconstructions" because the capital cost of the new components did not exceed 50 percent of the capital cost needed to construct a comparable new facility. The states have appealed to the U.S. Court of Appeals for the Third Circuit, Pennsylvania v. Allegheny Energy, Inc., No. 14-1584 (3d Cir. filed Mar. 11, 2014), and EPA has filed a notice of intent to support the appeal as amicus curiae. 
Commenter 0291 stated that EPA's existing general reconstruction rule codified in the general provisions of 40 (17.F.R. Part 60, applies to over a hundred categories of NSPS sources. An existing facility fails under the reconstruction rule "upon reconstruction, [...] irrespective of any change in emission rate." In contrast, the NSPS modification rule applies only where projects at existing facilities "resulti[ng in an increase in the emission rate to the atmosphere of any pollutant to which a standard applies," - Reconstruction is triggered when an owner or operator replaces the components at an existing facility to such an extent that 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. A reconstructed unit is not required to meet the standards if doing so would be "technologically and economically" infeasible. EPA proposes that the BSER for reconstructed fossil fuel-fired boiler] and IGCC EGUs will the "the most efficient generating technology." This technology includes using "higher steam, temperature and pressure. Even if the boiler was not originally designed to do so." BSER for large sources is a supercritical pulverized coal or supercritical circulating fluidized bed boiler, while a subcritical pulverized coal or circulating fluidized bed boiler is BSER for small sources. EPA asserts that requiring supercritical technology for large sources is "technically feasible" because "supercritical steam conditions has !sic] been demonstrated by many facilities since the 1960s," and that the steam tubing and other equipment necessary to allow the use of the best demonstrated steam cycle can be replaced at any existing EGU. It maintains that a boiler that has been reconstructed to use this technology will produce fewer emissions than before and that no add-on technology to control emissions would be involved. EPA also asserts that this option is "economically feasible." It bases this assertion on a U.S. Department of Energy National Energy "Technology Laboratory theoretical study that estimated that a new supercritical boiler using subbituminous goal would emit 7 percent less CO2 per MWh at an additional cost of only 3% compared to a subcritical boiler. EPA observes that utility boilers are numerous and diverse in size and configuration," and acknowledges that it often -does not have sufficient information" about them.. However. The Department of Energy study examined only two units, both of which burn subbituminous coal and only recently began operation. The LK respectfully submits that EPA's current approach seeks to arbitrarily pursue a major rule that could apply to almost a thousand diverse EGUs. Many of which burn different coals. The LEC is not aware that any existing subcritical unit has ever been converted to a supercritical unit, and strongly believes it would be impractical to do so. EPA cannot therefore base its Proposed Rule on an as-yet-untested boiler conversion. Basing a proposed. Emission limits on an unlawfully unsupported BSER. EPA proposes that sources with a heat input above 2,000 MMBtu/h (large units) must meet an emission limit of 1,900 lb CO2/MWh-net while sources with a heat input equal to or less than 2.000 MMBtu/h (small units) must meet an emission limit or 2,100 lb CO2/MWh-net. EPA requests comment on a range of limits between 1,700 to 2.100 lb CO2/MWh-net for large units and between 1,900 to 2,300 lb CO 2/MWK-net for small units, using a 12 operating-month rolling basis. The 1..EC believes that although some new state-of-art supercritical boilers might the able to achieve 1,900 lbs CO2/MWh-net for large coal-fired boilers, it is not possible for existing units undergoing reconstruction to do so. Even relatively new supercritical Units may not achieve 1,900 lbs CO2/MWh-net, depending on duty cycle, local environmental siting conditions, and water cooling method. In addition to issues concerning EPA's authority, the Proposed Rules for reconstructed units lack supporting technical justification and should therefore be withdrawn. 
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. 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 also 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. 
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. 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. 
Identification of BSER
Efficient IGCC unit as BSER 
Commenter 0232 stated that if EPA does not adopt conversion to gas as BSER for reconstructed coal-fired EGUs, it should base the standard on performance of an efficient IGCC unit. The commenter stated that EPA did not fully consider an efficient IGCC unit as BSER for reconstructed coal-fired EGUs as they only stated that the DOE/NETL estimates that an IGCC unit emission rate is comparable to those achieved by a supercritical coal-fired EGU. The commenter stated that if EPA had fully considered efficient IGCC technology, they likely would have concluded it is the most efficient coal-fired generation technology available and that this technology supports an emission standard as low as 1,600 lb CO2/MWh net. The commenter presented the following reasons for its position that IGCC better satisfies the statutory criteria for BSER than the conventional, uncontrolled SCPC system that EPA has proposed:
-Technical feasibility. IGCC systems have been commercially available for years and are adequately demonstrated. In the proposed standards for new EGUs, EPA stated that generation technologies representing enhancements in operational efficiency (e.g., supercritical or ultra-supercritical coal-fired boilers or IGCC units) are clearly technically feasible and present little or no incremental cost compared to the types of technologies that some companies are considering for new coal- fired generation capacity. EPA's proposal for new units indicates that each of the coal-fired units EPA found to be in the advanced stages of construction and development utilizes IGCC. The technical literature confirms the technical feasibility of IGCC technology. EPA incorrectly suggested that IGCC technology could not achieve a lower emissions rate than an SCPC facility. Even five years ago, a new IGCC facility could achieve an emission rate of 1,745 lb CO2/MWh net, substantially lower than the 1,900 lb/MWh net emission rate that EPA has proposed for large reconstructed coal-fired EGUs. Today, IGCC units with Shell Global Solutions gasifiers can achieve an emission rate of 1,595 lb CO2/MWh net. IGCC configurations using General Electric Energy and ConocoPhillips gasifiers can achieve rates of 1,723 lb CO2/MWh net and 1,710 lb CO2/MWh net, respectively. Accordingly, modern IGCC technology can readily achieve an emission standard between 1,600 and 1,700 lb CO2/MWh net. A facility that cannot feasibly meet this standard is not reconstructed (see 40 C.F.R. 60.15(b)(2) (establishing technological and economic feasibility as part of the definition of reconstruction). If site-specific challenges make it impossible for certain units to achieve an emissions rate between 1,600 and 1,700 lb CO2/MWh net, those units would not be considered reconstructed sources and would be required to comply with state plans under section 111(d). 
-Emission reductions. Establishing a standard that is 200-500 lb CO2/MWh net lower than the one EPA has proposed can lead to significant emission reductions over the lifetime of a facility. Fossil fuel-fired utility boilers and IGCC units have lifespans of several decades. It is essential that EPA avoid policies that would allow the lock-in of high-emitting infrastructure.
-Costs. A reconstructed unit can deploy IGCC technology at reasonable cost, well below the legal standard for BSER. NETL estimates the levelized cost of electricity from an IGCC unit to be about $94 to $103/MWh (in 2007 dollars). This is slightly higher than the levelized cost of electricity from an SCPC unit, which NETL estimates to be $75/MWh (2007$). It is also comparable to the cost of electricity a new coal-fired EGU with partial CCS, which EPA estimated at approximately $110/MWh (2011$) excluding revenue from sale of the captured CO2. The cost of an IGCC unit is well within the range of costs determined to be appropriate by courts reviewing section 111 performance standards. Thus, cost considerations are not a barrier to selecting IGCC as BSER for these reconstructed units. EPA should also consider how changes in the regulatory environment may affect the relative costs of IGCC and SCPC units. The NETL report was based on a study that was conducted before EPA promulgated MATS and its cost projections assumed that the performance target for new IGCC and SCPC units would be a mercury emissions rate that is significantly less stringent than the finalized MATS standard for these units. The mandate to rigorously control mercury emissions may have eroded the SCPC units' cost advantage over IGCC.
-Non-air health and environmental impacts. Selecting an efficient IGCC facility as BSER would avoid significant impacts on water resources. IGCC facilities produce much less wastewater than SCPC facilities and consume less water than SCPC facilities.
-Innovation. EPA has the opportunity to spur significant innovation in IGCC technology. A recent study by EPRI identified several key technological advances that could contribute to increasing net plant efficiency at an IGCC facility with CCS by more than 11 percentage points while cutting the cost of electricity in half. Several of these innovations could improve efficiency and reduce costs at an IGCC facility that does not utilize CCS. For instance, advanced gas turbines with a firing temperature of 2900 F are predicted to increase efficiency by 5.5% and reduce the cost of electricity by 21% (measured in cost/MWhr). EPRI predicts that the capital costs of IGCC should come down as the technology matures and more units are constructed, but it is the next generation of technologies discussed in this roadmap that will have the most significant impact on the competitiveness of IGCC relative to other coal power technologies. Relying on IGCC technology is also consonant with deploying CCS technology. With currently available technology, CCS is generally more economical at an IGCC facility than at an SCPC facility. Each of the three coal-fired EGUs that are at an advanced stage of construction and development are utilizing CCS and IGCC technology together, taking advantage of opportunities for efficient deployment of CCS.
-Energy requirements and impacts on power sector. The net plant efficiency (measured on an HHV basis) is comparable at IGCC and SCPC facilities. Accordingly, basing BSER on the reductions achievable with efficient IGCC technology would not impose more burdensome energy requirements than an SCPC-based standard. In addition, selecting efficient IGCC technology as BSER would not have a significant impact on nationwide electricity prices, fuel diversity, the structure of the power sector, or electricity supply. EPA reasonably concluded that the proposed rule would not have significant impacts on these issues because few units are expected to undergo reconstructions and there are already strong incentives to utilize efficient generation technologies at these facilities, and the same analysis would apply to a standard based on IGCC.
The EPA recognizes IGCC as an advanced technology that provides increased flexibility. However, on a net basis, the emission reductions are similar to those of a highly efficient SCPC and the EPA does not determine it to be the BSER for reconstructed sources.
5.2.1 Technical Feasibility
EPA misinterpreted or misused the Sargent & Lundy report to support its proposed standard and BSER.  
Commenter 0259 stated that in the unlikely event they modified or reconstructed a unit, such unit could not meet the emission reductions set out in the Proposed Rule. The commenter stated that perhaps such reductions are too stringent because the EPA misinterpreted or misused the key report it relies on to support its proposed standard and BSER. The commenter stated that the EPA reviewed the engineering studies available and selected the Sargent & Lundy 2009 study as the basis for its assessment of heat rate improvement potentials from equipment and system upgrades. In regard to that study, Sargent & Lundy recently confirmed to the commenter that they did not view the heat rate savings to be cumulative and that Sargent & Lundy believe the EPA misinterpreted the study results. See Sargent & Lundy letter to Jolin M. Meacham of NPPD dated September 16, 2014. The commenter stated that Dr. Raj Gaikwad, Sargent & Lundy's head of environmental services, made a presentation concerning potential heat rate savings and indicated that there is difficulty in generalization that every facility is different and that same solution cannot be applied. See presentation made by Dr. Gaikwad, Reducing CO2 Emissions through Improved Generation Efficiency, at 7. The commenter stated that the Nicholas Institute workshop published a report in January of 2013 which quotes Dr. Gaikwad as saying "the potential for improvements in heat rate is source-specific because that potential depends upon factors that differ from unit to unit: combustion type, fuel type, elevation, maintenance and retrofit history, and air controlled technology, to name a few." See Nicholas Institute, Regulating Carbon Dioxide under Section 111(d) of the Clean Air Act: Options, Limits and Impacts (January 2013), at pp. 12 and 13. The commenter stated that the report states that "Bilirgen and Gaikwad emphasize the difficulty in generalizing the potential for heat rate improvements in units across the nation absent calculations on a granular, unit-by-unit level." The commenter stated that the Sargent & Lundy study used by EPA stated that all estimated capital and installation costs were as of the year 2008. See attachment of Sargent & Lundy letter to Jolin M. Meacham of NPPD dated September 16, 2014 The commenter stated that the study goes on to warn that: "S&L cautions that the costs presented herein are not indicative of those that may be expected for a specific facility due to variables such as equipment, material, and labor market conditions and site specifications." Sargent & Lundy, Coal-Fired Power Plant Heat Rate Reductions, at 1-3 (Jan. 22, 2009). The commenter stated that heat rate improvement projects can be very costly and reliance on S&L's 2008 cost estimates for non-specific plants do not comport with Section 111(a)(1)'s requirement that the cost of achieving emission limitations must be taken into account. The commenter stated that the EPA's apparent misunderstanding or confusion concerning the Sargent & Lundy report underscores the fact that the EPA has not shown that its proposed BSER is achievable, cost effective or adequately demonstrated. The commenter recommended that the EPA adopt a unit specified assessment and thereafter a unit-specific emission limit for modified or reconstructed sources. Such a plan would not depend on the 2009 S&L study as a basis.
 The S&L study was not used to develop standards for reconstructed sources.  Comments related to use of the S&L study have been addressed in Chapter 6 of this RTC.
Commenter 0215 stated EPA's proposed BSER determination is based on data from only two units that do not address feasibility at the nearly one thousand diverse EGUs throughout the country, many of which burn different coals than those assessed in the studies EPA cites. No subcritical unit has ever been converted to a supercritical unit, and it would be impractical to do so. Conversion to supercritical steam conditions, therefore, has not been adequately demonstrated for subcritical EGUs that undertake reconstructions. 
Commenter 0215 continued that any control technology selected as BSER must be "adequately demonstrated." The D.C. Circuit has held that a system that has been adequately demonstrated is "one which has been shown to be reasonably reliable, reasonably efficient, and which can reasonably be expected to serve the interests of pollution control without becoming exorbitantly costly in an economic or environmental way." Essex Chem. Corp. v. Ruckelshaus, 486 F.2d 427, 433 (D.C. Cir. 1973); see also Natural Res. Def. Council v. Thomas, 805 F.2d 410, 428 n.30 (D.C. Cir. 1986). Commenter concluded that an adequately demonstrated system must have an operational history that shows more than mere technical feasibility. It must be dependable, effective, and affordable for individual sources, based on actual operating experience within the source category or at sufficiently similar sources. Moreover, a technology must be adequately demonstrated for all sources within a category or subcategory and available for each source type to which the standard will apply. For example, in its 2005 proposed revisions to the NSPS for Subpart Da units, EPA rejected supercritical boiler design, IGCC technology, and the use of clean fuels as potential bases for its revised standards due in part to the unavailability of these options across source types to which the standards would apply. 70 Fed. Reg. 9706, 9712, 9714, 9715 (Feb. 28, 2005). Commenter said the conversion of subcritical units to supercritical units has not been adequately demonstrated by any stretch of the imagination.
Commenter 0289 stated doubt that the vast majority of supercritical units could meet these standards "taking into account the cost of achieving such reduction;" it would not be technologically and economically feasible. Commenter said EPA asserts that requiring supercritical technology for large sources is "technically feasible" because "[t]he use of supercritical steam conditions has been demonstrated by many facilities since the 1960s." While supercritical steam technology itself may be a feasible technology, there is insufficient evidence to demonstrate that reconstructed supercritical units could comply with the proposed limits. Further, there is absolutely no demonstration that a reconstructed subcritical unit can be reconstructed in the form of a compliant supercritical unit. A supercritical unit cannot be re-built on the site of a subcritical power plant without essentially requiring the construction of a power plant with a completely different design. Commenter said there is much more to converting a subcritical plant to a supercritical plant than "replace the steam tubing and other necessary equipment." Numerous support facilities and infrastructure would have to change, pushing these changes far beyond technological and economic feasibility. Furthermore, the regulations state that the 50-percent threshold that triggers reconstruction requirements is based on the "fixed capital cost that would be required to construct a comparable entirely new facility," but subcritical and supercritical units are not comparable-they are far too distinct to use a supercritical unit to set the triggering threshold for subcritical units. Ultimately, the standards proposed by EPA for reconstructed units cannot be met. Commenter said EPA must impose more lenient limits for supercritical units, as those limits currently proposed are not achievable. It must then also create categories for subcritical units, with correspondingly less onerous standards. Furthermore, within each of those primary categories (subcritical and supercritical), it must then create fuel-specific subcategories. There must be subcategories for lignite, with further relaxed emissions limits and standards that reflect the unique characteristic of the fuel and the design of the facilities to burn the fuel. 
Commenter 0215 stated EPA acknowledges that the existing fleet of fossil fuel-fired steam generating boilers is "numerous and diverse in size and configuration" and that it often "does not have sufficient information" about them, but EPA's TSD for reconstruction nevertheless attempts to support its proposal based on a study of two brand new units that recently commenced operation, both of which burn subbituminous coal. Commenter argued that the record is insufficient to support a rule that could apply to almost a thousand diverse EGUs, many of which burn different types of coal. Commenter highlighted a key point from one of their attachments from one of their consultants, that no existing subcritical unit has ever been converted to a supercritical unit, and it would be impractical to do so. See Cichanowicz Heat Rate Report at 4-2. Commenter said it is arbitrary and speculative for EPA to base its proposed reconstruction rule on a radical boiler conversion that has never been undertaken; therefore, the proposed NSPS is unlawful because EPA has failed to demonstrate that it is adequately demonstrated, achievable, or even feasible, across the entire source category. Commenter said BSER for all coal-fired units, except those that are already designed to be supercritical units, should be their original subcritical design. 
 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. 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. Importantly, the EPA notes that the reconstructed unit is not required to convert a subcritical boiler to a supercritical boiler  -  the EPA does not specify any particular technology that must be used. Rather the reconstructed unit must meet a standard of performance consistent with the emission reductions achieved by the BSER. Owners/operators can consider other options  -  such as 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 emissions of air pollutants.
Disagree that BSER is a SCPC or SC CFB boiler for large sources, and the use of the highest available subcritical steam conditions for small sources
Several commenters (0146, 0149, 0149, 0152, 0158 0160, 0171, 0177, 0183, 0187, 0195, 0199, 0203 0214, 0222, 0226, 0227, 0239, 0242, 0249, 0278) disagreed with the EPA's proposed BSER for reconstructed fossil fuel-fired utility boilers and IGCC units: that BSER is a supercritical pulverized coal or supercritical circulating fluidized bed boiler for large sources, and the use of the highest available subcritical steam conditions for small sources; that supercritical technology for large sources is technically feasible because the use of supercritical steam conditions has been demonstrated by many facilities since the 1960s and that the steam tubing and other equipment necessary to allow the use of the best demonstrated steam cycle can be replaced at any existing EGU; that such a redesigned boiler would result in fewer emissions and that no add-on technology to control emissions would be involved and that this option is economically feasible based on a DOE NETL theoretical study that estimated that a new supercritical boiler using subbituminous coal would emit 7 percent less CO2 per MWh at an additional cost of only 3 percent when compared to a subcritical boiler; and that the proposed emission limits would be 1,900 lb CO2/mwh-net for units with a heat input of greater than 2,000 mmbtu/h or 2,100 lb CO2/mwh-net for sources with a heat input of 2,000 mmbtu/h or less.
Several commenters (0146, 0150, 0167, 0171, 0177, 0183, 0201, 0214, 0222, 0224, 0229, 0249, 0254, 0277) stated that the EPA had provided no evidence that the proposed BSER is technologically feasible nor a demonstration that the standard can be met.
 
Commenter 0227 stated that comparing the cost of constructing a new unit of one design versus another design reveals nothing about the cost to "reconstruct" an existing unit for duty it was never designed initially to accommodate. The commenter stated that a reconstruction analysis is most likely to be undertaken if there has been a catastrophic event that has damaged a sufficient number of the components that make up the "affected facility" that complete replacement of the damaged components is required. The commenter stated that while such replacements may present some opportunities to rebuild with materials that are capable of accommodating the higher pressures and temperatures that are employed in supercritical units, the ability to do so in an economically feasible fashion will depend almost entirely on the components that need to be replaced. Even then, supporting supercritical operations may require the addition of components not present in the original steam generator configuration for which there is no space, including steam reheat cycles as proposed by EPA, making the conversion technically infeasible. EPA has no basis for its assumption that such reconstructions are possible, let alone economical.
 
Commenter 0222 stated that a supercritical unit cannot be re-built on the site of a subcritical power plant without essentially requiring the construction of a power plant with a completely different design. The commenter stated that there is much more to converting a subcritical plant to a supercritical plant than replacing the steam tubing and other necessary equipment; numerous support facilities and infrastructure would have to change, pushing these changes far beyond technological and economic feasibility. The commenter stated that furthermore, the regulations state that the 50 percent threshold that triggers reconstruction requirements is based on the fixed capital cost that would be required to construct a comparable entirely new facility, but subcritical and supercritical units are not comparable - they are far too distinct to use a supercritical unit to set the triggering threshold for subcritical units.  
 
Commenter 0226 stated that the EPA estimated capital costs of a SCPC EGU (3 percent greater than a subcritical unit) does not demonstrate that the proposed standards for reconstructed coal-based boilers and IGCC units are achievable in a modified/reconstructed unit context. The commenter stated that such a cost does not appear the meet the second prong of the test of a reconstructed unit test. That is, that the component replacement constitutes a reconstruction only if it is technologically and economically feasible for the source to meet the applicable standards.
 
Commenter 0149 stated that EPA's Reconstructed Memorandum discusses EPA's efforts to project achievable emission rates through the hypothetical reconstruction of a small sample of existing coal-based units and that as part of these hypothetical reconstructions, EPA alters not only the boiler and steam cycle, but also requires that units use different coal ranks and install different cooling systems and then concludes that the resulting standard has been demonstrated as nationally achievable. The commenter stated that these types of wholesale changes likely would be equal to or more expensive than building an entirely new, completely different new unit, in part because EPA is requiring the construction of an entirely new unit. The commenter stated that in essence, the proposed BSER and standards for reconstructed units prohibit reconstructions and standards that effectively prohibit reconstructions are, by definition, unachievable, regardless of EPA's hypothetical projections about potential emission rates.
 
Commenter 0160 stated that utilities would likely be forced to build new power plants, rather than attempt compliance with the EPA's proposed reconstruction rules and that new power plants may not represent the most efficient allocation of utility resources creating unnecessary costs that would be passed along to customers through higher power prices. The commenter stated that the EPA has also not addressed the most likely form of reconstruction, the conversion of boilers to burn natural gas rather than coal. 
 
Commenter 0169 stated that in the BSER Memo, EPA discusses the design parameters for the most efficient power plant inferring that all modified or reconstructed power plants should utilize all the technologies discussed. See BSER Memo, pp. 2-5. The commenter stated that all of these ideal design parameters may not be feasible, practical, economical, or possible to use at every modified or reconstructed facility. The commenter stated that, for example, EPA discusses that once-through cooling systems have an efficiency advantage over recirculating systems, yet power generating facilities are under constant barrage from environmental advocacy groups to replace existing once-through cooling with recirculating cooling tower technology. The commenter stated that under the Clean Water Act 316(b) Phase I requirements it is virtually impossible to construct a new large power plant without utilizing recirculating system cooling tower technology to meet these requirements. The commenter stated that in an effort to optimize efficiency within the required cooling tower recirculating system, the commenter's facility was designed and constructed using advanced cooling tower packing. The commenter stated that as this example shows, when modifying or reconstructing a new power plant, every ideal design parameter cannot be met, and choices are made that influence other design parameters.
 
Commenters (0146, 0249) stated that EPA attempts to support the proposed standards in a TSD based on a DOE NETL study of two units that recently commenced operation, both of which burn subbituminous coal. The commenters stated that this is an inadequate basis to demonstrate achievability of a standard that could apply to a category of sources that are numerous and diverse in size and configuration, that vary in age, and that use different ranks of coal. The commenters stated that for this reason alone the proposed NSPS is unlawful because EPA has failed to demonstrate that it is achievable, or even feasible, across the entire source category. The commenters stated that they are not aware that any existing subcritical unit has ever been converted to a supercritical unit, and strongly believes it would be impractical to do so
 
Commenter 0146 stated that EPA has proposed to base its NSPS for large modified Subpart Da units on a system that has never been demonstrated; no existing subcritical unit has ever been converted to a supercritical unit, and it would be impractical and exorbitantly expensive to do so. The commenter stated that EPA may be correct that many units have been constructed that incorporate supercritical steam design, but that is irrelevant to whether an existing subcritical utility boiler's owner can, at reasonable cost, redesign the entire facility to accommodate dramatically increased steam temperature and pressures. The commenter stated that as a practical matter, it would never be technologically and economically feasible for a source to undertake such a radical boiler conversion, meaning that no source would ever qualify as reconstructed; the proposed NSPS would therefore be meaningless.
 
Commenter 0222 stated that under the proposed rule, reconstructed sources would be able to comply with an emissions limit that would be achievable at a supercritical steam turbine. The commenter stated that they do not believe that the vast majority of even supercritical units would be able to meet these standards taking into account the cost of achieving such reduction; it would not be technologically and economically feasible. The commenter stated that while supercritical steam technology itself may be a feasible technology, there is insufficient evidence to demonstrate that reconstructed supercritical units could comply with the proposed limits and there is no demonstration that a reconstructed subcritical unit can be reconstructed in the form of a compliant supercritical unit. 
 
Commenter 0183 stated that EPA's proposed standards for reconstructed units fail to recognize the extraordinary nature of converting a subcritical unit to supercritical operation. The commenter stated that such a rebuild would involve an unprecedented steam condition conversion from a lower energy steam (subcritical) to a higher energy process (supercritical). The commenter stated that not only is such a conversion not economical, it would require the replacement of pressure parts on a massive scale and result in an extremely long outage. The commenter stated that while new supercritical units can be constructed, their mere existence does not make a retrofit of existing units to this type of unit adequately demonstrated. The commenter stated that even if conversion were possible, EPA provides no evidence that the unit, particularly lignite unit, would be able to meet the standard proposed by EPA.
 
Commenter 0201 stated EPA proposed that BSER for reconstructed units is "the most efficient generating technology". The commenter agreed, in general, that efficient generating technology does represent BSER, but said the technology could vary depending on the type of unit that is in place at the facility. The commenter stated that a source should not be expected to alter their original unit design to accommodate an entirely different technology that EPA deems is more efficient. 
 
Commenter 0242 stated that they have concerns with EPA setting a limit with the assumption all units that would fall under the applicability of this section would be able to reconstruct the boiler to use higher steam temperature and pressure, even if the boiler was not originally designed to do so because there may be cases where this is not physically and/or economically feasible. The commenter stated that the United States' first ultra super critical boiler (AEP Turk) was commissioned for commercial operation in December of 2012 and was designed from the ground up. The commenter stated that there has been insufficient time to determine the long-term efficiency of this unit and to attempt to apply this type of efficiency to modified and reconstructed units is premature and without foundation.
 
Commenter 0183 stated that their engineering consultant, with substantial experience in coal-fueled power plant design and air quality control system retrofits, reports that it has never been engaged in a project where a subcritical to supercritical conversion was considered, much less undertaken. The commenter stated that setting BSER for reconstruction at the emission level for supercritical units completely eliminates the reconstruction of an existing unit as a viable business decision. The commenter stated that EPA may justify this extreme decision by saying that reconstruction is unlikely, but the likelihood of reconstruction is not a legal consideration in setting BSER under the CAA.
Several commenters (0149, 0160) stated that there is only one supercritical CFB in the world, located in Poland and EPA has not explained how a single operational unit can serve to adequately demonstrate that reconstruction of an existing unit is "achievable" as a system of emission reduction, as required by CAA section 111(a)(1). Commenter 0149 stated that from an engineering standpoint, the supercritical conditions described by EPA as BSER could, in fact, offset the advantages of using CFB technology, since CFB units are designed to operate at low temperatures, in part to minimize nitrogen oxide formation.
Commenter 0153 stated that subcritical, supercritical and CFB EGUs are so different in so many basic ways that it is not possible for EPA to justify the conclusion that it is technically feasible to convert to SCPC or CFB; even it were possible, the conversion costs would be excessive (far from reasonable) and the resulting decrease in CO2 emissions rate small in comparison to the cost. The commenter stated that the only example that EPA gives where changes in production technology are used as BSER is the Kraft Pulp Mill NSPS; pulp and paper mills are complex manufacturing facilities where production technologies are routinely improved, which is not the case for EGUs.
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. A project that entails costs that are 50% or greater of fixed capital cost that would be required to construct an entirely new EGU would almost certainly involve very significant - and very costly - investment (if not entire replacement of) in 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]. Commenters claim that such a conversion would be technically or economically infeasible. The EPA disagrees  -  however, if the owner/operator can demonstrate 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. Importantly, the EPA notes that the reconstructed unit is not required to convert a subcritical boiler to a supercritical boiler  -  the EPA does not specify any particular technology that must be used. Rather the reconstructed unit must meet a standard of performance consistent with the emission reductions achieved by the BSER. Owners/operators can consider other options  -  such as 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 emissions of air pollutants.
Too many conditions to provide meaningful comments 
Commenter 0242 stated that they cannot provide meaningful comments on this proposal. The commenter stated that the EPA proposed a small and large unit category for both utility boilers and IGCC units that are reconstructed yet acknowledges subcategorizing by primary fuel type may be necessary, that it may be necessary to restrict the smaller category to boilers so that all IGCC units would be in the large category regardless of size, or as an alternative possibility, eliminating the small category all together and subjecting all to the larger category standard. The commenter stated that there are too many variables that the EPA has introduced to evaluate as possibilities against the different standards and ranges presented and, compounding the issue is that all these options are to be considered in conjunction with 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 the EPA has not provided enough specificity for the commenter to determine the achievability of the proposed standards of performance; thus, the commenter is not able to provide meaningful comments.
The EPA often solicits comment on a range of potential regulatory approaches. The proposed standards for modified and reconstructed sources contained a range of potential options.  However, the proposal was not so complex as to make it no understandable. The number of informed and thoughtful comments received on the proposal is testament to its clarity.
Coal refuse CFB
Commenter 0182 stated that coal refuse CFB's control of acid gases for MATS compliance is based on limestone injection into the bed of the boiler, which increases CO2 emissions over those of conventional fossil fuel fired plants due to the CO2 released when the limestone calcines in the boiler and also due to the additional fuel needed to calcine the limestone with estimated CO2 increases of 8-9% based simply on MATS compliance. The commenter stated that Cross States Air Pollution Rules (CSPAR) considerations may require further increases in limestone consumption and further increases in CO2 generation. The commenter stated that coal refuse CFBs are limited to the fuel they have available within reasonable transportation distances and that this fuel has degraded in heat content and increased in sulfur content over the lives of the plants. The commenter stated that as the heat content decreases the efficiency generally decreases and as sulfur increases more limestone is required, both of which contribute to increased CO2 emissions.  Fuel changes that are forced on the plants by the changing availability of appropriate fuel make it impossible to establish a CO2 emission rate that can be consistently met. The commenter stated that coal refuse CFBs are also under pressure from the economics of operation and the reduced price of electricity in the markets in which they operate resulting in increased operation at reduced loads, which also impacts efficiency negatively. The commenter stated that while all of the above factors make it impossible for a coal refuse CFB to meet historically demonstrated levels of CO2 emissions, there is no technological solution for such plants as there aren't any scrubber technologies that can be employed; carbon capture and sequestration is not a BSER technology; and co-firing with natural gas, even where available is not BSER by EPA's own determination. The commenter stated that because of the myriad of factors that make it impossible to capture CO2 emissions from coal refuse CFBs and the lack of available BSER to capture the CO2, it is not feasible to establish performance standards for coal refuse CFBs. The commenter stated that since performance standards are not feasible, and since the Administrator is authorized, under Section 111(h) to promulgate a work practice standard in those circumstances, that a work practice standard is the only feasible approach for coal refuse CFBs to minimize CO2.
Readers are directed to response to a very similar comment in Chapter 6 of this RTC.
5.2.2 Costs, Structure of the Energy Sector
Reduced fuel costs for supercritical units not enough to make cost of generating electricity less compared to a subcritical EGU 
One commenter 0149 stated that EPA is incorrect in stating that reduced fuel costs are significant enough that the overall cost to generate electricity is actually lower for a supercritical pulverized coal EGU compared to a subcritical EGU and that the emission reductions are cost effective for larger EGUs.  The commenter stated that a 2006 paper evaluating the performance of existing supercritical and subcritical units noted that when deciding between building a supercritical or a subcritical unit, reduced fuel costs (where supercritical processes have an advantage over subcritical due to their higher efficiency) was not the only variable for operators to consider. See Anthony J. Carrino and Richard B. Jones, Modeling New Coal Projects: Supercritical or Subcritical?, Power Engineering (Nov. 1, 2006), The commenter stated that the lower fuel costs of a higher efficiency supercritical unit have to be balanced against a supercritical unit's higher initial capital costs, higher operation and maintenance costs and more frequent outage rates. The commenter stated that the authors also observed that, while a supercritical unit can have a five to 10 percent efficiency advantage over a subcritical unit, part of this advantage can be attributed to economic dispatch models keeping the supercritical units at a higher load level than subcritical units. The commenter stated that given EPA's expected shift towards greater dispatch of existing natural gas-based units under the proposed section 111(d) guidelines, which will likely decrease coal-based unit utilization rates, it is not clear what cost advantage a supercritical unit would realistically provide.
The most important difference between subcritical and supercritical units in this case is the difference in the emissions of CO2. As noted, the CO2 emissions from a well performing supercritical unit are significantly lower than those of a well performing subcritical unit. Triggering the reconstruction provision is a significant economic hurdle - and it has only rarely been done. However, in the event that a unit does trigger the reconstruction provisions, the reconstructed unit would not required to convert a subcritical boiler to a supercritical boiler  -  the EPA does not specify any particular technology that must be used. Rather the reconstructed unit must meet a standard of performance consistent with the emission reductions achieved by the BSER. Owners/operators can do so by installing a new supercritical boiler, or by converting a large subcritical boiler to supercritical conditions or by utilizing other options  -  such as 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 emissions of air pollutants. In any case, per 40 CFR 60.15, if the owner/operator can demonstrate 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.
 
To evaluate cost of BSER, EPA should consider conversion cost from a subcritical to a supercritical boiler 
Commenter 0214 stated that EPA did not appropriately evaluate the cost of its BSER determination for reconstructed boilers and IGCCs. The commenter stated that in justifying the cost reasonableness of an existing subcritical unit converting to a supercritical unit, the Agency compared the capital cost of a new subcritical pulverized coal boiler and a new supercritical pulverized coal boiler. The commenter stated that this comparison is inappropriate and EPA must consider the incremental costs incurred to implement BSER, which is the conversion cost from a subcritical to a supercritical boiler. The commenter stated that they believe an appropriate cost analysis will demonstrate that EPA's BSER cannot be implemented at a reasonable cost.
 In the event that a unit does trigger the reconstruction provisions  -  which, for EGUs, has only rarely occurred  -  the reconstructed unit would not be required to convert from a subcritical boiler to a supercritical boiler  -  the EPA does not specify that any particular technology must be used to meet the final standard. Rather the reconstructed unit must meet a standard of performance consistent with the emission reductions achieved by the BSER. Owners/operators can do so by installing a new supercritical boiler, or by converting a large subcritical boiler to supercritical conditions or by utilizing other options  -  such as 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 emissions of air pollutants. Regarding cost  -  a reconstruction project that exceeds 50% of fixed capital cost that would be required to construct an entirely new EGU would almost certainly involve very significant cost and likely considerable investment in (if not entire replacement of) the boiler. At that time, conversion from a subcritical boiler to a supercritical boiler can be done. In any case, per 40 CFR 60.15, if the owner/operator can demonstrate 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. 
Proposal would necessitate costly conversion from subcritical to supercritical unit and create a disincentive for upgrades
Several commenters (0149, 0183) stated that the proposal would be too costly and a disincentive to upgrade units.
Commenter 0183 stated that the conversion of a coal-fired power plant from subcritical steam conditions to supercritical steam conditions, which EPA's standard would essentially require, means the steam pressure must be increased from a typical operating pressure of 2,400 psig to 3,600 psig. The commenter stated that while some of the plant components and a portion of the steam cycle equipment could be retained, the following pieces of equipment would likely require replacement if converting a subcritical unit to a supercritical unit: 

- Boiler pressure parts (water walls, economizer, superheaters, reheaters, etc.)
- High pressure steam turbine
- Main steam piping
- Boiler feed pump and driver
- High pressure feedwater heaters
- Boiler feed piping

The commenter stated that these components, in aggregate and installed at the same time during a one-time retrofit of a unit, represent a significant investment and one that most operators would decline to make. The commenter stated that their engineering consultant estimates the current cost to replace the equipment listed above to be between $300 million to $500 million for a typical unit.
The commenter is concerned about the cost to replace the listed equipment. However, a reconstruction project that exceeds 50% of fixed capital cost that would be required to construct an entirely new EGU would almost certainly involve very significant cost and likely considerable investment in (if not entire replacement of) the boiler  -  including, likely, many of the pieces of equipment listed. 
Required conversion from subcritical to supercritical means emission standard is not economically viable and would cause early retirement of coal-fired units 
Commenter 0183 stated that by requiring the conversion from subcritical to supercritical, EPA is establishing an emission standard that is not economically viable for an existing source. The commenter stated that where a generator might otherwise consider building a new supercritical unit, the New Unit Proposal eliminates that as a viable alternative; thus the reconstruction standard effectively would require the replacement of the unit and appears to force early retirement of coal-fueled equipment. The commenter stated that this is not setting a standard of performance, it is mandating shutdown. The commenter stated that, if subjected to the proposed standard, those coal-fueled EGUs that invested in control equipment to comply with the MATS would be left with stranded investments, having spent millions of dollars to remain operational and comply with EPA's other rules.
Commenter 0242 stated that they are concerned that some changes required to meet the standard of performance under this proposal or under the proposal for existing sources, such as a reconstruction of a subcritical unit to a supercritical unit, may necessitate replacement of the entire footprint at the unit/facility. The commenter stated that they are very concerned over the EPA's interpretation under this proposal with regards to when reconstructed units become new units. The commenter stated that the EPA is proposing that replacement of the entire footprint would qualify the change as a new unit and therefore subject the unit to the new unit CSS provisions. The commenter stated that the EPA must be careful to ensure changes made to a unit that are necessary to comply with these rules (or the Section 111(d) rules) are not excluded as an option thereby creating a disincentive for meaningful reductions in CO2 that could occur.
 
Commenter 0242 is concerned that this proposal, in conjunction with the Section 111(d) proposal, will provide a disincentive for coal-fired plant owners to commit to a major upgrade of their plants to gain efficiency. According to the commenter, upgrading a supercritical boiler to an ultra-supercritical would likely exceed the 50 percent cost threshold necessary to trigger the definition of "reconstruction." The commenter stated that this rule then requires the source to submit information to the EPA for a determination of whether the proposed upgrade qualifies as a "reconstruction"; in making that determination EPA states that, "it is EPA's view that a unit that entirely, or for all practical purposes, completely replaces an existing sources by being constructed on the replaced source's existing footprint would also constitute a newly constructed source."  The commenter stated that under this interpretation, any regulated entity that intends to invest in an upgrade to ultra-supercritical for efficiency purposes and to decrease their heat rate, will then qualify as a "new" source and be subject to the proposed CCS obligations. The commenter stated that while the EPA has stated that they do not expect any new coal-fired power plants to be built, this interpretation of reconstruction will effectively prevent any established and well demonstrated advancements in efficiency at existing plants too, reinforcing the concept that the Section 111(b) and Section 111(d) rules are designed to reduce the use of, or eliminate, coal-fired power plants.
The commenters confuse a "reconstruction" with smaller projects to improve the heat rate or even modifications. A reconstruction project is one that exceeds 50% of fixed capital cost that would be required to construct an entirely new EGU.  Such projects have been historically rare in EGUs. Utilities have not undertaken such projects in the past as a means of improving efficiency or heat rate or to prolong the operating life of a unit.  Thus this final standard will not discourage investment in efficiency projects.
EPA solicited comment on having an upper capital cost threshold for reconstruction  
Commenter 0192 opposed such an upper threshold for reconstruction stating that regardless of the scope of capital expenditures associated with a reconstruction project, an existing facility is always limited to some degree by prior design decisions and, therefore, lacks the same degree of flexibility that is available to newly constructed sources. The commenter stated that while a newly constructed coal-fired EGU could, in theory, be designed in a manner that could accommodate partial CCS technology, the same is not true for an existing source undergoing modification. The commenter stated that, for example, an existing facility may lack the space to incorporate a carbon capture system and may lack access to the pipeline infrastructure and CO2 storage areas needed to implement CCS; thus, as long as a project qualifies as a reconstruction project under existing regulatory criteria rather than as new construction, it should be subject to the reconstructed source standard. The commenter stated further that establishing an upper threshold for reconstruction could produce perverse and unintended consequences as reconstruction projects are typically designed to maximize economic and environmental benefits, but establishing an upper threshold may cause facilities to adopt less efficient reconstruction plans in order to stay below the upper threshold. The commenter stated that the EPA must avoid this outcome by treating all reconstructed sources equally. 
Commenter 0142 stated that in response to the EPA requests for comment on an upper capital cost threshold for reconstruction, they believe there is no need to identify an upper capital cost threshold for reconstruction, if the EPA is confident in their projection that there will be very few units that reconstruct with capital costs exceeding 50 percent. The commenter stated that establishing any range of capital costs is arbitrary and its only purpose is to justify a reconstruction standard which is significantly less stringent than the new source standards proposed in January 2014. The commenter stated that the EPA makes the argument that it has historically considered reconstructed sources as new sources, yet now the EPA struggles to justify a basis for not making reconstructed sources meet the new source standard. The commenter stated that the root problem is that the EPA established an unreasonable new source standard that new sources and reconstructed sources cannot meet. The commenter stated that the EPA offers very little justification or reconciliation as to why BSER for reconstructed sources (which the EPA assumes to be new sources) is based upon supercritical steam cycle efficiency, yet the BSER for newly constructed sources is based upon partial carbon capture and sequestration.
 
Commenter 0259 stated that concerning EPA's request for comments on specific changes, they support EPA adjusting the upper capital cost threshold to the higher end of the 75-100 percent range. The commenter stated that the original 50 percent threshold contained in Part 60 was established in 1975 and the cost of components has increased significantly since that time and it is important to update the regulations. The commenter stated that furthermore, given the spatial constraints existing units have with regard to installing controls to meet the NSPS, it is appropriate for EPA to use the higher end of the percentage range to reduce the likelihood that the reconstruction requirements are triggered.
The EPA is not finalizing an upper cost threshold on the definition of reconstruction. The determination of whether or not an existing source has triggered the Reconstruction provisions is done as specified in 40 CFR 60.15(d), (e), and (f).
5.2.3 Incentive for Technological Innovation
EPA's objective is reducing air pollution, not incentivizing sources to avoid the purpose of the CAA 
Commenter 0282 stated that they were disconcerted to see EPA declare that the Proposed Rule is intended to provide an incentive, and the information needed, for existing sources to structure their actions to achieve their operating and business goals without triggering the modification or reconstruction standards. The commenter stated that incentivizing sources to evade the purpose of the Clean Air Act, i.e., protecting human health and welfare from dangerous, and in the case of climate change, catastrophic pollutants, and to elude the new source performance standards in particular, decidedly is not the business of the nation's Environmental Protection Agency. The commenter stated that to the contrary, it is EPA's business to reduce air pollution to the maximum feasible extent, and we trust EPA will continue to do so in finalizing the Proposed Rule.
Commenter 0263 stated that requiring implementation of the identified energy efficiency improvements is redundant and will stifle innovation. The commenter stated that EPA is already proposing that the CAA section 111(d) implementing authority determine a unit-specific emission limit based on the results of an energy assessment; companies will be responsible for complying with the limit. The commenter stated that if an innovative approach to meeting the limit is later determined to be technically achievable and economically favorable, then the companies should be afforded the opportunity to use the innovative approach. The commenter stated that requiring implementation of a specific energy efficiency improvement may forestall the opportunity to install a better performing technology or work practice. The commenter stated that it is foreseeable that the results of an energy improvement audit may conflict with the requirements of a CAA 111(d) plan if the audit is performed before a comprehensive 111(d) compliance strategy is in place; in such instances, the energy efficiency improvement would not be allowed to operate over its depreciable life.
The EPA most certainly has not finalized standards that incentivize sources to evade the purpose of the Clean Air Act.  The suite of CAA 111 rules that are being finalized together will assure that fossil fuel-fired EGUs  -  whether they are new, modified, reconstructed, or existing  -  will achieve GHG emission reductions consistent with the best system of emission reduction that has been adequately demonstrated. Further, the EPA is not finalizing standards based on the results of energy efficiency audits. 
Determination of the Level of the Standard
Limits not achievable 
Several commenters (0149, 0150, 0162, 0178, 0193, 0215, 0218, 0239, 0249, 0257, 0260, 0284) stated that the proposed limit of 1,900 lb CO2/MWh for large reconstructed boilers and 2,100 lb CO2/MWh for small reconstructed boilers cannot be achieved.
Several commenters (0195, 0199, 0260) stated that EPA should finalize emissions limits on the upper end of EPA's proposed ranges. Two commenters (0260, 0199) urged EPA to adopt the highest standards within the proposed ranges but on a gross output basis. Commenter 0260 stated that the highest proposed standards more accurately account for unit cycling, performance degradation, and other factors. The commenter stated that if EPA does not adopt the higher performance standards, EPA should consider using a sliding scale based on generation thresholds to determine the performance standard for EGUs on an individualized basis; for example, the highest limit should apply to units operating at low capacity factors (i.e., in the 33 percent to 45 percent range). The commenter stated that the emissions limit could be reduced incrementally as the generation threshold increases. The commenter stated that adoption of standards on the high end of the proposed ranges, or a sliding scale approach, will account for the impacts of the widespread re-dispatch that is expected to occur pursuant to EPA's proposed Clean Power Plan. The commenter stated that if states continue to increase the amount of renewable energy, as required by EPA's Proposed Clean Power Plan, fossil-fired units are more likely to serve as load-following units in support of the highly variable generation from renewable sources.
Commenter 0260 stated that the increasing dispatch of NGCCs would reduce the dispatch of coal-fired EGUs, which results in lower heat rate performance at those units. The commenter stated that a coal-fired EGU's heat rate is highest (i.e., least efficient) at the minimum load point at which the unit can safely operate and at low load points, many plant components operate below their most efficient design points. The commenter stated that heat rate decreases (i.e., improves) in a non-linear fashion as the load increases until it reaches an optimal load point; the heat rate may then increase slightly as load approaches the maximum capability of the unit. According to the commenter, the heat rate at the lowest load can be 15 percent to 20 percent higher than at the optimum load point. 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. The commenter included a table that shows the average heat rate for varying load scenarios at a coal-fired EGU, demonstrating the impact of lower load operations on heat rate. The commenter recommended 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 or employ a sliding scale approach.
Two commenters (0257, 0284) stated that, as discussed in the Cichanowicz Heat Rate Report, achieving 1,900 lbs CO2/MWh-net for large coal-fired boilers may be achievable for some individual new state-of-art supercritical boilers, but it is not achievable for existing units undergoing reconstruction. Commenter 0284 stated that even relatively new supercritical units may not achieve 1,900 lbs CO2/MWh-net, depending on duty cycle, local environmental siting conditions, and water cooling method. Commenter 0257 stated that of the 183 large electric generating units identified to likely continue to operate in future decades and potentially subject to the proposed standards for modified and reconstructed sources, the proposed rate of 1,900 lb CO/MWh was achieved by only 40 units (20 percent). The commenter stated that the proposed NSPS for reconstructed small Subpart Da units is based on an emission rate that no small supercritical unit has ever achieved. The commenter stated that as EPA acknowledges, its selected best performing facility for this category had an emission rate of 2,320 lb CO2/MWh, and the proposed NSPS of 2,100 lb CO2/MWh actually reflects a "normalized" emission rate based on improvements in unspecified design factors for a "theoretical reconstructed facility." The commenter stated that they do not believe that an NSPS should be based on the performance of a "theoretical reconstructed facility". The commenter, therefore, request that EPA identify variable conditions that might contribute to the amount of expected emissions, establish that the test data relied on are representative of potential industry-wide performance, given the range of variables that affect the achievability of the standard, and re-propose the standard accordingly. 
Commenter 0215 stated that the emission limits EPA proposes cannot be achieved by existing units undergoing reconstruction. Commenter said new units may not be able to meet the limit for large units, and no small supercritical unit has ever achieved the limit EPA proposes for small units. 
Commenter 0259 stated that they cannot support any of the range of limits proposed because, based on historical records, these limits could not be consistently achieved. The commenter stated that reconstructed units face design and technical constraints that are not present in new construction, and thus cannot achieve as stringent a level of emission reductions; accordingly, the reconstructed emission limits should be set higher to account for this reality. The commenter stated that older units do not run as efficiently as new units; this factor also suggests that reconstructed units will not be able to achieve as stringent emission levels as new units and EPA has not suggested that the high end of the ranges of permissible emission limits is within a zone of reasonableness, thus setting higher limits for reconstructed units should not violate the statute.
Commenter 0259 stated that, in response to EPA's request for comment on whether other factors should be considered in setting emission limits, they request that consideration be given to the fact that not all coal-fired EGUs are pulverized coal units. The commenter's Sheldon Station unit is a cyclone unit that burns larger pieces of coal and is less efficient than a pulverized coal unit; accordingly, it (and presumably other cyclone units) will not be able to meet even the high end of the identified range for units under 2,000 MWBtu/h, of 2,3001b CO2/MWh net. The commenter recommended that a standard for cyclone units be set at 2,600 lb CO2/MWh net to recognize the differences between them and pulverized coal units.
Commenter 0263 that the emission limits as proposed for reconstructed units are not achievable based on real-world performance of regulated sources. The commenter stated that the best performing unit in Wyoming with a heat input greater than 2,000 MMBtu/hr exceeds the proposed limit of 1,9001b CO 2/MW-hr by nearly 11 percent despite significant recent upgrades that have targeted improvements in energy efficiency. The commenter stated that a smaller unit that would be subject to the proposed limit of 2, l 001b CO 2 /MW-hr currently exceeds the limit by 12 percent, and that unit is less than five years old; the plant is already energy efficient and therefore requiring additional reductions is not practical. 
 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. 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 that 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 also 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. 
 The commenters claim that the final emission standard for reconstructed sources cannot be achieved. 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. 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.
More stringent standard for existing sources is backwards
Two commenters (0157, 0183) stated that with this proposal, EPA has reversed the progression of stringency. The commenter stated that where one would expect to see the most stringent limits on brand new, yet-to-be-constructed sources, in fact the lowest (most stringent) limits are applied to existing units under 111(d), and units yet to be constructed must meet only a rate of 1,110 lb CO2/MWh-net, and that with carbon capture and sequestration; and modified or reconstructed units would have to meet a maximum emission rate of 1,900 lb CO2/MWh-net. EPA's more stringent standard for existing sources is backwards and departs from past agency interpretations without explanation.
Comments regarding the stringency of the 111(d) existing source standards are addressed in the 111(d) final Emissions Guidelines preamble and are out-of-scope for this RTC.
Unreasonable to apply standards of performance for reconstructed sources to modified sources 
Commenter 0192 stated that they do not support EPA's proposal to apply the standard of performance for reconstructed sources to modified sources. The commenter stated that first, the standard of performance for reconstructed sources is arbitrary and capricious; second, it is based on installation of an ultra-supercritical boiler, and it is unreasonable to apply those emission limits to modified sources after EPA rejected boiler upgrades as BSER for modified sources. The commenter stated that EPA must identify a numeric limit that is related to heat rate improvements to ensure that sources that have already implemented available heat rate improvements will not have to find other ways to further reduce CO2 emissions in the event that they undergo a modification.
EPA did not propose to apply the standard of performance for reconstructed sources to modified sources.
Emissions standards are too lenient 
Commenter 0282 stated that the proposed emission standards for modified or reconstructed coal-fired power plants are too lenient. The commenter stated that EPA may not set any standard for modified and reconstructed sources other than the proposed 111(b) standard for new sources. The commenter stated that the standards for reconstructed large and smaller boilers and IGCCs are insufficiently stringent and legally unjustifiable. 
Commenter 0244 stated that the proposed limits are too lenient and that many existing coal-fired EGUs already meet these emission limits, whereas the purpose of the NSPS program is to advance the technological vanguard, not entrench the status quo. The commenter stated that EPA must ensure that reconstructed EGUs satisfy a performance standard that is both sufficiently rigorous and technologically forward-looking. Our proposal for reconstructed sources is the application of the 111(b) new source standard. [The commenter referred EPA to their comments for the agency's proposed new source rule, attached as Exhibit 1 and incorporated by reference herein, for a detailed discussion of the issue.] The commenter stated that in keeping with the proposed new source standard, EPA should designate efficient generation technology with partial CCS as BSER for reconstructed steam EGUs and should impose a performance standard at least as stringent as 1,200 lbs CO2/MWh on a net output basis. The commenter stated that partial CCS is economically feasible and technologically achievable for reconstructed units and should be mandated for all such facilities. Reconstructed units have historically been extremely rare. The commenter stated that they see little reason why a plant operator would choose to undergo such a project if not for the express purpose of extending the life of an aging plant rather than constructing a new facility that would be subject to a rigorous new source standard, a scenario not in keeping with the goal or purpose of the Clean Air Act; the statute grants EPA the tools to ensure that it does not occur. The commenter stated that the agency must therefore utilize the tools at its disposal and prevent environmentally harmful life extension projects by adopting our proposal for reconstructed steam EGUs.
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. A project that exceeds 50% of fixed capital cost that would be required to construct an entirely new EGU would almost certainly involve significant cost. The determination of whether or not an existing source has triggered the Reconstruction provisions is done as specified in 40 CFR 60.15(d), (e), and (f).
Support mass-based standard 
Commenter 0282 stated that they support EPA's choice of a mass-based standard for the Proposed Rule and the proposed 111(b) standards and believe it is critical that the section 111(d) standards be expressed on a mass basis rather than a rate basis, primarily to provide an actual cap to emissions rather than a rate-based limitation that allows emission to increase depending on energy demand, but also to avoid difficult conversion and intra-state trade issues that could allow system gaming. The commenter stated that in addition, the inconsistency between a rate-based section 111(d) plan and a mass-based section 111(b) standard can be avoided by requiring mass-based section 111(d) standards.
The EPA did not propose mass-based standards in any of the proposals under CAA 111(b).
5.3.1 Large Units Standard of 1,900 lb CO2/MWh; solicited comment on range of 1,700-2,100 lb CO2/MWh
Limit is unachievable
Commenter 0173 stated that a performance standard of 1,900 lbs CO2/MWh for large reconstructed coal-fueled EGU boilers with a heat input greater than 2,000 MMBtu/h is unachievable for existing coal-fueled utility boilers undergoing a reconstruction and is also too stringent for new coal-fueled power plants. The commenter stated that this was demonstrated by an analysis of CO2 emissions rates, which the commenter submitted to EPA as part of its comments on the CO2 performance standards for new coal-fueled EGUs. The commenter stated that the study reviewed 21 EGUs that began operation after January 1, 2007 and used data from CAMD. The commenter stated that the analysis demonstrated that new coal-fueled EGUs can achieve emission rates of 1,915 lbs CO2/MWh for supercritical boilers burning bituminous and subbituminous coals; 2,080 lbs CO2/MWh for subcritical boilers burning bituminous and subbituminous coals; and 2,150 lbs CO2/MWh for all boiler types burning lignite coal. The commenter stated that as demonstrated by these emissions rates, a new state of the art coal-fueled power plant cannot consistently meet the 1,900 lbs CO2/MWh standard for large reconstructed sources; even the most efficient new large supercritical units may not be able to achieve 1,900 lbs CO2/MWh-net due to duty cycle, local environmental siting conditions, water cooling method, and auxiliary power demands. The commenter stated that if too stringent for new state of the art facilities, a performance standard of 1,900 lbs CO2/MWh is clearly unachievable for reconstructed facilities. The commenter did not specifically address the CO2 standard of 2,100 lbs CO2/MWh for smaller reconstructed units, but stated this standard is also invalid and should be withdrawn for the reasons highlighted in the UARG comments. 
Commenter 0197 disagreed with the 1,900 lb CO2/MWh-net limit for larger coal-fired units.
The achievability of the final standards has been addressed in previous comments.
Performance standards are not supported by an adequate technical analysis 
Commenter 0173 stated EPA's proposed performance standards for modified and reconstructed sources are supported by inadequate technical analysis and an inaccurate interpretation of an engineering study. The commenter stated that to support a CO2 emissions rate of 1,900 lbs CO2/MWh for reconstructed utility boilers, EPA relied on the performance of a single EGU and to justify a two-percent heat rate improvement standard for modified utility boilers, EPA incorrectly interpreted an engineering analysis conducted by Sargent & Lundy.
Commenter 0242 stated that EPA's consideration of ranges as low as 1, 700 or 1,900 lb CO2/MW-h-net is irrational. The commenter stated that even the EPA acknowledges a rate of 1,700 lb CO2/MWh-net could potentially be met by an EGU using advanced ultra-supercritical steam conditions. The commenter stated that although this technology has been discussed, the actual alloys needed to construct such a unit are still being researched and developed and there are no long term data at the existing ultra-supercritical unit operations (AEP Turk) to assess long-term viability. The commenter stated that these standards should be established consistent with the requirements of CAA section 111 (b), so that these proposed standards reflect the degree of emission limitation achievable through the application of BSER that has been adequately demonstrated. The commenter stated that the EPA is proposing standards on unproven technology in direct conflict with the purpose and intent of BSER. 
Comments on the technical basis for the standards for modified steam generating EGUs have been addressed in Chapter 6  -  including critiques of the use of the Sargent & Lundy study. The EPA stands by the technical basis for the standard for reconstructed EGUs and maintains  -  as we have discussed in response to many other comments  -  that they are achievable.
EPA reliance on information from one unit, Weston Unit 4, to support the proposed 1,900 lbs CO2/MWh standard is inappropriate 
Commenters 0173, 0195 stated that EPA relied on emissions information from one unit, Weston Unit 4, to support the proposed 1,900 lbs CO2/MWh standard. Commenters said EPA's analysis failed to demonstrate that the proposed performance standard is achievable by all affected coal-fueled reconstructed EGUs based on a wide range of operating conditions, including duty cycle, local environmental siting conditions, water cooling method, and auxiliary power demands. EPA provided no explanation as to why Weston 4 is a representative plant of the fleet or an appropriate basis for a performance standard, and further, if undergoing a reconstruction, could a reconstructed unit achieve an emissions rate similar to the one achieved by Weston 4. Weston 4 is a new unit built in 2008 that employs supercritical generating technology that is not realistically applicable to existing subcritical boilers, and even if applicable, may not achieve the same performance due to the operation of the plant and the size of the unit. EPA's analysis ignores the fact that the CO2 emissions rate for any particular EGU is determined by many design parameters, including thermodynamic steam cycle, coal rank and quality, EGU cooling system, EGU geographic location and ambient conditions, EGU duty cycle and load generation flexibility requirement, EGU size, and installed pollution control technology. The commenter stated that EPA has therefore conducted an inappropriate analysis in establishing the emissions rate standard for reconstructed EGU boilers and as a result, the selection of supercritical technology as the basis for BSER for large EGUs has not been demonstrated and does not meet the requirements of section 111.
Commenter 0146 stated that EPA has not justified the proposed 1,900 lb CO2/MWh-net for large units. The commenter stated that for large units, although EPA was able to identify one recently constructed unit that achieved a 99 percent confidence emission rate below 1,900 lb CO2/MWh=net, it has provided no information on the emissions performance of other similar units. The commenter stated that a rate of 1,900 lbs CO2/MWh-net may be achievable for some individual large, new state-of-the-art supercritical boilers, but it may not be achievable for many other new supercritical boilers depending on duty cycle, local environmental siting conditions, water cooling method, and auxiliary power demands, and it is certainly not achievable for existing units undergoing reconstruction. 
As EPA shown in previous response  -  and in response to similar comments in Chapter 6 of this RTC  -  the AEP Turk facility has demonstrated an ability to meet the final standard of 1,800 lb CO2/MWh-g. In addition, affected reconstructed units can consider alternative compliance options such as natural gas co-firing to meet the final standard. In any case, per 40 CFR 60.15, if the owner/operator can demonstrate 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.
For the possible range of 1700 to 2100 lb CO2/MWh-net emissions for large units, a limit of 2100 lb CO2/MWh-net is more reasonable 
Commenter 0169 stated that regarding EPA's request for comments on a range of 1700 to 2100 pounds (lb) CO2/MWh-net emissions for large units, the commenter said that a limit of 2100 lb CO2/MWh-net is a much more reasonable emission rate than 1700, and should be achievable with varying conditions. The commenter stated that an EGU cannot be expected to operate under ideal conditions all the time. The commenter stated that Figure 7 of the BSER Memo clearly shows that anything less than 2100 lb CO2/MWh-net is not consistently achievable, and BSER is clearly required to be achievable under routine operating basis, not only under ideal operating conditions. 
The EPA has finalized a standard of 1,800 lb CO2/MWh-gross, which the EPA finds to be achievable.
Technical justification for CO2 emission standards at the lower end of the range EPA is considering for reconstructed sources is not sufficient 
Commenter 0142 stated that they do not agree that there is sufficient technical justification to establish CO2 emission standards at the lower end of the range the EPA is considering for reconstructed sources. The commenter stated that EPA proposed the 1,700 lb CO2/MWh-net standard based upon the ultra-supercritical steam cycle and they are aware of just one ultra-supercritical coal-fired boiler located in the U.S., which only recently commenced operation in December 2012. The commenter stated that they are unaware of any reconstructed subcritical or supercritical units being reconstructed to an ultra-supercritical unit that has demonstrated it can achieve 1,700 lb CO2/MWh-net. The commenter stated that EPA has no basis for establishing an emission limit without data supporting its achievability. 
Commenter 0215 stated without adequate basis, EPA proposes that sources with a heat input above 2,000 MMBtu/h (large units) must meet an emission limit of 1,900 lb CO2/MWh-net while sources with a heat input equal to or less than 2,000 MMBtu/h (small units) must meet an emission limit of 2,100 lb CO2/MWh-net. Commenter referred to one of their attachments, a consultant's report, that stated achieving 1,900 lbs CO2/MWh-net for large coal-fired boilers may be achievable for some individual new state-of-the-art supercritical boilers, but it is not achievable for existing units undergoing reconstruction. See J. Edward Cichanowicz & Michael C. Hein, "Critique of EPA's Proposed CO2 NSPS For Modified and Reconstructed Subpart Da Sources," at 1 (Oct. 13, 2014). Commenter said even relatively new large supercritical units may not achieve 1,900 lbs CO2/MWh-net, depending on duty cycle, local environmental siting conditions, water cooling method, and auxiliary power demands. 
Commenter 0215 mentioned that the proposed NSPS for large reconstructed Subpart Da boilers is based on the "99% Confidence Emission Rate" of one recently constructed unit burning subbituminous coal, and EPA does not explain what a "99% Confidence Emission Rate" is or how it is calculated.
The EPA is not finalizing the lower end of the range that was proposed. The EPA has finalized a standard of 1,800 lb CO2/MWh-gross (approximately 1,900 lb CO2/MWh-net), which the EPA finds to be achievable by a large reconstructed source.
5.3.2 Small Units Standard of 2,100 lb CO2/MWh; solicited comment on range of 1,900-2,300 lb CO2/MWh
Standard does not reflect BSER and is not achievable 
Several commenters (0146, 0195, 0215, 0218) stated that EPA did not provide justification for the proposed standard for smaller reconstructed units.
Commenters 0146, 0195, 0215 stated that with regard to smaller reconstructed EGUs, while EPA selects subcritical technology as BESR for these units, the Agency sets the numerical limit at a level that is not even achieved in practice by the new unit used to set the standard. The commenters stated that the TSD explains that for the Wygen III unit, "even though the emission rate for the Wygen III facility is 2,320 lb CO2/MWh-net, based on the normalization of that data the EPA has determined that the 12-month emission limit that corresponds to BSER is 2,100 lb CO2/MWh-net for reconstructed EGUs with a base load rating of 2,000 MMBtu/h or less." The commenters stated that although EPA itself does not have information regarding the design factors and operation and maintenance practices that form the basis of this normalized emission rate, the Agency inexplicably assumes that a reconstructed EGU would be able to incorporate both of these into the design and operation and maintenance practices of a reconstructed EGU. The commenters stated that putting aside the fact that EPA uses a new unit to set a standard for reconstructed units, EPA needs to finalize a standard that reflects what a subcritical unit achieves in actual operation; otherwise, the standard will not reflect BSER and is unlawful. Commenters added EPA has no authority to base an NSPS on the performance of a "theoretical reconstructed facility." 
Commenter 0215 added the Agency must "(1) identify variable conditions that might contribute to the amount of expected emissions, and (2) establish that the test data relied on by the agency are representative of potential industry-wide performance, given the range of variables that affect the achievability of the standard." Sierra Club v. Costle, 657 F.2d 298, 377 (D.C. Cir. 1981). EPA may not rely on "mere speculation or conjecture," as it has done here. See Lignite Energy Council v. EPA, 198 F.3d 930, 934 (D.C. Cir. 1999) (per curiam). Commenter said given EPA's failure even to attempt to justify its proposed NSPS for reconstructed units in accordance with these legal criteria, it should be withdrawn.
Triggering the reconstruction provision is a significant economic hurdle - and it has only rarely been done. However, in the event that a unit does trigger the reconstruction provisions, the EPA does not specify any particular technology that must be used. Rather the reconstructed unit must meet a standard of performance consistent with the emission reductions achieved by the BSER. Owners/operators can do so by installing a new well-performing subcritical boiler, or by upgrading the existing subcritical boiler to best performing conditions or by utilizing other options  -  such as the use of natural gas co-firing to achieve the final emission limitation. Natural gas co-firing has long been recognized as an option for coal-fired boilers to reduce emissions of air pollutants. In any case, per 40 CFR 60.15, if the owner/operator can demonstrate 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.
Subcategories
Additional subcategorization is warranted based on IGCC and utility boilers, boiler type and coal rank 
Several commenters (0169, 0173, 0182, 0183, 0192, 0277, 0203, 0222) stated that there was a need for EPA to establish subcategories with different emission limits.
Commenter 0173 stated that EPA's proposed performance standards are subcategorized in two general ways: first, EPA subcategorizes between utility boilers and natural gas turbines; and second, within the utility boiler category, EPA subcategorizes based on plant size. The commenter stated that in the past, EPA has routinely subcategorized coal-fueled utility boilers with more granularity than they are subcategorized here and as an example, cited the MATS where EPA subcategorized coal units based on coal rank and whether the plant was a boiler or an IGCC power plant. The commenter stated additional subcategorization is warranted based on boiler type and coal type for both modified and reconstructed utility boilers. The commenter stated that different types of boilers that use coals of different rank have significantly different CO2 emissions rates on average with emissions rates varying by more than 200 lbs CO2/MWh between the highest and lowest emitting category. The commenter stated that according to the DOE, coal plant efficiency varies from 27 percent in the lowest decile to 37 percent in the highest.
Commenter 0183 stated that EPA fails to acknowledge the fundamental design differences between IGCC units and coal-fueled units that use a more traditional coal boiler. The commenter stated that significant process differences exist between IGCC and pulverized coal boilers (subcritical, supercritical, and ultra-supercritical) or fluidized bed boilers and the differences are conceded in EPA's own report. According to the commenter, similarities between IGCC and more traditional pulverized coal or fluidized bed electric generating units are limited to the raw fuel (coal) consumed and the electricity produced. The commenter stated that the intervening process varies greatly as pulverized coal and fluidized bed units burn fuel and generate heat to produce steam for electricity production, while IGCC units gasify fuel to produce syngas (hydrogen and carbon monoxide) which is ultimately combusted in gas turbines. The commenter stated that IGCC may be viewed as a process similar to that of a gas-fueled combined cycle unit closely coupled with a multiple stream chemical plant, whereas a coal-fueled boiler is a traditional Rankine cycle plant utilizing a traditional steam turbine and conventional pollution controls; these are fundamentally different source types.
Commenter 0183 stated that it is inappropriate to set a CO2 emission standard that applies to both IGCC and coal-fueled boilers (i.e., pulverized coal or fluidized bed). The commenter stated that these technologies share little with each other except that both produce steam from releasing energy stored within fossil fuels and different standards are necessary to reflect the different processes and emissions profiles of these different types of sources. The commenter stated that it is impossible to create a "best system of emission reduction" that takes into account the required factors (cost, energy requirements, etc.) for a category that lumps together coal-fueled boilers and IGCC units because the economic and operational considerations for these units are totally different. 
Commenter 0183 stated that an IGCC unit uses coal as a feedstock, not as a fuel, and the equipment within the unit is fundamentally designed to function differently than a traditional pulverized coal unit. The commenter describes the IGCC process and contrasts it with that of a coal-fueled boiler. The commenter stated that these process differences between an IGCC and a coal-fueled boiler produce entirely different emission "footprints" that drive distinct emission control strategies and thus cannot be lumped together into a single CO2 emission target. The commenter stated that the Clean Air Act 1977 Conference Report authorized the EPA to "set a range of pollutant reduction that reflects varying fuel characteristics," and, historically, the EPA has used that discretion to treat various fuels, designs, and circumstances differently in fashioning emission limitations. The commenter stated that the Modified and Reconstructed Unit Proposal is inconsistent with how these same units are categorized under other overlapping CAA programs and unlike other CAA programs, the Modified and Reconstructed Unit Proposal treats coal-fueled boilers and IGCC plants interchangeably simply because they both use coal, despite their significantly different designs, operations, and emissions footprints. The commenter stated that EPA provides no explanation as to why these very different EGU designs should be treated identically under a single source category; considering the differences between coal-fueled boilers and IGCC plants, the use of a single source category for both cannot be sustained.
Commenter 0183 stated that EPA must further subcategorize modified and reconstructed sources based on coal type and boiler type. The commenter stated that Cichanowicz and Hein analyzed data from a larger data set than was used by EPA and found that coal composition, load factors, boiler design, and coal moisture all affect CO2 emissions. The commenter stated that with regard to moisture content, Powder River Basin subbituminous fuel may contain 30% moisture compared to 6% moisture content for a typical eastern bituminous coal, resulting in a 3-5% thermal efficiency penalty due to the amount of fuel that must be com busted to generate a fixed amount of steam. The commenter stated that despite this thermal penalty, Cichanowicz and Hein's statistical analysis (using EPA's methodology) demonstrates that boiler steam conditions are more relevant for creating categories for CO2 emissions than whether the coal is subbituminous or bituminous; on the other hand, lignite coal faces firing and utilization challenges that have a bigger effect on CO2 emissions than the boiler steam conditions. The commenter stated that the Cichanowicz and Hein report recommends three different emissions standards: one for supercritical boilers burning subbituminous or bituminous coals, one for subcritical boilers burning subbituminous or bituminous coal, and one for boilers burning lignite. The commenter stated that any final rule must provide a separate standard for IGCC units and a separate standard for coal-fueled utility boilers subcategorized by type (i.e., lignite, subcritical bituminous and subbituminous, and supercritical bituminous and subbituminous) and that in the absence of separate standards, EPA must recognize the differences in emissions from these three categories and adjust the performance standard accordingly. The commenter believes standards for EGUs should be subcategorized by primary fuel type as provided in the statute to distinguish among classes, types, and sizes within categories of new sources; failure to do so, or even consider it, would be arbitrary and capricious. The commenter stated that EPA's own prior analysis and findings with respect to units that burn low-rank virgin coal demonstrate the need for subcategories. The commenter stated that in establishing subcategories for its MATS rule, EPA determined that the differing heat content of low-rank virgin coal justified a subcategory for mercury emissions; that same rationale applies with equal force to require a subcategory for CO2 emissions from these same units.
Commenter 0169 stated that EPA has long recognized the need for categories of EGUs under the NSPS and as far back as 1979, when EPA divided Subpart D for Steam Generating Units into three (3) subparts, it was recognized that standards were needed to recognize the limitations associated with certain equipment. The commenter stated that categories for plant designs, sizes, and ages (i.e. appropriate EGU criteria), should be developed for this standard as well. The commenter stated that EPA acknowledges in the rule preamble that utility boilers are numerous and diverse in size and configuration and further states that developing a single standard for all modified utility boilers or IGCC units is challenging. For these reasons and if this rule moves forward, the commenter asserts that EPA should subcategorize under Section 111(b)(2) and account for the many differences in boilers. The commenter stated that EPA has conceded it is open to creating categories for NGCCs and has solicited comment on establishing separate standards for load following NGCC (i.e. intermediate capacity factor) EGUs with a more stringent standard applying only during periods of high annual capacity factors and a less stringent standard applying during periods of intermediate load. The commenter stated that EPA explains that using this approach addresses potential issues with regards to design of NGCCs. The commenter stated that if EPA is open to creating categories for NGCC units, then it should be open to creating categories for coal-fired EGUs in the Modified Source Rule. Commenter 0201 stated that the standards should not only be subcategorized by primary fuel type, but also by the type of unit that is in place and the type of emission control technologies in use on the unit, since these factors can all directly impact operating efficiency and emissions.
Commenter 0192 stated that rather than proceeding with this rulemaking, EPA must withdraw this proposed rule and conduct a new BSER analysis for reconstructed coal-fired EGUs that addresses not only the commercial availability of emission reduction technologies, but also whether or not they can be retrofitted for use by existing sources. The commenter stated that as the D.C. Circuit explained, under Section 111 due consideration must be given to the possible impact on emissions of recognized variations in operations and some rationale offered for the achievability of the promulgated standard given the test conducted and the relevant variables identified. To facilitate public comment, we think this rationale should appear in the Agency's initial support statement. National Lime Ass'n v. EPA, 627 F.2d 416, 434 (D.C. Cir. 1980). The commenter stated that thus, as part of its BSER analysis for reconstructed sources, EPA must consider important differences among coal-fired EGUs, including differences between subcritical boilers, supercritical boilers, and IGCC facilities and, if appropriate, establish different standards of performance for different subcategories of reconstructed coal-fired EGUs. The commenter stated that this analysis must include consideration of all associated support systems, water and steam systems, and steam turbine design and capabilities and that it is likely that such a change to ultra-supercritical operation would necessitate installation of an entirely new facility, thus EPA's regulatory approach would, as a practical matter, eliminate continued use of a reconstructed steam generator. 
Commenter 0242 stated that coal fired generators were largely engineered to operate at high capacity factors. The commenter stated that these proposed rules, along with the proposed rules for existing units, will force many coal-fired units to operate as load following units, outside of their design parameters and at the expense of efficiency. The commenter stated that the EPA cannot provide a sound technical rationale as to why these same concepts do not apply to coal-fired EGUs and urges the EPA to extend those considerations offered to NGCC units to coal-fired units; otherwise, it is clear that the EPA is choosing a winning fuel, natural gas, over a losing fuel, coal, and that was not the intention of the CAA.
Commenter 0222 stated that ultimately, the standards proposed by EPA for reconstructed units cannot be met. The commenter stated that the EPA must impose more lenient limits for supercritical units and must also create categories for subcritical units, with correspondingly less onerous standards. The commenter stated that within each of those primary categories (subcritical and supercritical), it must then create fuel-specific subcategories; there must be subcategories for lignite, with further relaxed emissions limits and standards that reflect the unique characteristic of the fuel and the design of the facilities to burn the fuel.  
Subcategory for lignite 
Commenter 0222 stated that lignite-fired power plants are technologically and operationally distinct from traditional coal-fired power plants, and even more distinct from IGCC units, and include different design elements that warrant and require a separate subcategory within the overarching coal category. The commenter stated that this lignite subcategory should include more relaxed emissions limits and standards. The physical and chemical characteristics of lignite demand sub categorization: lignite has a lower heat-value than other types of coal, resulting in the need to combust additional fuel in order to meet comparable generation amounts; the physical and chemical composition of lignite also typically requires larger, more energy intensive, control technologies than other coal-fired units and the parasitic load of these technologies inherently impacts GHG emissions and performance capabilities of these units; and lignite EGUs are almost always at mine-mouth power plants that are co-located with the mines that supply their coal. The commenter stated that imposing limitations that would require a source to comply with the emissions standards of non-lignite units following modification or reconstruction is simply not feasible and would require a power plant to change fuel types in order to continue to operate, but fuel switching is impossible for many of these mine-mouth plants, as they do not possess the infrastructure, whether it be rail lines to import alternative coal, pipelines to transport natural gas, or the boiler/burner design to fire either. The commenter stated that these types of changes would be far beyond the scope of any modification and reconstruction.
Commenter 0222 stated that EPA, as recently as the MATS Rule, established a subcategory for lignite within the larger coal subcategory, not only because of the chemical composition of the fuel source, but also because lignite units are universally constructed at or near a mine containing lignite with designated and narrowly limited conveyance mechanisms to transport lignite from the mine to the power plant. According to the commenter, if EPA does not provide a lignite subcategory, operators of existing lignite-fired power plants conducting a modification or reconstruction would be required to shut down, forfeiting use of extremely valuable and affordable generating units. The commenter stated that it would also require those units to forfeit access to domestic, plentiful, and affordable lignite and would signal the end of the ability of co-located mine-mouth plants to conduct modifications or reconstruction, as well as the ability to recover potentially sizable investments in their mines because of the limitations placed on an operator's ability to maintain, expand, or add capacity to use these local, domestic, and sizeable fuel supplies. The commenter stated that natural gas is not available in many areas reliant on lignite, but beyond those areas, natural gas supplies (or even alternative coal supplies) are also not readily available in all parts of the country, including large regions dependent on lignite-fired generation. The commenter stated that EPA has not accounted for the regional availability of natural gas or coal that may be imposed on modified/reconstructed units by a rule without a separate lignite subcategory.
Subcategory for coal refuse
Commenter 0182 suggested that EPA separately define BSER for coal refuse CFB units. 
The EPA sees no need to subcategorize the reconstructed standard for anything beyond size as the EPA has determined that smaller boilers cannot implement measures to meet the emissions achievable by supercritical boiler technology.  The EPA has based the emission limitation for larger reconstructed units on the performance of a supercritical unit burning subbituminous coal. That standard can be met by similar units burning bituminous cost (e.g., the Longview plant in WV) and by units burning dried lignite (which will have a similar heat input as subbituminous coal.  The EPA re-emphasizes ... triggering the reconstruction provision is a significant economic hurdle - and it has only rarely been done. If it is triggered, the EPA does not specify any particular technology that must be used. Rather the reconstructed unit must meet a standard of performance consistent with the emission reductions achieved by the BSER. Owners/operators can do so by installing a new boiler or by converting an existing boiler or by refurbishing the existing boiler or by utilizing other options  -  such as the use of natural gas co-firing to achieve the final emission limitation. In any case, per 40 CFR 60.15, if the owner/operator can demonstrate 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.
Commenter 0222 stated that the proposed 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. The commenter stated that 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. The commenter stated that 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. The commenter stated that EPA should set these emission levels at a much higher level and also create separate subcategories for regulated units.
Achievability of the final standard has been addressed elsewhere in this RTC.
Support for a case-by-case assessment for each utility boiler
Commenter 0215 stated EPA's general reconstruction rule requires an analysis of whether it is technologically and economically feasible to meet a limit, including a consideration of the estimated life of the facility after the replacements. See 40 C.F.R. section 60.15(f). This provision inherently requires case-by-case reconstruction determinations in light of economic and technological feasibility considerations, which EPA fails even to acknowledge (let alone discuss) in the Proposed Standards. Commenter said EPA concedes that existing EGUs are a diverse population, therefore, it may be difficult for EPA to set a single NSPS that can be achieved at all reconstructed units. Commenter said EPA is authorized, however, to subcategorize under section 111(b)(2) and can undertake the necessary analyses to account for the many differences in the boiler population. Given the rarity of reconstruction, however, commenter suggested that EPA withdraw its Proposed Standards and decline to set a standard. At a minimum, based on the foregoing discussion, EPA should explicitly deem economically infeasible "and therefore not a reconstruction" any situation where the imposition of the NSPS would result in an EGU shutting down.
Several commenters (0253, 0259) stated that the condition for defining reconstruction as being technologically and economically feasible to meet the applicable standard should be continued as a condition for an EGU to be subject to the reconstructed emissions standards. The commenter stated that ascertaining that this condition is met would be, as it has been, a critical part of the case-by-case assessment option because it allows the state or EPA to evaluate each units specific factual constraints and how they affect its ability to reach emission limits.
Commenter 0218 stated that heat rate improvement is a potential approach for reducing carbon emissions from modified or reconstructed EGUs but it must be analyzed on a case-by- case basis to allow for consideration of current unit configurations and operating and maintenance practices. The commenter stated that for each EGU, possible heat rate improvements are dependent on load, temperature, design and control configuration, operation and maintenance practices, and availability of cost-effective equipment upgrades and, because a static limit is not a reasonable standard in the case of variable CO2 emissions from utility boilers or IGCC units, BSER should require best practices of operation and maintenance which limit heat rate variability and consequent CO2 emissions. The commenter stated that based upon the limited data available and the wide variation that may be expected from the types and sizes of EGUs that may modify or reconstruct in the future, it is inappropriate for EPA to establish specific emission limitations for CO2. The commenter stated that the Agency's attempt to define a specific limit as BSER fails to account for the recommendation by Sargent & Lundy to provide flexibility by performing a power plant energy audit, to determine the availability of cost-effective equipment upgrades and commensurate improvements in heat rate. 
Commenter 0146 stated that BSER for all reconstructed Subpart Da units should be based on their design steam conditions. 
Commenter 0224 stated that states should set standards of performance for individual EGUs rather than the proposed numerical range of potential emission limits for the several different source categories. The commenter stated that this uniformity within a category 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 same point applies to other technologies retrofitted to existing plants. 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 commenter stated that for this reason, standards for reconstructions are done on an individual facility basis. See 40 C.F.R. section 60.15(b)(2) (reconstruction means "the replacement of components of an existing facility" to the extent it "is technologically and economically feasible to meet the applicable standards"); 79 FR at 34971/2 (recognizing "need to clearly delineate between a reconstructed source and a newly constructed source" when setting standards).
Commenter 0291 stated that EPA cannot reasonably assume that any specific level of emission reduction can be achieved across the board by EGUs undertaking 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, 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. Commenter suggested 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 above five factors. 
The EPA has properly finalized 111(b) standards of performance for reconstructed units  -  rather than setting up a case-by-case determination of the final standard.  The EPA also has not proposed to  -  nor finalized  -  any changes to 40 CFR 60.15 provisions for reconstructed sources.
Applying national averages to individuals units rather than case-by-case basis 
Commenter 0187 stated that the Agency's heat rate improvement assertion is flawed for several reasons: national averages cannot be applied directly to individual units as each unit must be evaluated on a case-by-case basis and specific unit's heat rate is primarily due to factors outside of the source's control such as plant location, design, age, and size, coal type, cooling system type, grid dispatch, time of year the unit is dispatched, ambient temperature, auxiliary load requirements, pollution controls, and other factors; also, the operation of SO2 scrubbers, SCR controls, and fabric filter baghouses degrade the heat rate of EGUs. The commenter stated that because many utilities took steps to improve the efficiency of their units, it would be inappropriate for EPA to use any year prior to the year in which those projects were undertaken as the baseline for heat rate improvements; furthermore, future projects that will reduce unit efficiency will need to be taken in response to environmental regulations, such as MATS and Regional Haze; and other future compliance requirements must be accounted for prior to any heat rate improvement requirement.
Commenter 0242 stated that the permitting or implementing authority should be making a unit-specific determination based upon potential energy efficiency improvements for all source types based upon unit-specific information and the cost and technically feasibility.
Commenter 0257 stated that the efficiency improvements cited by the EPA were determined on an industry-wide aggregate basis; therefore, they apply well to some individual generating units and not so well to others. The commenter stated that it is inappropriate to apply measures determined in aggregate to individual units, especially when the information is available to determine what improvements are achievable for each. The commenter stated that in some cases, recent investments already have been made to improve the heat rates of existing coal-fired units and additional efficiency gains of the magnitude proposed in the rule would be infeasible both physically and economically. The commenter requested that to the extent EPA retains a requirement to improve efficiency for modified or reconstructed units, the EPA allow affected units to credit previous efforts to improve heat rate toward compliance with these standards.
Commenter 0214 stated that the EPA erred in relying on its GHG Abatement Measure TSD (which was developed to support the Agency's section 111(d) Proposed Guidelines) as it primarily analyzed national annual average CO2 emission rates which do not support unit-specific standards. The commenter stated that the GHG Abatement Measures TSD, thus, mutes unit-level CO2 emission rate variability; for example, the net CO2 emission rates of the commenter's coal-fired units show significant CO2 emission rate variability at the unit level. The commenter included figures in their submission to illustrate the unit-level variability. The commenter stated that EPA's assumptions regarding nation-wide emission rate averages are a poor estimate for what a single modified boiler could achieve nor does the GHG Abatement Measures TSD provide any data resembling EPA's proposed compliance criteria (i.e., 12-operating month rolling average net CO2 emission rate data). The commenter stated that, thus, no support is provided to justify the achievability of the Agency's proposed standards for modified boilers and IGCC units.
Commenter 0291 stated EPA cannot reasonably assume that any specific level of emission reduction can be achieved across the board by EGUs undertaking a modification. Commenter said 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, 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 above five factors. 
The EPA has properly finalized 111(b) standards of performance for reconstructed units  -  rather than setting up a case-by-case determination of the final standard.  The EPA also has not proposed to  -  nor finalized  -  any changes to 40 CFR 60.15 provisions for reconstructed sources.
Need for subcategories  
Regarding EPA's claims of the cost of BSER and the commensurate improvements in efficiency, Commenter 0169 stated that for a newly constructed unit, it does not matter if the best practices are high cost, low cost, or no cost, if the unit has been designed and built with those options already included. The commenter stated that as a newly-constructed, technologically advanced, stand-alone unit, their unit is disproportionately affected by presuming that either a 2 or 4 percent reduction in CO2 emissions is achievable. The commenter stated that this demonstrates the need for sub-categorization of units within the Modified Source Rule, giving newly constructed units a separate performance standard than older units; in fact, these newer units should set the bar for BSER. 
Commenter 0169 stated that for a newly constructed unit, it does not matter if the best practices are high cost, low cost, or no cost, if the unit has been designed and built with those options already included, as the commenter has. The commenter stated that as a newly-constructed, technologically advanced, stand-alone unit, they are disproportionately affected by presuming that either a 2 or 4 percent reduction in CO2 emissions is achievable. Both of these demonstrate the need for sub-categorization of units within the Modified Source Rule, giving newly constructed units a separate performance standard than older units. In fact, these newer units should set the bar for BSER. In a footnote, the commenter stated that the GHG Abatement TSD does not support EPA's conclusion in this context. EPA prepared the GHG Abatement TSD to demonstrate in the ESPS docket the available average heat rate improvements compared to 2012 values for existing EGUs; yet EPA attempts to use that same analysis to demonstrate that individual units which perform modifications can reduce emissions an additional 2 percent beyond their best demonstrated historical performance from 2002 through the time of the modification.
This comment addresses standards for modified EGUs  -  which have been addressed in Chapter 6 of this RTC. The final standards for modified sources reflect the best historical performance of the affected source itself and therefore there is no need to subcategorize by size, fuel-type, location, or boiler type.
Subcategorize by fuel type and boiler configuration  
Commenter 0255 stated that EPA should subcategorize the modified [sic] boiler carbon dioxide intensity floor for fuel type and boiler configurations. The commenter stated that a limit of 1,900 lb CO2/MWh-net is not appropriate for plants that fire lower-ranked fuels such as lignite. The commenter stated that under EPA's CPP, North Dakota power plants would have to achieve an intensity goal of 2,226 lb CO2/MWh-net, a much more reasonable floor for pulverized coal boilers firing North Dakota lignite fuel; cyclone-fired boilers may require an even higher floor.
Commenter 0222 stated that the EPA proposes to group utility boilers, mainly coal- and lignite-fired power plants, into the same source category as IGCC units. The commenter stated that traditional coal-fired power plants are in a completely different class and are of an entirely different type than IGCC units and the differences in generation technologies result in different emissions profiles, including differences in the rate of CO2 emissions. The commenter stated that like the lignite category, the distinction between coal-fired power plants and IGCC units was explicitly recognized in the MATS Rule, in which the IGCC category was subject to distinct emissions limits, recognizing these differences in generation technologies. The commenter stated that in the New Source Rule 111(b) proposal, EPA proposed creating a separate subpart (subpart TTTT) which would separate utility boilers and IGCC units into different categories; this new subpart is evidence of EPA's own recognition that traditional coal and lignite-fired power plants should not be grouped into a single category with IGCC power plants. The commenter stated that for the reasons discussed in the MATS Rule and New Source Rule Proposal, the EPA must not group traditional coal- and lignite-fired generation units with IGCC units; the differences between the technologies are too great and necessitate a separate subcategory.
Triggering the reconstruction provision is a significant economic hurdle - and it has only rarely been done. However, in the event that a unit does trigger the reconstruction provisions, the reconstructed unit would not be required implement any particular technology or take any specific actions. Rather the reconstructed unit must meet a standard of performance consistent with the emission reductions achieved by the BSER. Owners/operators can do so by installing a new well-performing boiler, or by refurbishing an existing boiler in order to meet the final standard. Owners/operators can also take advantage of other options to further reduce emissions and meet the final standard of performance  -  such as coal drying (for lignite-fired units) or natural gas co-firing which has long been recognized as an option for coal-fired boilers to reduce emissions of air pollutants. In any case, per 40 CFR 60.15, if the owner/operator can demonstrate 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.
Identify appropriate BSER for modified/reconstructed sources and apply to determine standards of performance achievable by the source category 
Commenter 0214 stated that they are concerned that establishing a source category-wide, or even subcategory-wide, numerical standard that is achievable by most potentially affected units is likely impossible, given the significant variability from unit to unit, and even at the same unit from year to year. The commenter stated that if EPA attempts to develop appropriate separate standards of performance for modified and reconstructed coal-fired and natural gas-fired units it must: (1) identify an appropriate BSER and (2) apply that BSER to determine standards of performance that are achievable by the source category. 
The EPA has identified separate standards for modified and reconstructed sources based on the determination of different BSERs for each category.