Chapter 4
Alternatives

Contents
4.1	General	2
4.2	Partial CCS	2
4.3	Conversion to or Co-firing with Natural Gas	8
4.4	CHP	15
4.5	Hybrid Power Plant	16
4.6	Reduction in Generation Associated with Dispatch Changes, Renewable Generation, and Demand Side Energy Efficiency	18
4.7	Efficiency Improvements Achieved Through a Combination of Best Operating Practices and Equipment Upgrades	28
4.8	NGCC Technology with Partial CCS	30
4.9	High Efficiency Simple Cycle Aero-Derivative Turbines	31



General
Commenters 149, 195, 197, 214 agreed with EPA's assessment that natural gas conversion, natural gas co-firing, natural gas-reburning, combined heat and power, and plant hybridization are not BSER for modified and reconstructed sources. Commenters agreed that these technologies are inside-the-fence options that are not technically or economically feasible for all sources, therefore few existing sources would have the ability to achieve a standard based on them. Commenter 195 stated these other control technologies are not appropriate given that they would fundamentally "redefine" the source. According to the commenter, it is well-established in the context of permitting a new unit or a major modification that EPA may not make assumptions about available control technology that would result in a "redefinition" of the source. The commenter concluded that to mandate co-firing with gas, cogeneration, or hybridizing would be using the CAA to impermissibly require a unit designed as a coal-fired unit to be completely redesigned so that it can burn natural gas. 
Commenter 214 supported EPA's decision not to look beyond the fence-line of the source in determining BSER for modified and reconstructed EGUs. The commenter questioned EPA's decision to even consider outside-the-fence options at all, such as the re-dispatch to natural gas resources, renewable energy resources, nuclear resources, and demand-side energy efficiency that EPA has included in its section 111(d) Proposed Guidelines, given that those resources and activities should be clearly beyond the reach of section 111 of the CAA. But, the commenter concluded, EPA's ultimate decision to exclude those options from further consideration under section 111(b) is appropriate.   
See section VII.B of the final rule preamble of the EGU GHG NSPS for EPA's response to this comment.
Commenter 211 stated EPA has not provided sufficient information concerning several of the options it puts forward for alternative and variable standards. According to the commenter, these deficiencies make it problematic to provide informed comments and correspondingly call into question EPA's ability to finalize options that have not been fully described or technically supported. The commenter also suggested EPA supplement the information provided concerning the unavailability of CCS for natural gas-fired combustion turbines.
The EPA described issues we solicited comment on in sufficient detail that commenters were able to provide substantive responses. The EPA's response to CCS for NGCC units is discussed in the preamble to this final rule.  
Partial CCS
The following commenters support EPA's decision that CCS is not BSER.
Commenters 145, 149, 152, 157, 171, 182, 189, 195, 197, 214, 229, 254, 257, 263 supported EPA in rejecting partial CCS as BSER in this proposal.
Commenters 149, 152, 171, 214, 229 stated CCS is properly rejected based on a lack of information about costs, site-specific space requirements and equipment configurations, and it has not been adequately demonstrated. Commenters stated there is no test data for establishing whether partial CCS is achievable; partial CCS is not in use at any EGU in any source category or fully integrated with electricity generation. Commenter 149 incorporated by reference a more complete discussion of why partial CCS cannot be BSER, at this time, for any EGU is included in their comments on EPA's proposed rule for GHG emissions from new stationary source EGUs.
Commenter 260 stated that retrofitting a plant with partial CCS would entail integrating the carbon capture equipment with the affected unit's steam cycle (or with an external source of steam or heat) to release the captured CO2 and regenerate the solvent or sorbent. According to the commenter, partial CCS is unreasonably expensive and inadequately demonstrated even when included in the original design of an EGU, making it clearly inappropriate as a system of control for a modified or retrofitted EGU. The commenter stated the cost of adding partial CCS to a modified or retrofitted EGU would depend on many site-specific details, including the space available for the capture equipment, and because of these site-specific constraints, it is not possible to estimate the cost of partial CCS, on either a source-specific basis or an industry-wide basis.  
Commenter 195 stated the costs of implementing partial CCS at this time are so excessive as to render partial CCS completely unreasonable as the basis for BSER. The commenter cited D.C. Circuit (Essex Chem. Corp. v. Ruckelshaus) that costs of implementing BSER may not be "exorbitantly costly." 
Commenter 189 stated even if CCS was technologically feasible, the high cost of CCS would preclude the technology as BSER. According to the commenter, current CCS projects at EGUs have only succeeded thus far due to significant governmental funding, and those projects have significantly increased in cost since first initiated. The commenter stated that since these CCS projects have required funding through governmental programs, it is clear there is more time needed to develop economic CCS technologies before it would be considered BSER whether the EGU is new, modified and reconstructed or existing.
Commenter 260 provided additional information on the unreasonable costs of CCS, noting higher electricity costs associated with its use, parasitic load concerns, the need for DOE financial incentives for demonstration projects, and the lack of U.S. commercial ventures that capture, transport, and inject industrial-scale quantities of CO2 solely for the purposes of carbon sequestration. The commenter also stated that few, if any, merchant power companies or regulated electric utilities are likely to invest in a new coal-fired power plant with CCS, and as a result, it is unlikely that CCS technology will be developed, refined or improved so as to make it technologically or economically viable to EGUs, generally, in the near future.
Commenter 260 described how CCS has not been adequately demonstrated as a control technology for any power plants, whether new, modified, or reconstructed. The commenter noted that currently are no commercially viable power plant projects that employ permanent carbon sequestration, and provided additional information on the Kemper County plant, noting that the plant has characteristics that would be difficult to replicate nationwide. The commenter discussed concerns that existing CCS projects in other sectors only operate intermittently and do not capture carbon on the same scale that would be needed by power plants. Furthermore, the commenter noted regional and economic concerns with access to EOR opportunities. 
Commenter 182 noted that EPA concedes that CCS is not a viable control technology for modified EGUs. The commenter also noted that EPA's reliance on CCS projects funded through DOE on the corresponding 111(b) rule appear to be in conflict with the Federal Power Act. The commenter also stated EPA has not fully evaluated the technology and economics of CCS and EPA has not fully analyzed the potential for the sequestration part of the carbon capture. According to the commenter, there are limitations in location, areas geologically suitable, and the related cost tied to any transmission, compressor stations and the emissions from these stations, and leakage from the pipelines tied to sequestration. The commenter stated that when looking at these concepts and subtracting these losses, the actual reductions may be a lot less than what is being captured and transmitted for sequestration.
Commenter 257 noted constraints on facilities not located near an existing CO2 pipeline or an existing oil field, the latter for purposes of employing the CO2 emissions in enhanced oil recovery (EOR) operations.
Commenter 197 referenced comments submitted to the proposed NSPS for fossil-fired EGUs discussing several additional aspects of the technical and economic feasibility of CCS. The commenter discussed concerns with the EPA assumption of a 100 percent retention rate for sequestered CO2 and concerns with the significant energy penalty associated with CCS. 
Commenter 152 supported EPA not including CCS and outside-the-fence measures in the proposal. The commenter stated that regarding outside-the-fence measures, the Clean Air Act requires EPA to set a standard that is achievable by sources within the source category, and accordingly, EPA cannot include any outside-the-fence measures in its Modified/Reconstructed- Source Proposal.  
See sections IX. C.4.a through c of the final rule preamble of the EGU GHG NSPS for EPA's response to this comment.
The following summarizes comments suggesting that EPA create a subcategory for which CCS should be BSER. 
Commenter 280 stated that EPA currently has sufficient information to set performance standards for subcategories of modified and reconstructed sources, based in part on partial CCS retrofit. According to the commenter, CCS retrofit technology is available in many circumstances (and enhanced oil recovery (EOR) sequestration can be cost-effective as a CO2 pollution control). The commenter stated that for modified and reconstructed subpart Da sources, retrofit partial CCS must be among the best systems of emission reduction (BSER) supporting the proposed and final standard, at least for a subcategory of modified sources within 80 miles of EOR opportunities, and for reconstructed sources. The commenter recommended that EPA strengthen its performance standards using its authority to subcategorize the industry to reflect the potential for retrofit CCS technologies to achieve deep, near-term emissions reductions in CO2 from modified and reconstructed sources based on the availability of EOR sequestration opportunities. The commenter referenced IEA and other studies, noting that CCS is an important emission reduction option for power plants. 
Commenter 280 noted that EPA previously recognized that "CCS technology has been adequately demonstrated, and its implementation costs are reasonable," and based the CO2 NSPS emissions rates for new, subpart Da, fossil fuel-fired utility boilers and IGCC units on a BSER including partial CCS. However, according to the commenter, even though modified and reconstructed sources are included in the statutory definition of "new source," EPA did not, in that proposed rule, address partial CCS as a BSER and basis for standards of performance for modified and reconstructed subpart Da sources. The commenter referenced the SaskPower Boundary Dam CCS retrofit project, noting that partial carbon capture is "available" and in use now on coal-fired power plants in the U.S., as well as in industrial uses here and abroad in similar contexts that support technology transfer. The commenter stated that incidental sequestration ("storage") at EOR sites, which helps offset the costs of partial CCS, is an option for many existing sources. According to the commenter, EPA has authority to "distinguish among classes" of modified sources for the purpose of setting standards, including by defining a subcategory of sources based on locational proximity to sequestration options and EPA therefore, should create a subcategory of modified subpart Da sources, which are within 80 miles of EOR and base the performance standard on a partial CCS BSER. The commenter also stated the Agency additionally must base the reconstructed subpart Da sources performance standards on a partial CCS BSER, or the construction of an NGCC, consistent with CAA section 111(b) standards proposed in January 2014.
Commenter 280 stated CCS retrofits are the BSER for the NSPS for certain modified sources within 80 miles of EOR sequestration.
 
The commenter stated modified sources automatically trigger the NSPS if "any physical or operational change to an existing facility which results in an increase in the emission rate to the atmosphere of any pollutant to which a standard applies." The commenter also stated however, EPA has the authority to "distinguish among classes...within categories of new sources for the purpose of establishing...standards." According to the commenter, the word "class" can include the location of the source, if relevant to the availability of more effective pollution control options at certain locations. The commenter recommended that EPA exercise its authority to define a subcategory of modified sources based on the proximity of sequestration opportunities to sources in the subcategory. By sequestration opportunities, the commenter meant existing pipelines, operational EOR fields, or existing production fields with EOR potential. The commenter stated for that subcategory of sources, the CO2 performance standard would be based in part on partial CCS technology. The commenter stated a modified source subcategory based on proximity to EOR sequestration is justified by the potential for retrofitted sources to offset the costs of partial CCS retrofits with sale of captured CO2 to an EOR operator for use and long-term containment in depleted oil or gas fields. The commenter suggested that a distance of 80 miles to such EOR opportunities can define the extent of this subcategory. The commenter noted it has seen actual evidence that an 80 mile +/- distance from EOR resources can provide the financial incentive to apply retrofit carbon capture and sequestration. The commenter stated the Petra Nova Carbon Capture Project is a retrofit in Texas currently under construction, at which NRG Energy is installing and transporting captured CO2 by an 82-mile long pipeline for EOR utilization and sequestration.
 
The commenter stated the court in Sierra Club found reasonable an industry subcategory based on the sulfur content of local fuel, stating that location-specific considerations are relevant to the question of what is the "best" system of emission reduction to form the basis for a 111(b) standard:
 
"an efficient water intensive technology capable of 95 percent removal efficiency might be 'best' in the East where water is plentiful, but environmentally disastrous in the water-scarce West where a different technology capable of only 80 percent reduction efficiency might be 'best.'"
 
The commenter stated similarly, where partial CCS may be part of the BSER for a performance standard for existing modified sources with access to EOR storage for the captured, compressed CO2, so too it may not be reasonable to include it in assessing the BSER supporting performance standards for modified sources at a further distance from EOR or other sequestration resources. The commenter stated a subcategory of modified sources based on proximity to CO2-EOR sequestration opportunities promotes the purposes of the CAA, which was designed "to assure the use of available technology and to stimulate the development of new technology" as well as to require achievement of the maximum degree of emission reduction possible, while encouraging the development of innovative technological means of achieving equal or better degrees of control. The commenter stated partial CCS retrofits are adequately demonstrated and available. The commenter also stated basing the BSER for subpart Da sources on partial CCS spurs newer kinds of technology that can enable near zero carbon emissions from modified and reconstructed fossil fuel-burning plants. The commenter stated that goal is well within EPA's authority to consider in setting these technology-forcing, forward-looking standards. The commenter stated where proximity to CO2-EOR storage may preclude application of partial CCS, it is reasonable to subcategorize based on this factor rather than simply to deem partial CCS infeasible for all modified and reconstructed sources. 
 
Commenter 280 stated modified subpart Da sources outside of 80 miles from sequestration opportunity must comply with EPA's proposed MRSPS and partial CCS must be considered during any PSD permitting process. The commenter encouraged EPA to finalize co-proposed "Alternative #1" for modified subpart Da sources outside of 80 miles from an EOR opportunity. The commenter stated Alternative #1 would require a source to meet a unit-specific emission limit determined by the unit's best historical annual CO2 emissions rate plus an additional 2 percent emission reduction. The commenter also stated that such sources would continue to be responsible for their CAA section 111(d) obligations as well. According to the commenter, States have authority to set source specific emission limits and there is no guarantee that a modified source's obligations under CAA section 111(d), alone, will be sufficient to address the increased emissions associated with a "modification." The commenter also stated while a modified source may be further than 80 miles from an EOR resource, partial CCS may still be available and the appropriate place to consider it is during the CAA section 165 Prevention of Significant Deterioration ("PSD") best available control technology ("BACT") analysis. The commenter stated that during that process the permit issuing authority determines an achievable emissions limitation for each pollutant subject to regulation under the CAA from any proposed major modification "on a case-by-case basis, taking into account energy, environmental, and economic impacts and other costs." BACT is required for "greenhouse gases emitted by sources otherwise subject to PSD review." The commenter stated therefore, the feasibility of CCS must be evaluated on a case-by-case basis when an EGU undergoes a major modification.
See sections V.B and IX. C.4.a through c of the final rule preamble of the EGU GHG NSPS for EPA's response to this comment.
Commenter 280 stated a modified and reconstructed standard based on partial CCS is a logical outgrowth of the rule as proposed.
The commenter stated their proposed changes to EPA's MRSPS, namely, to include a subcategory of modified sources with a more stringent standard based on the availability of retrofit CCS with EOR sequestration, and to apply the CAA section 111(b) standard to reconstructed sources, is a logical outgrowth of EPA's proposal. The commenter stated EPA's MRSPS proposal provides sufficient detail about partial CCS as a potential BSER, and seeks comment on all aspects of the proposal. The commenter stated CAA section 307 requires EPA to make its proposal available for public comment along with a statement of basis, which includes the factual data and methodology the proposal rests upon along with the Agency's legal and policy determinations; however, EPA is not required to adopt a final rule that is identical to the proposed rule. The commenter stated to the extent that EPA has sought comment and received it on a particular aspect of the proposal, as here where EPA evaluated partial CCS as BSER for all modified and reconstructed sources, the Agency is well within its authority to finalize a rule including a performance standard relying in part on partial CCS as the BSER for a subcategory of the regulated industry. According to the commenter, the purpose of a comment period is to gather information and "[a]genies, are free -- indeed, they are encouraged -- to modify proposed rules as a result of comments they receive." The commenter stated, thus, a final rule may be a logical outgrowth of a proposal if interested parties "should have anticipated" comments on the subject during the notice-and-comment period. The commenter stated that here, EPA has more than placed the issue of partial CCS as BSER in the record -- it has based its earlier proposed section 111(b) NSPS for new sources in part on the availability of partial CCS for newly constructed sources. The commenter also stated that moreover, the Agency notes its view that modified and reconstructed sources are included in the definition of "new sources," and specifically discuss the issue in the modified and reconstructed source proposal. According to the commenter, it therefore is unnecessary for EPA to re-propose the MRSPS in order to finalize a MRSPS rule including CATF's recommendations. 
See sections V.B and IX. C.4.a through c of the final rule preamble of the EGU GHG NSPS for EPA's response to this comment.
Commenter 280 stated CCS must be included in the BSER for a MRSPS for reconstructed sources. 
The commenter stated the owner of an existing source, who considers whether or not to undertake reconstruction of that source, is embarking on a significant economic investment in plant approaching the decision to build a greenfield source. The commenter stated the decision to reconstruct an existing source is by definition one to expend resources equivalent to 50 percent or more of the replacement cost of the facility. According to the commenter, it is that level of investment, approaching the investment for a greenfield source, that as a policy matter and consistent with the statutory framework, supports performance standards reflecting the "best" controls for all regulated pollutants, including designated pollutants. Therefore, the commenter stated, part of the decision as to whether to "reconstruct" a source, rather than "modify" it, must be whether or not the source will be able to meet the pollution control requirements implicit in the new source standards. The commenter stated, in other words, this is the kind of large investment the Congress understood to be the appropriate time to significantly update pollution controls at a source.
The commenter stated for these reasons, and because the problem of CO2 emissions from the subpart Da source category represents more than a third of U.S. anthropogenic CO2 emissions, the BSER for the CAA section 111(b) reconstructed source performance standards must reflect partial CCS technology (or the construction of an NGCC), just as is the case for the new source section 111(b) standards---put differently, reconstructed sources must meet the proposed 111(b) standards published by the Agency in January 2014, as finalized. The commenter stated carbon capture is available and EOR sequestration is widely available, particularly near existing coal-fired subpart Da sources. The commenter stated the CO2 NSPS standards proposed on January 8, 2014, must apply to both subpart Da reconstructed sources and reconstructed subpart KKKK sources. 
The commenter stated that although CCS retrofit capability may be limited for some sources due to site-specific issues such as access to CO2-EOR storage, EPA promulgated the two part test in the reconstruction provisions in order "to discourage the perpetuation of a facility instead of replacing it at the end of its useful life with a newly constructed affected facility." The commenter stated, so if "reconstruction" level investment is to be made in an existing source, EPA's longstanding rules require that it must meet the NSPS for that source category.
See sections V. B and IX. C.4.a through c of the final rule preamble of the EGU GHG NSPS for EPA's response to this comment.
Conversion to or Co-firing with Natural Gas
Commenters 171, 215, 239, 257, 260 agreed with EPA that conversion to or co-firing with natural gas in a utility boiler is a very expensive means of reducing CO2 emissions and should not be included as part of BSER for reconstructed or modified coal-fired units. Commenter 260 stated conversion to, or co-firing with, natural gas is an inefficient way to generate electricity compared to use of a NGCC unit. Commenters 171, 260 noted logistical and practical constraints on the availability and transport of natural gas to existing units that make conversion/co-firing impracticable, such as the time needed to construct a new pipeline, financing concerns, and financial risks power generators may incur due to market uncertainties and increased prices associated with signing firm contracts to support conversion to natural gas. 
See sections V.H.8 and VII.B the final rule preamble of the EGU GHG NSPS for EPA's response to this comment.
Commenter 0157 stated that they believe that the industry lacks sufficient experience with natural gas reburning to propose it as BSER for reconstructed utility boilers and IGCC units. 
Commenter 183 agreed that co-firing is not appropriate for BSER because in addition to the costs cited by EPA, it has not been adequately demonstrated for use on all coal types. With regard to natural gas reburning, the commenter disagreed with EPA's conclusions regarding the potential benefit associated with reburn. According to the commenter, when fly ash contains sufficient unburned carbon, recovering the energy remaining in the fly ash may become a viable technical option; however, the process of recovering the energy frequently involves the addition of a support fuel, such as natural gas, since the boiler may not be able to stay lit during the re-burn. The commenter stated that an external engineering consultant evaluated Luminant's units to determine the feasibility and potential of fuel gas reburn and based on their analysis, the potential heat rate benefit would be negligible due to the small quantity of unburned carbon present in the ash. Therefore the commenter does not believe that reburn is a viable opportunity for CO2 emission reduction and therefore should not be BSER.
See sections IX. C.4.a through c of the final rule preamble of the EGU GHG NSPS for EPA's response to this comment.
Commenter 131 generally agreed with EPA that co-firing or switching from coal to gas in coal boilers is not economical to be considered BSER, noting they are only aware of such switching occurring in meeting compliance with MATS where in some plants it is economical, but are currently not aware of anyone switching for CO2 compliance. However, according to the commenter, given complex compliance plans driven by NSPS, ESPS, and this proposal, it may be presumptive for EPA to suggest this would not be an option in the right market and geographical area.
See sections V.H.7.a and VII.B of the final rule preamble of the EGU GHG NSPS for EPA's response to this comment.
Commenter 190 agreed that EPA correctly concludes that natural gas co-firing, even without any capital investment or impact on the performance of the affected facility, should not be part of the BSER for modified or reconstructed steam generating units, although the commenter is concerned about EPA's conclusions on conversion of a utility boiler to natural gas and believes this statement should be viewed in the context appropriate only for this rulemaking,  i.e., as an element establishing the Best System of Emission Reduction. The commenter noted that two of their operating companies will be converting from coal to gas as a fuel source to comply with regulatory requirements completely unrelated to CO2 reductions, but these projects will have the ancillary benefit of achieving significant CO2 reductions. The commenter noted it is important that EPA not reach the conclusion that such projects are not economic under all Clean Air Act programs.
See sections V.H.7.a and VII.B of the final rule preamble of the EGU GHG NSPS for EPA's response to this comment.
Commenter 149 stated EPA's proposed standards for reconstructed utility boilers and IGCC units are not achievable and could effectively prohibit reconstructions. EPA has not proposed standards that would address the most likely type of reconstruction---the conversion of a utility boiler such that it can burn natural gas instead of coal. The commenter noted that in the context of natural gas co-firing, EPA seeks comment on whether natural gas reburning (NGR) or similar technologies should be part of the BSER determination for reconstructed utility boilers and IGCC units. According to the commenter, in order for reconstructed units to utilize NGR, they must convert to gas-fired boilers. The commenter stated that EPA has not explained why co-firing generally cannot be BSER for reconstructed units, but that the wholesale conversion of a unit to burn only natural gas could be considered BSER for these units. At minimum, the commenter stated, EPA would have to address access to sufficient natural gas for all possible reconstructed units before finalizing a standard that relied on this technology.
Commenter 0149 stated that the EPA's proposed standards for modified utility boilers fail to recognize that more coal-based units would convert to boilers that burn natural gas rather than reconstruct to continue to burn coal and that units that convert to burn natural gas will not trigger section 111 regulation as a modified unit because natural gas fueling reduces CO2 emissions by approximately 50 percent on a rate basis. The commenter stated that for units to trigger regulation as reconstructions the costs of the fixed capital components being replaced must exceed 50 percent of the costs of the fixed capital components of an entirely new comparable facility and that the costs of coal-to-natural-gas conversions will not trigger this requirement. The commenter provided an example of a unit converting from coal to natural gas showing that the unit would not be subject to either the modification or reconstruction rules. The commenter stated that it is clear that coal-to-natural-gas conversions are neither modified nor reconstructed units, given the regulatory requirements; accordingly, these existing units will remain subject to regulation under section 111(d) 
See section IX.D.3.b of the final rule preamble of the EGU GHG NSPS for EPA's response to this comment.
Commenter 232 stated the BSER for reconstructed fossil fuel-fired utility boilers and IGCC units is conversion to a natural gas-fired facility to secure greater emission reductions. The commenter stated the proposed standard would not provide significant emission reductions relative to converting these units to combust natural gas. According to the commenter, EPA's analysis does not appropriately characterize the costs of gas conversion or reflect full consideration of the BSER factors, and that careful examination of these factors demonstrates that coal-to-gas conversion is the system that best fits the statutory criteria for BSER for reconstructed fossil fuel-fired utility boilers. 
According to the commenter, the technology to convert a coal-fired utility boiler to burn natural gas is well-demonstrated and commercially available, as EPA acknowledges. The commenter provided additional discussion on the technical feasibility, referencing recent conversion projects and literature on conversions. The commenter stated that although conversion of a boiler to operate on natural gas involves some physical modifications to the facility, such investments are reasonable as part of a BSER given that a reconstruction "generally entails fundamental decisions about what type of unit to rebuild." The commenter also stated the required physical modifications are often relatively modest and coal-to-gas conversion projects can usually be accomplished without replacing the existing boiler, and often entail only the construction of natural gas delivery infrastructure (where not already available) and modifications to ancillary equipment such as burners and ducts. The commenter noted they are unaware of any existing sources for which conversion to natural gas is technologically infeasible. Regardless, according to the commenter, a standard based on the reductions achievable from coal-to-gas conversion would not apply to any such unit. The commenter noted that under EPA's longstanding regulations, a source is only subject to reconstructed-source standards if "[i]t is technologically and economically feasible to meet the applicable standards." Therefore, the commenter continued, the remote possibility that some unit could not comply with a standard based on conversion should not dissuade EPA from adopting rigorous standards for reconstructed fossil fuel-fired utility boilers and IGCC units.
The commenter stated that in comparison to EPA's proposed BSER, switching to natural gas fuel has very significant potential for reducing the carbon emissions from reconstructed fossil fuel-fired utility boilers and IGCC units.  The commenter noted EPA's analysis of conversions for the proposed emission guidelines concluded that a reconstructed utility boiler firing 100% natural gas would have an emissions rate of 1,239 lb CO2/MWh-net, representing a 41% reduction in CO2 emissions rate from 100% coal firing, and reductions of this magnitude are especially significant at reconstructed EGUs, which are, by definition, undertaking large capital investments that potentially allow the plant to operate for many years.
The commenter suggested EPA should also consider the benefits of co-pollutant emission reductions that would result from converting a reconstructed unit to burn natural gas. According to the commenter, the net costs may be higher than other options EPA has considered, but they are significantly lower than the benefits associated with criteria pollutant reductions from conversion, which are approximately $67-150/MWh-net. According to the commenter, adding in the benefits of reduced carbon pollution would only increase the net benefits of conversion as a BSER. Further, the commenter stated, net costs of conversion to gas are certainly within the relevant limits that courts have placed on the costs of performance standards under section 111. He commenter also stated that the fact that many conversion projects have been recently completed or are currently underway shows that the costs are reasonable, and in no way approach the legal standard for a BSER, and the fact that relatively few EGUs have undertaken modifications or reconstructions in the past would further limit the impact of this BSER on electricity prices or energy supply.
The commenter stated it was also inappropriate for EPA to reject unit conversion as too costly by comparing that system to new NGCC facilities. According to the commenter, EPA has failed to offer a reasonable explanation for how the cost-effectiveness of emission reductions by NGCC units is relevant to "the cost of achieving [emission] reduction' through the BSER for the sources affected by this rulemaking. The commenter stated EPA's rejection of a potential BSER based on its consideration of a different source category undermines the Congressional purposes for section 111 because it would lead to a standard that does not 'reduc[e] emissions as much as practicable." The commenter stated it would be unreasonable to impose a weak standard on existing sources undergoing a modification or reconstruction because another category of newly constructed sources is lower emitting. Moreover, EPA's consideration of NGCC in setting standards for reconstructed fossil fuel-fired utility boilers and IGCC units is inconsistent with its January 8, 2014 proposal for new EGUs. There, the commenter sated, the agency proposed a stringent standard for steam electric utility boilers and IGCC facilities without considering whether reductions could be achieved more cost-effectively by building an NGCC unit instead.
The commenter stated coal-to-gas conversion has emerged as a means of complying with emission standards precisely because it is sometimes the most cost-effective strategy. According to the commenter, the cost of fuel-switching boilers is minimal for units that are already designed to burn gas, but the cost of more extensive retrofits is still moderate (and well below the legal standard for BSER) in the context of an EGU reconstruction project, and even where retrofit costs are significant, the conversion to natural gas is cost-effective and can be achieved in a manner that enables electricity consumers save money. With respect to costs associated with pipeline construction from conversion to natural gas, the commenter noted that this standard would not apply to any facilities for which compliance is economically infeasible, since if site-specific factors render coal-to-gas conversion exorbitantly expensive (such as inordinate distance from a natural gas pipeline), a unit would not qualify as a reconstructed source.
The commenter stated EPA impermissibly failed to consider the non-air quality health and environmental impacts of the systems it identified as potentially representing the BSER, and if EPA had performed the 'mandated consideration of the factors enumerated in section 111(a),' the agency would have recognized that switching to natural gas firing at reconstructed units would have far greater non-air health and environmental benefits than its proposed standard. The commenter discussed coal ash and noted conversion to natural gas firing also reduces on-site water quality impacts.
The commenter discussed that EPA has reasonably concluded that its proposed emission standard for reconstructed fossil fuel-fired utility boilers and IGCC units will not have significant adverse impacts on nationwide electricity prices, fuel diversity, the structure of the power sector, or electricity supply because so few units are expected to undergo reconstructions and there are already strong incentives to utilize efficient generation technologies at these facilities, and a standard based on the reductions achievable with coal-to-gas conversion would also avoid these impacts, for the very same reasons. Moreover, according to the commenter, it is improbable that any rigorous reconstructed-source standard would negatively affect electricity prices because the standard would not apply to units where it is not economically feasible to meet.
The commenter stated EPA should consider the additional benefits of a standard based on coal-to-gas unit conversion: likely reduce the energy requirements of a reconstructed unit because natural gas units have lower parasitic loads; reduces electricity demand for fuel preparation (including coal transport, crushing, pulverizers); and the reduction in parasitic load results in an increase in net output.
The commenter concluded a careful weighing of the BSER criteria "excluding any improper considerations regarding the cost of reductions in other source categories" leads to the conclusion that converting to burn natural gas is the best system for emissions reduction for reconstructed fossil fuel-fired utility boilers and IGCC units. The commenter stated this system will achieve far greater reductions than the one EPA has proposed selecting as BSER, and can do so at reasonable cost well below the legal standard. Moreover, according to the commenter, a standard based on natural gas conversion will have important non-air health and environmental benefits and reduce dangerous co-pollutant emissions.
See section VII.B of the final rule preamble of the EGU GHG NSPS for EPA's response to this comment.
Commenter 232 stated the proposed standard would not secure significant emission reductions, and the alternative approach requiring conversion to natural gas, would better fulfill the Clean Air Act's requirement that performance standards reflect the "best" system of emission reduction securing the greatest possible emission reductions considering the other statutory factors. According to the commenter, conversion to natural gas is the BSER for modified coal-fired EGUs because this system would result in lower emissions of carbon pollution and other harmful pollutants at costs that are well within the legal standard. The commenter stated that although EPA has discretion to weigh cost as a factor, that discretion must be exercised in accordance with ensuring that emissions are controlled to the "maximum practicable degree." Furthermore, the commenter stated that EPA's proposal fails to consider, much less give weight to, the potential health benefits that would result from the greater reduction of co-pollutants that would be achieved by conversion to gas. The commenter provided additional information that conversion to natural gas is technically feasible and the cost of conversion to natural gas is reasonable, and additionally that these costs are clearly outweighed by the health benefits associated with lower emissions. The commenter stated it is unreasonable for EPA to reject gas conversion as a BSER because the CO2 reductions resulting from conversion are expensive relative to replacement with a new NGCC, as according to the commenter, the relevant statutory question is whether the cost of conversion is within the appropriate range, not whether the system in question is more expensive than another system that EPA is not even considering as an alternative. The commenter stated NGCC replacement is not an alternative BSER that EPA has considered for modified coal-fired EGUs; unlike conversion, which can be achieved by modifications to the EGU's existing boiler, NGCC replacement requires retirement of the existing EGU and construction of an entirely new EGU. The commenter also stated that EPA's assessment of costs for modified coal-fired EGUs should take into consideration that modifications may be intended to achieve short-term extensions of the service life of the EGU. The commenter also stated that the actual cost of conversion is likely to be lower than EPA's estimates because, for most units, the cost of building a pipeline is likely to be less than EPA assumed, as the median distance of a coal-fired unit from a pipeline is 28.3 miles, just over half the length of the pipeline in EPA's calculations.
The commenter stated the overriding purpose of section 111 is to ensure that pollution is reduced to the maximum extent practicable, giving adequate consideration to other costs and factors. According to the commenter, EPA's analysis indicates that conversion to natural gas will typically reduce the emission rate of carbon pollution from a utility boiler by 41%, to a level of approximately 1,239 lb CO2/MWh-net; in contrast, the BSER EPA has proposed will reduce emissions to no less than 1,900 lbs CO2/ MWh-net for high heat input sources and 2,100 lbs CO2/ MWh-net for other sources. The commenter stated that EPA's analysis demonstrates that a standard based on conversion would achieve considerable additional carbon reductions at each EGU. 
The commenter suggested EPA should also consider the benefits of co-pollutant emission reductions that would result from converting a modified unit to burn natural gas. According to the commenter, EPA reasonably estimated that converting to 100% natural gas would significantly reduce a unit's emissions of SO2, NOx, and PM2.5, and the health benefits associated with these reductions are between $67/MWh-net and $150/MWh-net, greatly exceeding the costs associated with conversion. The commenter also noted that conversion to natural gas firing at modified units would also have far greater non-air health and environmental benefits than EPA's proposed standard, as described above, and these benefits include reduced generation of coal ash and reduced water consumption.
The commenter noted that EPA has reasonably concluded that its proposed emission standard for modified fossil fuel-fired utility boilers and IGCC units will not have significant adverse impacts on nationwide electricity prices, fuel diversity, the structure of the power sector, or electricity supply because so few units are expected to undergo modifications and there are already strong incentives to utilize efficient generation technologies at these facilities. According to the commenter, a standard based on the reductions achievable with coal-to-gas conversion would also avoid these impacts, for the very same reasons. The commenter suggested that EPA should also consider that conversion to natural gas will reduce parasitic loads associated with fuel preparation at conventional coal-fired EGUs.
See section VII.B of the final rule preamble of the EGU GHG NSPS for EPA's response to this comment.
Commenter 216 stated EPA should establish a more stringent standard of performance for modified steam generating units based on a BSER of co-firing or conversion to natural gas. The commenter believed that total or partial conversion to natural gas is the BSER for modified steam generating units. According to the commenter, this approach would result in an emission standard for modified steam generating units that is significantly more stringent than the standard EPA has proposed; a BSER of 50 percent conversion would support an emission standard of 1,673 lb CO2/MWh-net, while a BSER of total conversion would support an emission standard of 1,239 lb CO2/MWh-net. Moreover, the commenter stated, both options are technically feasible, produce substantial co-benefits, and can be implemented at a reasonable cost. 
According to the commenter, the factors cited by EPA do not provide sufficient basis to reject conversion as the BSER for modified steam generating units. The commenter stated that in determining whether a system of emission reduction is the BSER for modified steam generating units, EPA is authorized to consider the technical feasibility, cost, emission-reduction potential, technology-forcing potential, and environmental and energy impact of a system of emission reduction. According to the commenter, all of these factors support co-firing or conversion to natural gas. 
The commenter stated that the cost of co-firing or conversion is within an acceptable range, citing information from the TSD that EPA's own data demonstrate that conversion to natural gas generates net benefits. The commenter also stated that the reasonableness of the cost of conversion to natural gas is further demonstrated by the fact that a number of coal-fired steam generating units have converted, or are planning to convert, to natural gas. The commenter provided examples and additional discussion on costs. Accordingly, the commenter stated that because conversion to natural gas results in substantially greater emission reductions than those achieved under EPA's proposal, and because each option is technically feasible and capable of being implemented at reasonable cost, EPA must adopt either total or partial conversion to natural gas as the BSER for modified steam generating units.
See sections V.I and VII.B of the final rule preamble of the EGU GHG NSPS for EPA's response to this comment.
CHP
Commenters 149, 157, 171 and 260 agreed with EPA that CHP is cannot constitute BSER as "not all potentially modified and reconstructed utility boilers and IGCC units are located close enough to thermal hosts to economically or efficiently use the recovered thermal energy."
We thank the commenters for their support.
Commenter 247 stated the NSPS should unequivocally exclude CHP units from the proposed NSPS, including those units with simultaneous purchase and sale.  According to the commenter, there are strong technical and policy reasons why industrial CHP units should not be covered by the proposed new NSPS for CO2 emissions from EGUs. The commenter referenced their comments for the proposed NSPS for new EGUs, in which they suggested that EPA include an explicit exemption for industrial CHP units or, failing that, that EPA add language to the applicability provisions of the NSPS that would make clear that units whose primary purpose is not to sell electricity in the marketplace will not be subject to the emission standards for new units, and for the same reasons EPA should include a clear, broad exemption or industrial CHP from the CO2 emission standards for modified and reconstructed EGUs.
According to the commenter, even if EPA chooses not to adopt language to add a specific exemption for industrial CHP units, though, EPA still needs to make sure that the language of the CO2 NSPS for new and modified EGUs retains provisions of the current regulations designed to limit application of the EGU NSPS to CHP units. The commenter stated that it is particularly important, when EPA fiddles with the applicability provisions and related definitions of Subparts Da and KKKK, that it not expand application of Subpart Da and Subpart KKKK standards for CO2 (or for other pollutants) to additional CHP units. According to the commenter, one aspect of that is making sure that the applicability cutoffs expressed in terms of sale of electricity or generation of electricity for sale ignore the accounting fiction of simultaneous purchase and sale of electricity at facilities with CHP units. The commenter stated that in order to further policy preferences for encouraging cogeneration, as well as to prevent established electric utility companies from discouraging competition by imposing unfavorable terms of service on CHP unit thermal hosts, federal regulations and some state rules or tariffs have made it advantageous in many instances for a facility that uses the thermal and electrical output from a CHP unit to sell some or all of the electricity produced by the CHP unit to the grid, while at the same time purchasing from the grid that same amount of electricity needed to operate the thermal host. In this way, the commenter continued, even a CHP unit whose entire electrical output is needed for the operation of the thermal host facility could appear to be selling more than one-third of its potential electric output to the grid, because of this simultaneous purchase and sale transaction. The commenter then stated that EPA has recognized, in several contexts including Subpart Da NSPS, the need to apply the applicability criteria only to the net sales after subtracting out purchases for the facility. 
Commenter 247 also stated that important facts and policies underlie the exclusion of CHP units from existing EGU NSPS and warrant continued, clear exclusion from the proposed rule. The commenter provided a detailed discussion on the distinction between industrial and commercial boilers, including CHP, from utility units. 
See section III.D.2 of the final rule preamble of the EGU GHG NSPS for EPA's response to this comment.
Commenter 193 stated EPA should include the full thermal output of CHP facilities when calculating gross output. The commenter noted that when determining a facility's compliance with the proposed emission standards for new units and modified and reconstructed units, EPA has proposed to count 100 percent of electric and mechanical output but only 75 percent of useful thermal output, despite the fact that 100 percent of the useful output can, by definition, be used effectively. The commenter continued that in its proposed modification and reconstruction rulemaking, however, EPA solicits comment on providing credit for useful thermal output in the range of two-thirds to 100 percent. The commenter recommended that EPA include 100 percent of the useful thermal output in the calculation of gross output. According to the commenter, this would ensure the full energy saving value of CHP units is accounted for and given credit under EPA's proposed emission standards. The commenter stated that accounting for only a fraction of the useful thermal output would unnecessarily undermine the full energy value of CHP units, and EPA should be taking every step to encourage the adoption of these highly efficient systems.
See section III.F.2 of the final rule preamble of the EGU GHG NSPS for EPA's response to this comment.
Commenter 193 stated EPA should increase the line loss credit for affected CHP units to 6 percent. The commenter noted that EPA has proposed providing affected CHP facilities that supply at least 20 percent of their output as useful thermal output with a "credit" of 5 percent for electric and mechanical output due to the avoided line losses of CHP. According to the commenter, while EPA is correct in recognizing the benefits of reduced line loss at CHP facilities by providing a 5 percent credit to the electric and mechanical output of CHP facilities, EPA should raise the credit provided to 6 percent. The commenter stated the national average line loss is currently 6 percent, and even this amount likely underestimates the line-loss benefits of CHP, as line loss increases to up to three-times the average rate during peak periods.
The requirements of this final rule only apply to CHP units that sell a significant percentage of their potential electric output to the grid. While the line loses from these units are still less than for non-CHP EGUs located far from load centers, it is not possible to determine the precise line loss savings. The EPA has concluded that 5 percent is a reasonable approximation.
Hybrid Power Plant
Commenters 149 and 171 supported EPA that hybrid power plants cannot constitute BSER as EPA states that "not all modified and reconstructed EGUs may have the space or meteorological conditions to generate enough solar thermal energy to successfully convert to a hybrid power plant."
Commenter 157 stated the hybrid power plant option described by EPA should not be considered BSER because not only has it not been adequately demonstrated that existing plants could accommodate the additional generation required, but also it would be a fundamental redefinition of the existing source.
See section VII.B of the final rule preamble of the EGU GHG NSPS for EPA's response to this comment.
Commenter 131 stated that EPA sought comment on the whether hybrid facilities are viable under modified or reconstructed status and whether there should be separate standards. The commenter believed certain hybrid designs are quite cost effective but argues that there should be no separate standard. According to the commenter, hybrid technologies can make both coal-fired and gas-fired facilities significantly more efficient and thus significantly reduces CO2 per MWHr- the goal of the regulations.
See section VII.B of the final rule preamble of the EGU GHG NSPS for EPA's response to this comment.
Commenter 174 provided information in response to EPA's request for comment on whether hybrid power plant technology is broadly applicable to modified and reconstructed EGUs and on the costs of integrating non-emitting generation. The commenter stated that one of the benefits of hybrid fossil EGUs is decreased incremental cost of the non-emitting generated electricity (e.g., solar thermal) due to the ability to use equipment (e.g., HRSG, steam turbine, condenser, transmission, etc.) already included at or available through the fossil fuel-fired EGU. For example, the commenter stated, hybridization of concentration solar power (CSP) with fossil fuel facilities can eliminate the need to install a turbine exclusively for a CSP plant, thereby saving an estimated 20-30% of the CSP plant's capital cost.
According to the commenter, various possibilities exist for the integration of solar steam into existing fossil plants. The commenter stated CSP hybrid systems may include, but are not limited to, the injection of steam generated by a CSP facility into the steam turbine of a natural gas or coal plant or the use of CSP to preheat the incoming gas feed stream into the combustor for an air-Brayton system. Integration at the highest available temperature and pressure provides the greatest thermodynamic benefit. The most effective overall integration option for any particular situation, however, will depend on a variety of factors, including the existing plant equipment, site configuration, local climate, costs, financing, etc. 
The commenter provided detailed information on EPRI and NREL programs and studies on the potential for CSP, noting that since these initial studies, CSP costs have continued to come down. 
Hybrid power plants, such as those that integrate solar thermal, require significant open space that is often not available at existing units. In addition, hybrid power plant technology is not applicable nationwide. See section VII.B of the final rule preamble of the EGU GHG NSPS for EPA's response to this comment.
Commenter 174 provided two technical corrections to the Hybrid subsection of Identification of Best System of Emissions Reduction in the Propose Rule. First, the commenter stated, EPA described one potential integration system of "solar thermal with low quality steam heated to higher temperatures and pressures in the boiler prior to expansion in the steam turbine." The commenter noted there are multiple CSP integration configurations, including CSP production of high-pressure, high-temperature steam that can be directly injected into the steam turbine to supplement or displace fossil fuel generated steam of the same conditions. Second, the commenter stated, EPA's Hybrid subsection also states that the non-emitting solar thermal generation in a hybrid power plant requires a "steam turbine that is 10 to 20 percent larger than a comparable fossil only EGU to accommodate the additional steam load during sunny hours." In fact, according to the commenter, there is no requirement that the turbine is 10 to 20 percent larger. The commenter stated that the turbine can be the same size as the fossil-only EGU or some percentage larger, depending upon the design of the plant and the desired outcome of the project.
The EPA notes the comment. It does not change our BSER determination.
Reduction in Generation Associated with Dispatch Changes, Renewable Generation, and Demand Side Energy Efficiency
Commenters 149, 158, 165, 171, 183, 189, 215, 260 stated EPA properly rejected building blocks 2 through 4 of its proposed Section 111 (d) rule for existing sources as BSER for modified and reconstructed EGUs. Commenter 165 indicated their comment for the 111(d) proposal provides reasons against these building blocks. Commenters 171, 260 stated two reasons for which these building blocks cannot be BSER. First, according to the commenter, it is not possible in advance to determine which sources would be able to take advantage of such programs, so it is not possible to estimate the cost of this option. Second, the commenter stated, this option exceeds the scope of EPA's authority to regulate sources subject to Section 111(b). According to the commenter, EPA simply lacks the authority under the CAA to require modified and reconstructed sources to institute dispatch changes or require demand side energy efficiency improvements. Commenter 149 stated unit-specific controls are the only appropriate BSER options for modified and reconstructed units under section 111(b)'s unit-specific emission rate standards.
 We thank the commenters for their support.
Commenters 150, 197 agreed with EPA's assessment that re-dispatch to lower emitting sources, renewable generation, and demand side energy efficiency are not BSER for modified and reconstructed sources, as these are all outside-the-fence measures and beyond the scope of traditional regulation under section 111(b). 
With respect to building blocks two, three and four, commenter 187 stated EPA may not take into consideration carbon reduction requirements that rely on measures taken by entities outside of the affected source's control and beyond its fence line to establish standards of performance under CAA Section 111(b). According to the commenter, EPA lacks the authority to regulate outside entities that do not "cause, or contribute significantly to, air pollution which may reasonably be anticipated to endanger public health or welfare," referencing CAA 111(b)(1)(A).
Commenter 192 stated that applying a beyond the fence line BSER analysis for modified and reconstructed fossil fuel-fired EGUs would also be unlawful because EPA lacks the legal authority under the CAA to implement Building Blocks 2-4. According to the commenter, as a federal agency, EPA has limited regulatory authority and can only exercise the power that has been delegated to it by Congress. See North Carolina v. EPA, 531 F.3d 896, 922 (D.C. Cir. 2008) ("Lest EPA forget, it is 'a creature of statute,' and has 'only those authorities conferred upon it by Congress'; 'if there is no statute conferring authority, a federal agency has none.'" (quoting Michigan v. EPA, 268 F.3d 1075, 1081 (D.C. Cir. 2001))). Thus, the commenter stated, it is not enough for EPA show how CO2 emissions from the electricity sector might be reduced. EPA must also demonstrate that it has the legal authority to implement the emission reduction measures that it identifies. EPA cannot do so here. 
Commenter 196 opposed any attempt by EPA to incorporate "building blocks" 2-4 in a Final M&R EGU rule. The commenter opposed any attempt by EPA to expand the BSER evaluation for M&R EGUs to include "building blocks" 2-4. The commenter stated that regarding "building block" 4, in the EGU ESPS Proposed Rule, EPA suggests that this "building block" contemplates not placing the contemplated GHG reductions "entirely upon emitting EGUs; instead . . . measures and policies (e.g., demand-side efficiency programs and renewable portfolio standards")" could be employed "that distribute the burden of complying with GHG rules across other industries." The commenter stated that in the context of the EGU ESPS Proposed Rule, wherein EPA relies on CAA 111(d) to set emission guidelines for states to meet, EPA does not have the authority to regulate any "emission" of any "air pollutant" from any type of "source," irrespective of whether it might be desirable (or not) to spread compliance burdens across a broad swath of entities. The commenter stated the same holds true for the M&R EGU Proposed Rule, wherein EPA relies on CAA 111(b) as the statutory authority. The commenter stated CAA 111(b) requires EPA to promulgate Federal "standards of performance" for "new sources," included modified and reconstructed sources, within each "category" of "sources" the Administrator has determined "causes, or contributes significantly to, air pollution which may reasonably be anticipated to endanger public health or welfare." According to the commenter, the language of the CAA is clear - the Federal "standards of performance" contemplated by CAA 111(b) are for sources within the designated source "category" that are the subject of the rulemaking at issue. EPA has no authority or discretion to deviate from this plain language and attempt to impose burdens on other sources (whether in a CAA 111 source "category" or not). As such, the commenter encouraged EPA not to move forward with "building blocks" 2-4 when evaluating BSER for M&R EGUs. The commenter stated that if EPA nonetheless decides to move forward with such an approach, the Agency must provide a separate comment period for this action as the M&R EGU Proposed Rule does not provide any specificity on how "building blocks" 2-4 would be used to determine BSER for M&R EGUs. 
Commenter 195 supported EPA's conclusion that these various approaches are not BSER but for a different reason than the one articulated by EPA. Importantly, the commenter stated, these approaches are beyond-the-unit measures that require actions completely beyond the direct control of the source. The commenter stated Section 111 requires that the "best system of emission reduction" be both "achievable" and "adequately demonstrated." The commenter also stated under section 111, any designated system of emission reduction must be "applied" to the affected source. The commenter stated, to be achievable and adequately demonstrated for a source, a system of emission reduction must, at the very least be capable of being implemented by the source in a "reasonably reliable, reasonably efficient," and reasonably cost-effective way. The commenter stated that beyond-the-unit measures such as re-dispatch, renewable energy, or end-use energy efficiency-all of which require the participation of entities other than the owner or operator of an affected EGU-cannot meet these requirements because the implementation of those measures cannot be controlled by the source or its owner or operator. According to the commenter, EGU owners and operators cannot require their customers to use less electricity in order to reduce their own emissions. The commenter stated EGUs cannot require renewable energy developers to install additional capacity, or require the dispatch of renewable energy or NGCC capacity as replacement energy for coal- or other fossil-fueled generation. The commenter stated that for EPA to rely on these beyond-the-unit measures in its BSER determination would be well beyond the Agency's legal authority under section 111(d) and would provide clear grounds for the rule's invalidation. 
Building blocks are not included in this final rule.
Commenter 284 stated the Building Blocks 2 through 4 are not appropriate BSER for any source. According to the commenter, it is irrelevant that the Proposed Rule covers only sources that are modified or reconstructed. The commenter stated Building Blocks 2 through 4, as proposed in the 111(d) guidelines, are inappropriate for inclusion in this or any other rule because they are not source-specific technological or operational measures, rather, they are unlawful attempts to limit existing sources' emissions by shutting them down, curtailing their operation, or reducing demand for the good that they produce. The commenter stated this was not Congress' intent in authorizing the establishment of standards of performance under Section 111. The commenter stated as the term "standards of performance" itself suggests, Section 111 authorizes EPA or, under Section 111(d), the States to establish standards governing how sources perform, not standards that are designed to limit or prohibit their performance altogether. Simply, the commenter stated, Building Blocks 2 through 4 are not proper elements of BSER because they have nothing to do with the performance of individual sources. 
Commenters 149, 257 agreed with EPA's proposed rejection of Building Blocks 2 through 4 of its proposed Section Ill (d) existing source rule as BSER for modified and reconstructed units. According to the commenter, EPA's proposal for modified and reconstructed units includes only unit-level controls (which are essentially Building Block 1 measures), and expressly rejects the "outside of the fence" and beyond-the-affected-source category measures applied in Building Blocks 2-4 of its proposed Section 111(d) existing source rule as BSER for modified and reconstructed units. The commenters stated that unit-specific controls are the only appropriate BSER options for modified and reconstructed units regulated under section 111(b), as implementing Building Blocks 2-4 as part of a performance standard for modified and reconstructed EGUs would require EPA to impose legal obligations on a broad swath of unspecified entities that either consume or can displace generation from those EGUs. In addition, the commenters stated, EPA's proposed 111 (d) guidelines are based on average, statewide emission rates, unrelated to emission rates that may be achievable by modified or reconstructed EGUs, and by definition, these statewide standards are not achievable by individual units. Commenter 149 stated the point of compliance differs from that under the 111(d) rule, because under 111(d) EPA's proposed point of compliance is at the state level. The commenter stated units cannot achieve rate-based reductions through measures undertaken by states, as these units do not have access to the broad "system" on which EPA based the Building Blocks used in the proposed section 111(d) guidelines in the same way states do. Accordingly, the commenter stated, section 111(b) emission standards must be restricted only to those reductions that can be achieved by the individual source.
The EPA concluded that these options were inappropriate for BSER due to site specific constraints for existing EGUs on a nationwide basis. See section VII.B of the final rule preamble of the EGU GHG NSPS for EPA's response to this comment.
Commenter 192 stated a Section 111 standard of performance cannot require a source to reduce or cease operations. The commenter stated that, as EPA acknowledges in the Section 111(d) proposal, incorporating Building Blocks 2-4 reduces overall GHG emissions from the power sector by shifting electricity generation from coal-fired EGUs to other EGUs that produce fewer GHG emissions per unit of electricity. According to the commenter, EPA's proposed application of Building Blocks 2-4 to existing sources would reduce overall coal generating capacity by 24%, but requiring a coal-fired EGU that may be planning a modification or reconstruction to reduce operations, or possibly cease operations entirely, cannot be a lawful system of emissions reduction under Section 111.
Commenter 284 stated Building Blocks 2 through 4 are not appropriate BSER for any source because they have nothing to do with the performance of individual sources.. According to the commenter, they are unlawful attempts to limit existing sources' emissions by shutting them down, curtailing their operation, or reducing demand for the good that they produce. The commenter stated this was not Congress' intent in authorizing the establishment of standards of performance under Section 111. The commenter stated that as the term "standards of performance" itself suggests, Section 111 authorizes EPA or, under Section 111(d), the States to establish standards governing how sources perform, not standards that are designed to limit or prohibit their performance altogether.
The EPA concluded that these options were inappropriate for BSER due to site specific constraints for existing EGUs on a nationwide basis. See section VII.B of the final rule preamble of the EGU GHG NSPS for EPA's response to this comment.
According to commenter 183, there are numerous technical issues which illustrate how these building blocks have not been adequately demonstrated for Texas's competitive intrastate electricity system and are unachievable, particularly on EPA's proposed timeline. The commenter provided the following discussion with respect to Texas:
"Even with these shortcomings, it is apparent as a threshold matter that EPA's central assumption of a multi-state electricity system underlying its BSER is arbitrary and capricious as to Texas and undermines the proposed building blocks 2, 3, and 4. As EPA correctly notes, 'all of the lower-48 states, with the exception of Texas, are part of a multi-state, regional grid.' Yet, EPA's proposed building blocks 2, 3, and 4 completely fail to account for Texas's unique status. Repeatedly throughout its justifications, EPA relies on the multi-state nature of electricity transmission in the country but fails to account for Texas's differences, including its competitive market. ERCOT is not a "regional entity" that can "accommodate the[] substitutes" that these building blocks would mandate. The trading programs cited by EPA involve interstate trading, and, thus, the analogy breaks down in connection with ERCOT. Even the State-only programs EPA relies on involved states that could import electricity because their grid was connected. None of these basic assumptions apply to ERCOT."
The commenter stated that even if the building blocks could be achieved, EPA's proposal does not provide adequate time to achieve them. The commenter's experience in Texas is that it takes a substantial amount of time to make the kinds of infrastructure changes EPA's proposal would mandate. The commenter concluded that EPA must reevaluate both the substantive aspects of building blocks 2, 3, and 4, as well as the proposed timeline for implementing them, and as proposed, building blocks 2, 3, and 4 have not been adequately demonstrated for Texas.
The EPA concluded that these options were inappropriate for BSER due to site specific constraints for existing EGUs on a nationwide basis. See section VII.B of the final rule preamble of the EGU GHG NSPS for EPA's response to this comment.
Commenter 183 stated EPA's building blocks 2, 3, and 4 would extend to matters over which EPA does not have regulatory jurisdiction. The commenter stated EPA "is a creature of statute" and thus "has no power to act unless and until Congress confers power upon it." The commenter stated that if EPA lacks authority under the CAA to promulgate a rule, its action is "plainly contrary to law and cannot stand." According to the commenter, nowhere does the CAA give EPA the sweeping authority to regulate either the electricity sector as a whole or the generation, transmission, and consumer use of electricity. 
Commenter 183 also stated building blocks 2, 3, and 4 are inconsistent with the text of the CAA. Section 111(b) explicitly limits EPA to establishing "standards of performance for new sources." "[N]ew source," in turn, is defined as "any stationary source ...." The Act also narrowly defines "stationary sources" as any individual "building, structure, facility, or installation which emits or may emit any air pollutant." Thus, the required standard can only extend to the specific stationary sources at issue (here, EGUs) by category or subcategory, not the entire electric generation sector. EPA's building blocks 2, 3, and 4 extend well beyond the stationary source categories that EPA may regulate. Furthermore, EPA's BSER must be based on adequately demonstrated technology for such sources. In all prior Section 111 rulemakings, EPA has limited its BSER to technology-based emissions controls that could be installed and implemented at sources at a reasonable cost. Implementation of building blocks 2, 3, or 4 to modified or reconstructed sources would, thus, conflict with the plain terms of the statute and arbitrarily depart from previous EPA practice.
Commenter 215 stated that Section 111 requires that any NSPS be achievable by individual sources in listed source categories using measures that are implemented at the sources themselves. Section 111 states in plain terms that its standards of performance apply only to "new sources within [a listed] category." See CAA section 111(b)(1)(B). The CAA narrowly defines the stationary sources that may be regulated under this provision to any individual "building, structure, facility, or installation which emits or may emit any air pollutant." See CAA section 111(a)(3). Commenter said a 1986 EPA memorandum emphasizes just how narrow the "stationary source" regulated under Subpart Da is, noting that the affected facility under Subpart Da effectively ends at the boundaries of the boiler island. See Memorandum from John B. Rasnic, Acting Dir., Stationary Source Compliance Div., EPA OAQPS, to James T. Wilburn, Chief, Air Compliance Div., EPA (Nov. 25, 1986). Commenter added that any NSPS must be "achievable" based on a source applying the "best system of emission reduction" that has been "adequately demonstrated." See CAA section 111(a)(1). The achievability requirement indicates that Congress intended standards of performance to be based on systems of emission reduction that can be applied by (and thus, are within the control of) an individual source. Commenter said a standard cannot be "achievable" for a source if the source must rely on measures taken by some other entity that it does not control in order to meet the standard. 
Commenter 215 said EPA's own history of rulemaking confirms the narrow scope of section 111, since every NSPS or emission guideline that EPA has ever issued was based on measures that individual sources can implement through technological, design, or operational changes at the source itself. In Subpart Da alone, EPA has promulgated or revised standards of performance for emissions of sulfur dioxide ("SO2"), NOx, and other pollutants on several occasions since 1971, and in those rulemakings EPA has never even considered basing an NSPS on measures like Building Blocks 2, 3, or 4 - even though reducing demand for energy from coal-fired EGUs could result in aggregate reductions of those emissions in precisely the same way it could result in CO2 emission reductions. See 36 Fed. Reg. 24,876 (Dec. 23, 1971) (promulgating Subpart D); 44 Fed. Reg. 33,580 (June 11, 1979) (promulgating Subpart Da); 63 Fed. Reg. 49,442 (Sept. 16, 1998) (amending Subpart Da); 77 Fed. Reg. 9304 (Feb. 16, 2012) (amending Subpart Da). Commenter said Building Blocks 2, 3, and 4 are based on measures that reach beyond individual sources in the regulated source category, and these measures cannot form the basis of an achievable standard for individual reconstructed or modified Subpart Da units. The owner of an individual coal-fired utility boiler cannot control the dispatch of NGCC units relative to other fossil fuel-fired EGUs, nor can it make changes in the design or operation of its boiler that generate renewable energy or that lead consumers to use less electricity. Commenter said implementing Building Blocks 2, 3, and 4 as part of an NSPS for reconstructed or modified EGUs would require EPA to impose legal obligations on a broad swath of unspecified entities that either consume or can displace generation from those EGUs. Commenter believed this would plainly violate section 111(b) of the CAA, which unambiguously limits the scope of EPA's regulatory authority to individual new, modified, and reconstructed stationary sources that fall within a category that "causes, or contributes significantly to, air pollution which may reasonably be anticipated to endanger public health or welfare." CAA section 111(b); therefore, Building Blocks 2, 3, and 4 cannot provide the basis for a legally supportable NSPS. 
The EPA concluded that these options were inappropriate for BSER due to site specific constraints for existing EGUs on a nationwide basis. See section VII.B of the final rule preamble of the EGU GHG NSPS for EPA's response to this comment.
Commenter 192 stated EPA lacks authority to implement Building Blocks 2-4.  The commenter stated applying a beyond the fence line BSER analysis for modified and reconstructed fossil fuel-fired EGUs would also be unlawful because EPA lacks the legal authority under the CAA to implement Building Blocks 2-4. The commenter stated that as a federal agency, EPA has limited regulatory authority and can only exercise the power that has been delegated to it by Congress. The commenter referenced North Carolina v. EPA, 531 F.3d 896, 922 (D.C. Cir. 2008) ("Lest EPA forget, it is 'a creature of statute,' and has 'only those authorities conferred upon it by Congress'; 'if there is no statute conferring authority, a federal agency has none.'" (quoting Michigan v. EPA, 268 F.3d 1075, 1081 (D.C. Cir. 2001))). According to the commenter, it is not enough for EPA show how CO2 emissions from the electricity sector might be reduced; EPA must also demonstrate that it has the legal authority to implement the emission reduction measures that it identifies. EPA cannot do so here. 
The EPA concluded that these options were inappropriate for BSER due to site specific constraints for existing EGUs on a nationwide basis. See section VII.B of the final rule preamble of the EGU GHG NSPS for EPA's response to this comment.
Commenter 192 stated EPA cannot include Building Block 2 in a standard of performance for modified and reconstructed coal-fired EGUs because it does not have the authority to make electricity dispatching decisions. The commenter stated the FPA creates a division of responsibility between the States, on one hand, and the federal government (through FERC), on the other, reserving to the States jurisdiction "over facilities used for the generation of electric energy or over facilities used in local distribution or only for the transmission of electric energy in intrastate commerce." 16 U.S.C. - 824(b)(1). In turn, "[f]ederal regulation - extend[s] only to those matters which are not subject to regulation by the States." Id. section 824(a) (emphasis added); see Ark. Elec. Co-op. Corp. v. Ark. Pub. Serv. Comm'n, 461 U.S. 375, 377-78 (1983); Fed. Power Comm'n v. S. Cal. Edison Co., 376 U.S. 205, 215-16 (1964).
The commenter stated numerous judicial decisions have read the FPA and the other federal energy statutes as retaining the States' "traditional responsibility in the field of regulating electrical utilities for determining questions of need, reliability, cost and other related state concerns." Pac. Gas & Elec. Co. v. State Energy Res. Conservation & Dev. Comm'n, 461 U.S. 190, 205 (1983); see also Elec. Power Supply Ass'n v. FERC, 753 F.3d 216, 218 (D.C. Cir. 2014) (FERC rule "encroach[ed] on the states' exclusive jurisdiction to regulate the retail market"); New York v. FERC, 535 U.S. 1, 20 (2002) ("FERC's jurisdiction over the sale of power has been specifically confined to the wholesale market." (emphasis omitted)); Niagara Mohawk Power Corp. v. FERC, 452 F.3d 822, 824 (D.C. Cir. 2006) ("States retain jurisdiction over retail sales of electricity and over local distribution facilities."); Duke Energy Trading & Mktg., L.L.C. v. Davis, 267 F.3d 1042, 1056 (9th Cir. 2001) ("Retail sales of electricity 'are within the exclusive jurisdiction of the States'."). As a result, the courts have consistently rejected federal attempts to intrude on the States' authority in these areas. See, e.g., S. Cal. Edison Co. v. FERC, 603 F.3d 996, 1000-02 (D.C. Cir. 2010) (FERC lacked jurisdiction to preempt State authority to "set the netting period for station power - i.e., the pricing mechanism - in the retail market"); Piedmont Envtl. Council v. FERC, 558 F.3d 304, 315 (4th Cir. 2009) (FERC lacked permitting authority where a State commission "engage[d] in a legitimate use of its traditional powers"); Detroit Edison Co. v. FERC, 334 F.3d 48, 54 (D.C. Cir. 2003) (ruling that FERC actions infringed on State retail jurisdiction). 
Commenter 192 also stated at the most fundamental level, States have the authority to determine whether to operate a vertically integrated or competitive market system and to establish parameters under which those systems operate. The commenter stated that applying Building Block 2 would require replacement of coal- and oil/gas-fired generation with NGCC generation, but that is precisely the type of dispatching decision that is left to the States under the FPA. See Detroit Edison Co., 334 F.3d at 49 ("Retail service [subject to State authority] " denotes transmission or distribution to end users."); see also In re S. Cal. Edison Co., D. 05-01-054, 2005 WL 350964 (Cal. P.U.C. Jan. 27, 2005) (discussing State regulation of dispatch). Thus, the commenter stated, EPA cannot require increased generation at NGCC facilities as part of a standard of performance for modified and reconstructed coal-fired EGUs when dispatching decisions are made by the State. Furthermore, the commenter stated, to the extent that there is any residual federal authority over dispatching decisions at the federal level, it does not belong to EPA. See, e.g., New York, 535 U.S. at 19-20 ("[T]he text of the FPA gives FERC jurisdiction over the 'transmission of electric energy in interstate commerce and "the sale of electric energy at wholesale in interstate commerce.'" (quoting 16 U.S.C. section 824(b))). The division of authority between federal and State authorities under the FPA is clear and leaves no role for EPA to play.
The EPA concluded that this option was inappropriate for BSER due to site specific constraints for existing EGUs on a nationwide basis. See section VII.B of the final rule preamble of the EGU GHG NSPS for EPA's response to this comment.
Commenter 192 stated EPA lacks authority to implement building blocks 3 and 4. The commenter stated incorporating Building Blocks 3 and 4 into Section 111(b) standards of performance would require EPA to look beyond the affected source categories at issue in this proposed rule and impose legal obligations on nuclear energy generators, renewable energy generators, and retail electricity consumers; EPA lacks authority to do so. The commenter stated EPA cannot include Building Block 3's reliance on avoided retirement of nuclear generating capacity because it has no regulatory oversight of nuclear facilities. The commenter stated that under the Atomic Energy Act, the Nuclear Regulatory Commission ("NRC") is given the authority to issue, renew, and, if necessary, revoke commercial licenses for nuclear energy facilities. 42 U.S.C. section 2133. Further, the commenter stated, the savings clause in the Atomic Energy Act states that "this section shall not be deemed to confer upon any Federal, State, or local agency any authority to regulate, control, or restrict any activities of the Commission." Id. section 2018. Thus, the commenter stated, EPA lacks the authority to overrule an NRC decision regarding licensing of nuclear facilities and cannot otherwise compel a nuclear energy facility to remain in operation.
The EPA concluded that these options were inappropriate for BSER due to site specific constraints for existing EGUs on a nationwide basis. See section VII.B of the final rule preamble of the EGU GHG NSPS for EPA's response to this comment.
Commenter 192 stated EPA lacks authority to impose a State-specific renewable portfolio standard ("RPS") or otherwise mandate the construction of new renewable energy sources. The commenter stated that consistent with the States' general authority over electricity generation, dispatching, and transmission under the FPA, RPS have come exclusively from the States; that authority cannot be usurped by EPA. The commenter stated that further, nothing in the Clean Air Act suggests that Congress has given EPA authority to establish an RPS program as a means of reducing GHG emissions. In fact, the commenter stated, Congressional action with respect to the Renewable Fuel Standard ("RFS") and inaction with respect to several RPS bills confirm that the Clean Air Act does not currently authorize EPA to impose an RPS. The commenter stated the RFS program requires that minimum quantities of renewable fuel be blended into gasoline and diesel fuel in an effort to reduce GHG emissions associated with automobiles. The commenter stated EPA's authority to implement the RFS program was not inherent in the Clean Air Act, but required Congressional action in the Energy Policy Act of 2005 and the Energy Independence and Security Act of 2007 to set the specific volumes of renewable fuel that must be blended into transportation fuels. See 42 U.S.C. section 7545(o). In contrast, the commenter stated, Congress has repeatedly considered (but failed to pass) bills that would establish similar renewable energy standards for the electricity sector. See, e.g., S. 3813, 111th Cong. (2010); H.R. 890, 111th Cong. (2009); H.R. 2454, 111th Cong. (2009). Taken together, the commenter stated, this confirms that Congress has not given EPA authority to mandate the construction of new renewable energy sources.
See section VII.B of the final rule preamble of the EGU GHG NSPS for EPA's approach to identification of BSER.
Commenter 192 stated EPA lacks authority to impose mandatory demand-side energy efficiency improvements program. The commenter stated Energy Efficiency Resource Standards ("EERS") programs, like RPS programs, are adopted and implemented at the State level and reflect the exercise of authority that was reserved to the States. Indeed, the D.C. Circuit recently recognized "the states' exclusive jurisdiction to regulate the retail [electricity] market" under the FPA. Elec. Power Supply Ass'n, 753 F.3d at 218. The commenter stated that case is directly applicable here because the court invalidated FERC's "demand-response" rule, which sought to "incentivize retail customers to reduce electricity consumption." Id. The commenter stated that consistent with the States' authority under the FPA, the general federal approach to energy efficiency is based on voluntary programs, such as tax incentives and grants, rather than mandatory energy efficiency measures. Further, the commenter stated, nothing in the Clean Air Act suggests that EPA has authority to impose mandatory energy efficiency obligations. The commenter also stated that nor has EPA ever asserted that it possessed such authority in the past. Instead, the commenter stated, EPA's website highlights State programs, such as energy efficiency portfolio standards and building codes, as means to improve energy efficiency
See section VII.B of the final rule preamble of the EGU GHG NSPS for EPA's approach to identification of BSER.
In response to EPA seeking comment on potentially setting a standard for load following NGCCs as well as the impact of machine degradation and the impact of auxiliary equipment such as battery stations and flywheels, commenter 131 stated it will be extremely hard to determine under the complexity of the building block approach, what units in what states and placement on the grid could be called or designated load following. According to the commenter, with most of the NGCC fleet presumably going to base load (they need to move up more than 25% in capacity factor) under building block 2, it is it is not even, at this time, reasonable to determine how many units could fall into this category. Similarly, the commenter stated that the issue of batteries and fly wheels are technologies just emerging and not enough is known to make informed estimates of the impact. The commenter refers EPA to comments made regarding NGCC degradation with performance under the ESPS. 
See section VII.B of the final rule preamble of the EGU GHG NSPS for EPA's approach to identification of BSER. See section IX.B.2 of the final rule preamble of the EGU GHG NSPS for EPA's approach to subcategorization.
Commenter 142 stated the modified and reconstructed BSER approach taken by the EPA under section 111(b) is completely different than the approach the EPA took when applying BSER to existing sources under section 111(d). The commenter stated that according to the FCAA, BSER is applied to the source, thus, inclusion of building blocks two, three, and four is not appropriate for modified or reconstructed units regulated under section 111(b ), nor is it appropriate for existing sources regulated under section 111(d). Additionally, the commenter stated, the modified and reconstructed BSER approach taken by the EPA under section 111(b) is completely different than the approach the EPA took when applying BSER to existing sources under section 111(d), and the EPA has provided no justification for why existing source BSER is more stringent than modified or reconstructed BSER under section 111(b). The commenter stated BSER was applied to the source under the modified and reconstructed rule; whereas, the EPA applied BSER to the electric grid in determining state goals under section 111( d). According to the commenter, the EPA offers no compelling reason why the application of BSER proposed on the same day, potentially being applied to the same sources, is so dramatically different. The commenter stated for example, the standards proposed for modified utility boilers call for a unit-specific emission limit based upon the unit's best CO2 emission rate (from 2002 to date of modification) plus a two percent reduction, with an emission limit no lower than 1,900 lb CO2/MWh-net; yet, the proposed Texas state goal for all sources is 791lb CO2/MWh, which includes 45 percent of the state's total fossil fuel-fired electrical generation being supplied by coal-fired utility boilers with an average emission rate of 2,239 lb CO2/MWh. The standard for new, modified, and reconstructed large natural gas-fired turbines is 1,000 lb CO2/MWh-gross compared to the proposed Texas state goal for all sources of 791lb CO2/MWh. 
See section VII.B of the final rule preamble of the EGU GHG NSPS for EPA's approach to identification of BSER.
Commenter 183 stated EPA correctly recognizes that Section 111 standards may only apply to the affected source and not to the interconnected electricity grid as a whole. The commenter stated this is compelled by the statutory and regulatory framework, in contrast to the over-reaching existing source standard that EPA has proposed. The commenter stated EPA's determination in this proposal that its "building blocks" 2, 3, and 4 are inappropriate for modified and reconstructed sources confirms the need to withdraw EPA's Section 111(d) Existing Unit Proposal based on the same reasoning. The commenter stated the two proposals, which are required to be related under Section 111, are in fact irreconcilable. The commenter stated EPA originally proposed concurrent comment periods for the Modified and Reconstructed Unit Proposal and the Existing Unit Proposal, as they seek comment on many similar issues and the proposals are interrelated in some respects. The commenter stated EPA extended the comment period on the Existing Unit Proposal, but not the Modified and Reconstructed Unit Proposal. Thus, the commenter will necessarily address issues of relevance to this proposal in its subsequent comments on the Existing Unit Proposal and vice versa and hereby incorporates by reference its comments from each docket into the other.
Commenter 146 stated EPA illegally relied on the building block measures as the foundation for its Proposed Existing Source Guidelines for existing fossil fuel-fired EGUs. The commenter stated it plans to submit comments on the Proposed Existing Source Guidelines fully addressing the myriad ways in which reliance on these "building block" measures is inconsistent with section 111 of the CAA. The commenter stated that for the same reasons that will be discussed in those comments (which the commenter incorporates by reference), EPA may not rely on those measures to support its proposed NSPS for modified and reconstructed EGUs. 
See section VII.B of the final rule preamble of the EGU GHG NSPS for EPA's approach to identification of BSER.
Efficiency Improvements Achieved Through a Combination of Best Operating Practices and Equipment Upgrades
Commenter 150 stated EPA does not have authority under section 111(b) of the Clean Air Act to require an energy efficiency audit or to impose source-specific standards. 
Energy audits are not included in this final rule.
Commenter 260 agreed with EPA that efficiency improvements achieved through the use of the most efficient generation technology (i.e., a supercritical pulverized coal or supercritical CFB boiler) do not constitute BSER for modified EGUs. The commenter stated that the existing fleet of EGUs is numerous and diverse in size and configuration, making it impossible to estimate the cost of upgrading the steam cycle and auxiliary equipment to the most efficient generating technology. Further, according to the commenter, requiring a unit to meet levels achievable by a supercritical unit, when it was not originally designed to do so, could necessitate significant modifications that could make it uneconomical to continue operating the source, thereby forcing the source to retire rather than make the modification. The commenter stated that alternatively, existing fossil-fired sources could simply continue to operate without making modifications that trigger application of CO2 performance standards, resulting in greater CO2 emissions over the long-term.
We thank the commenter for their support. Note that EPA's approach to identification of BSER is discussed in section VII.B of the final rule preamble of the EGU GHG NSPS. 
Commenter 242 stated their belief that the type of flexibility (associated with allowing modified sources to "elect" to meet a unit-specific emission standard determined by the implementing authority based on implementation of energy efficiency opportunities) is what is necessary in order to address issues that will arise as states develop and implement Section 111(d) plans. The commenter believes 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.
See section VI.C of the final rule preamble of the EGU GHG NSPS for EPA's response to this comment.
Commenter 258 stated newer facilities that are subject to the modified/reconstructed sources rule should be able to take advantage of the energy assessment regardless of whether they are affected sources under 111(d).
The commenter is concerned that recently constructed facilities that undergo modification will not be able to meet an emission limit that is two percent less than the best demonstrated annual historical operating performance. The commenter proposed a reasonable alternative to the existing text whereby facilities in the above-mentioned situation that were constructed after 2002 would be subject to the emission standard implementation process proposed in 60.5520(b)(2). The commenter stated an independent energy assessment would identify heat rate improvements and possible changes to business as usual practices that could increase facility efficiency without creating an unrealistic burden for the facility.
The commenter stated EGUs constructed after 2002 are likely already using the most efficient generation technology available (supercritical boilers for large sources and subcritical boilers for small sources) and achieving a two percent reduction based on operational improvements and equipment upgrades alone may not be possible. The commenter stated the GHG Abatement Measures Technical Support Document cited studies in determining possible facility improvements characterized by the current U.S. coal-fired EGU fleet. The commenter stated current U.S. coal-fired EGU fleet has facilities decades old in operation and the improvements that these facilities could implement are far different from the options available to a newer facility. It should be in the interest of the US EPA to provide rules that are fair to all facilities subject to the 111(b) rulemaking and it is under that premise that newer facilities should be treated differently.
Neither the energy assessments nor the additional 2 percent reduction are not included in this final rule.
Commenter 263 stated that in setting the proposed emissions limits, EPA has not accounted for factors such as the diminishing gains in efficiency over time due to aging equipment. The commenter stated that to maintain a consistent CO2 rate improvement, units will need continual replacement of equipment, which was not considered by EPA in the cost calculations provided for this proposal. For these reasons, and the others stated above, the commenter suggested the selection of unit-specific emission limits for reconstructed units and modified utility boilers, including those that modify prior to becoming subject to a CAA 111(d) plan. The commenter stated the preferred and most flexible alternative of those presented by EPA is the unit-specific case-by-case assessment of modified or reconstructed units to achieve greater energy efficiency, and emission rates that are set based on those assessments.
The commenter stated that given that the practicable standard would be to set unit-specific emission limits based on energy efficiency improvement audits, the criteria for these audits is of particular interest. The commenter stated that EPA's proposal that energy assessments be conducted by professionals with energy experience is appropriate given that companies are required to certify the truth and accuracy of the information they provide to the EPA and Section 111 implementing authorities. However, the commenter stated, requiring individuals that perform energy assessments to be certified is not necessary. The commenter stated requiring certification of energy assessors places an unnecessary administrative and financial burden on the State when implementing 111(b), particularly where EPA is not proposing any new resources to assist states with implementation.
See section VII.B of the final rule preamble of the EGU GHG NSPS for EPA's approach to identification of BSER.
NGCC Technology with Partial CCS
Commenter 215 stated that EPA correctly rejected the use of CCS and high efficiency simple cycle aero-derivative turbines as BSER for combustion turbines. 
Commenter 211 supported EPA's determination that CCS technology is not BSER for any reconstructed or modified source subject to this rulemaking, including coal-fired boilers, integrated gasification combined cycle (IGCC) units and stationary combustion turbines. The commenter reiterated EPA's rationale, but also added that insufficient information on costs and site-specific details are not the sole reasons that EPA should reject CCS as BSER for modified and reconstructed sources. The commenter noted a lack of technical information supporting CCS for reconstructed or modified units in the docket or a TSD that would provide any information that would demonstrate the availability of CCS for modified or reconstructed EGUs. According to the commenter, there is insufficient data about how or if CCS technologies could be used on NGCC units, noting that CCS is not adequately demonstrated for such units, nor has it proven to be commercially viable. The commenter referenced numerous EPA determinations regarding whether CCS can be considered BSER for natural gas unit. The commenter stated that CO2 capture technologies do not match well with the operating flexibility of NGCC and simple cycle units, and even if technical barriers could be overcome, application of CCS to gas-fired turbines would also be exceedingly costly on a ton per CO2 avoided basis, especially with regard to retrofitted units. The commenter also noted that EPA has recognized that these costs would have a negative impact on electric prices and the structure of the electric power industry,
Commenter 211 also noted that the administrative record does not support CCS as BSER. Referencing the RIA, the commenter stated that EPA has not generated, reviewed or provided for public inspection adequate cost or technical information on which to propose a CCS standard for any modified or reconstructed unit. The commenter also referenced the GHG Abatement Measures TSD developed for the existing source proposed standards, noting that where EPA has looked at CCS in a retrofit application, it has found a number of substantial reasons (apart from costs or the available space on-site for CCS) why this technology should not be required for modified and reconstructed units. The commenter stated that EPA's conclusion that it did not have sufficient information to require CCS for modified and reconstructed units should on a more robust explanation of the insufficient information in this area, as well as a detailed assessment of the multiple impediments to CCS. According to the commenter, these impediments include not only cost, but physical constraints (both on-site in terms of available space to install additional equipment and the location of a unit relative to the availability of sequestration), operational cycling of natural gas-fired units, and commercial realities (e.g., the availability of financing, impact on cost to dispatch electricity and electricity rates).
According to commenter 211, the proposed modified and reconstructed source rule does not address in any meaningful way the availability of CO2 capture, compression, transportation and storage, nor does such information on these matters appear to be in the docket for this rulemaking. The commenter stated that EPA has also failed to consider the impact of enhanced oil recovery (EOR) regulations and guidelines for Class VI wells. The commenter also stated that these regulations and guidelines could be critical to the availability of CCS and are integral to EPA's assessment of the costs of partial CCS, and without such information and other information cited above, any standard based on CCS would be arbitrary and capricious.
See sections IV.B, VI.B, and VII.B of the final rule preamble of the EGU GHG NSPS for EPA's approach to identification of BSER.
High Efficiency Simple Cycle Aero-Derivative Turbines
Commenter 215 stated that EPA correctly rejected high efficiency simple cycle aero-derivative turbines as BSER
We thank the commenter for their support.
