Commenters 9408, 9657 stated their concern that this rulemaking may become an insurmountable barrier to the prospective construction and operation of new coal-fired electric generation units, thereby compromising a desirable level of energy supply diversity in our nation and in our community. The commenters stated their lack of support for policies that mandate fuel switching, directly or indirectly, should be promulgated as a reasonable means of complying with an emission standard.
Commenter 9426 stated that it is unlikely that electric generators would choose unproven CCS technology if a less risky alternative in NGCC is available. The commenter stated that it is difficult to understand how the proposal would somehow cause generators to pursue coal with CCS over NGCC
See preamble section V.I.4.
Commenter 9201 stated that EPA's rule does not incentivize technology and EPA's rationale is flawed. The commenter stated that there is no incentive to develop CCS, and additionally creates a disincentive by inducing construction of NGCC units that are not burdened with the costs and technological uncertainties associated with CCS. According to the commenter, the proposed rule does not induce better performance from NGCC and the standard is substantially higher than what can be achieved with the best existing technology. The commenter noted that they are not suggesting EPA mandate CCS for NGCC units, but simply pointing out inherent contradiction between the agency's reasoning for setting a standard for new coal plants based upon CCS and the standard for NGCC units. The commenter provided the analogy to DOE's incentive example for lightbulbs in which EPA would in effect be requiring certain manufacturers of light bulbs to become more efficient while exempting others. The commenter concluded that EPA's reasoning is an arbitrary decision and does not satisfy the legal requirements of CAA section 111.
 See preamble section V.L. and V.I.4.
Commenters 9666, 10662 stated that any CCS-based standard unlawfully dictates the choice of technology that Subpart Da sources must use.
According to commenter 9666, this violates section 111(b)(5) of the Act, which provides that nothing under section 111 shall be construed "to authorize the Administrator to require any new or modified source to install and operate any particular technological system of continuous emission reduction to comply with any new source standard of performance." The commenter noted that the proposed NSPS for Subpart Da sources could not be met with anything other than CCS.
Commenter 10662 stated that under CAA Section 111(b)(1)(B)(5), EPA cannot require any particular system of continuous emission reduction.
 The commenters are mistaken.  The final standard of performance is a numerical limit which can be met by any means a source chooses.  The EPA has further shown that there are alternative compliance pathways available which do not need to utilize CCS, which compliance pathways are also demonstrated, available at reasonable cost, and do not have collateral adverse environmental or energy utilization impacts.
Commenters 9666, 10662 stated that EPA cannot use section 111 to mandate the use of unproven control systems under the guise of "promoting technological development."
Commenter 10046 stated that it is unlikely that Congress provided discretion in section 111(b) for EPA to impose a mandate that would retard development of the technology that EPA is trying to force.
 See preamble section III.H.5.d. and other comment responses in RTC 2 on this issue.
Commenters 9666, 10046 stated EPA cannot select as BSER a technology that has not been adequately demonstrated based on an asserted interest in "promoting technological development." According to the commenters, requiring CCS will actually hinder its development by discouraging construction of new Subpart Da units.
Commenter 10046 compared the EPA's FGD technology forcing NSPS with that for CCS, and noted that now, alternative fuels are available.
 The EPA has not selected a BSER solely to promote use of a technology, and its determination would be the same whether or not it considered this factor.  See preamble section III.H.5.d.
Commenter 9666 stated the effective way to encourage technological innovation is to provide developers with greater regulatory flexibility, as the D.C. Circuit recognized in Sierra Club by  allowing EPA to promulgate a less stringent flexible standard that could be met by units experimenting with promising (yet unproven) dry scrubber technology. 657 F.2d at 351.
 The final standard of performance in fact can be achieved a number of different ways of which the EPA is aware.
Commenter 9666 stated EPA provides no support for its assertion that "not identifying partial CCS as the BSER could potentially impede further utilization and development of CCS." 79 Fed. Reg. at 1480. According to the commenter, the Agency has identified several projects currently under construction or in development that plan to integrate CCS, despite the fact that those projects are not subject to any CO2 emission limit based on the use of CCS, and therefore it is unclear why EPA believes the current regulatory status quo that has led to these projects would impede other similar projects from being developed in the future.
Commenter 9426 stated that the EPA contradicts itself by stating that few if any solid fossil-fuel EGUs will be built in the foreseeable future, and that a standard for new coal-fired EGUs based on partial capture "promotes deployment and further development of the technology."
Commenters 7977, 10662 stated that there is a distinction between technology forcing and encouraging technological innovation, and section 111(j) of the CAA specifically provides for the promotion, development, and deployment of innovative technological systems of continuous reduction for technologies like CCS that have not been adequately demonstrated. The commenter stated that, section 103(g) of the CAA provides EPA with the authority to conduct a basic engineering research and technology program to develop non-regulatory technologies and strategies.
Commenter 10046 stated that if the EPA's proposal will not promote the development of CCS technology, then EPA has no legitimate basis to proceed.
Commenter 10046 stated that the EPA should analyze whether the performance standard enhances or diminishes CCS technology or economic risk, or whether the addition of environmental compliance risk (requiring CCS) for one fuel (coal) but not the other (gas) does anything other than force companies to build gas units and avoid coal units.
Commenter 10046 noted that the statue and applicable case law require EPA to set a different standard if in fact the standard it proposes to set would stymie CCS development. The commenter provided citations to support their statement.
The EPA's task is to identify a best system of emission reduction adequately demonstrated and to set a standard predicated on performance of that technology.  The EPA has done so here.  The final standard of performance will encourage new sources  -  indeed will compel them  -  to emit less CO2 than they would if doing business as usual.  Moreover, it is well documented that a regulatory requirement often brings a great influx of technological innovation.  See preamble section V.K. and L., and TSD documenting the history of technological innovation following the 1971 NSPS for this same industry.  We again note that AEP and Alstom, in prior public statements extolling CCS technology reliability and cost-effectiveness, indicated the importance of a firm regulatory framework to promote use of CCS.
Commenter 9201 stated EPA's assertions about the proposed rule's ability to incentivize technological innovation are not adequately explained in the face of the unavailability of CCS technology for commercial power generators. Thus, the commenter noted, EPA's decision to set CCS as BSER over other technologies that represent significant CO2 reductions and incentivize technological innovation of efficient coal generation is unreasoned and arbitrary.
 CCS is an available technology.
Commenter 10048 stated that in the absence of environmental benefits, it appears that EPA's overriding reason for proposing the rule is to provide an incentive to promote adoption of CCS technology; however, as EPA is well aware, CCS is a complex, costly and legally challenging technology that will not be adopted when more cost-effective and less complicated generation alternatives are available.
 As shown in RIA 4, new non-compliant coal technology is not being constructed, for reasons unrelated to this NSPS.  New coal capacity is a technology now being adopted as a means of preserving a diverse energy portfolio, or some other reason than lower cost.  The promulgated standard of performance preserves that alternative by leaving new coal priced competitively with other baseload dispatchable non-NGCC technologies. Moreover, should there be very significant increases in natural gas prices, there may be renewed interest in new coal plants. Issuing a standard that allows construction of new high-emitting coal plants without a CCS requirement therefore poses a nontrivial risk of increased emissions and further exacerbation to climate. Given their long lifetimes, construction of new high-emitting coal plants could lock in their higher emissions for many decades to come.  See preamble section V.K.
Nationwide, Long-Term Perspective
Commenter 9735 stated that the proposed rule provides no graduated or realistic targets over the long-term, but rather immediately sets a low baseline emissions target that cannot currently be achieved on a large-scale or cost-effectively. The commenter further stated that it is necessary to encourage investment in advanced emissions reduction technologies while working toward CCS.
 The EPA has reasonably determined that partial CCS, with highly efficient SCPC, is BSER now.  The EPA must therefore establish a standard of performance reflecting performance of that BSER.
Commenter 9664 discussed the authority of EPA to adopt standards and technologies without requiring a cost-benefit analysis at the plant level as long as the response to the problem and the pollution reduction benefits can be justified at the regional or national level through a broad assessment (see Sierra Club v. Costle, 657 F.2d. at 329-332, S. Rep. No. 95-127 (1977) and H. Rep. No.95-294 (1977)).
 The EAP largely agrees with this comment.
Conversely, Commenter 9666 stated that the Agency may not set an NSPS based on national-scale considerations if it would impose unreasonable costs, environmental impacts, or energy requirements at the individual plant level, rather that the CAA only permits EPA to consider long term effects once it has determined that source-level impacts are consistent with the statutory criteria for NSPS (also citing Sierra Club v. Costle, 657 F.2d at 330). The commenter suggested that EPA improperly focuses on the costs and effects of its CCS mandate on a nationwide, long-term scale at the expense of considering its effects on individual new sources.
 The EPA has considered both plant-level impacts and national impacts in its determinations here.
Commenter 9774 states that the NSPS for coal-fired power plants cannot be based on CCS at this time, and that EPA must correct the NSPS deficiencies and modify the rule to exclude sources that are inappropriately regulated in order to avoid significant issues within the utility sector, including possible delays in CO2 emission reductions.
 The EPA disagrees.  See preamble section V.
Commenter 9425 suggested that these regulations may force several power plants to shut down in a relatively short amount of time. The commenter remarked upon the need for states to have enough time to work with EPA to understand the impacts to fuel diversity and energy reliability in setting the standards, as well as the implementation and timing of the standards.
These standards apply to new sources exclusively, or to modified and reconstructed sources.  There is no question that such a source would be `shut down' when not yet in existence.
Similarly, Commenters 9201, 6429 and 9666 discussed the potential impact of CCS on diversity of fuel supply for the electric grid in terms of both reliability and affordability. Commenter 9666 also stated that although the EPA recognizes that protecting fuel diversity is important and that the costs of CCS will render construction of new coal-fired capacity infeasible under the proposed standard, EPA incorrectly assumes that the CCS mandate will not increase energy prices or change the structure of the energy sector.  Commenters 9201, 6429 and 9666 suggested that because coal will be uncompetitive with natural gas due to CCS, the grid will become less diverse, more susceptible to price spikes and disruptions, and it will be less certain that additional natural gas-fired capacity will reliably meet the basic demand for electricity. Commenter 9426 provided the price increases during the polar vortex as an example, and stated that the proposed standard will distort the true cost of natural gas.
 Coal is already economically non-competitive with natural gas.  See RIA chapter 4.  See preamble section V.I.4. as to why basing a standard of performance on partial CCS will not discourage new coal capacity or use of CCS.  Again, AEP was of the considered public view that CCS represents a lifeline for the industry, not a millstone.
Commenter 10870 also stated its concern that the Proposed Rule will result in the elimination of coal from the nation's fuel portfolio rather than more fuel diversity, leading to less reliable and less affordable electricity as well as less effectively controlled sources of power generation needed for the economy. The commenter further asserted that uncertainty of additional requirements under Section 111(d) will effectively end development of coal-fired electric utility units unless the Proposed Rule is written to exclude any new requirements during the life of the plant.
The standard of performance adopted here does not apply to existing facilities.
Commenter 10048 stated that the majority of renewable energy options are not baseload resources. Additionally the commenter remarked that no significant new nuclear generation is planned, therefore fuel diversity can be expected to decrease.
Public announcements including IRPs confirm that utilities are interested in technologies that could provide or preserve fuel diversity within generating fleets. The Integrated Resource Plan TSD notes examples where the goal of fuel diversity was considered in IRPs; in many cases, these plans considered new generation that would not rely on natural gas. In particular, several utilities that considered fuel diversity in developing their IRPs included new nuclear generation as a potential future generation strategy. See also Global CCS Inst, "The Costs of CCS and Other Low-Carbon Technologies" (2015)p. 1 finding that "[n]uclear generation plant as well as hydro and geothermal platn can also be cost competitive ins ome markets fiven thei high utilisation rates (i.e. can be oeprated 80 to 90 per cent of the time)".
Commenter 9666 remarked that EPA incorrectly assumes in Section II that in the future, coal units without CCS will not be competitive with natural gas units not subject to CCS. The commenter further suggested that coal only becomes uncompetitive once a costly and undemonstrated CCS is imposed.
 See RIA chapter 4.
Commenter 9666 also stated that requiring CCS will not promote coal-fired generation by eliminating future obligatory controls uncertainty as EPA purports since this would be true of any final action EPA takes, regardless of the level of control chosen.  Furthermore, the commenter states that this rulemaking does not confer any advantage because any source that is subject to this proposed NSPS would not be subject to future NSPS controls or revised standards since the controls would apply only proactively, and sources could avoid falling under the revised standard by foregoing modification or reconstruction.
 See preamble section V.L and K. (documenting, among other things, the spurt in technological innovation after promulgation of NSPS based on FGC scrubber technology less well developed than CCS at a comparable point in the regulatory timeline), and see also statements of AEP that regulatory uncertainty was a factor in the decision not to proceed with the Mountaineer demonstration project.
Commenter 9191 stated that each of the facilities cited by EPA involve unique circumstances that do not render CCS appropriate for nationwide application
The EPA disagrees.  See preamble section V.
Commenter 10052 stated that CCS is infeasible in much of the country due to pipeline capacity, site availability and demonstration projects.
Similarly, Commenter 9408 stated that CCS will be particularly difficult to deploy in some geologic formations and implored EPA not to promulgate any standard that relies on CCS in those areas. For example, Florida has an artesian aquifer that underlies the entire State and is a source of potable water for every community in Florida. Because of the aquifer's relative importance, the commenter suggested that it is unlikely that subsurface CCS will ever be allowed in Florida, nor is the risk of potentially compromising the resource by injecting CO2 into it or through it acceptable. The commenter also suggested it is improbable that other State would accept Florida's CO2 emissions to be transported for permanent storage.
 See Section V.M. of the preamble and the technical support document on geographic availability. Potential GS formations are widely available in the United States. The EPA recognizes that geologic conditions to support CO2 storage may not exist in all regions of the country. Where such capacity is unavailable, electricity demand in those areas can be served by coal-fired power plants built in neighboring areas with geologic availability with generated electricity being supplied via transmission line, see Figure 1 of TSD on geographic availability, or the CO2 can be transported to available GS sites via pipeline. For other of those areas, coal-fired power plants are either not being built due to state law prohibition s against building such units, or other available compliance alternatives exist allowing a new coal-fired power plant meeting the promulgated NSPS to be sited. There are alternative means of complying with the final standards of performance which do not necessitate use of partial CCS, so any siting difficulties based on lack of a CO2 repository would be obviated.

The EPA notes that Figure 1 of the technical support document on geographic availability shows the areas of Florida that are within 100 kilometers of a potential GS formation; electricity demand may be served by coal-fired electricity generation built in areas that are proximate with geologic sequestration, and this electricity can be delivered through transmission lines.
Commenter 9426 stated that public education and communication between communities and potential storage project proponents is needed to move forward on a large scale so that landowners are comfortable with the process, monitoring and verification elements of CCS. The commenter provided fracking as an example of possible public reaction.
 Public awareness and support have been widely recognized as critical components in the development of new energy infrastructure, including CCS deployment. Efforts have been made to design strategies for successful outreach to the public. For example, under the DOE Regional Carbon Sequestration Partnerships, DOE has been engaging with local communities to educate and inform them about planned pilot and demonstration projects in their areas. DOE's Best Practices for Public Outreach and Education for Carbon Storage Projects presents lessons learned through the planning and implementation of CCS projects, as well as best practices for community engagement.
Commenter 10089 stated that given the currently sparse CCS market, the electric power sector would be compelled to work from ground zero to become compliant with NSPS. The commenter recommended that further analysis is necessary to ascertain whether CCS is indeed the best system of emission reduction for new power plants.
 The EPA disagrees.  See preamble section V.
Commenter 0775 stated what while CCS may not meet desired cost and energy efficiency goals today, the regulation is a safeguard against coal as the dominant energy source and stimulates CCS technology.
 The EPA disagrees with this comment on every count.  Partial CCS is an adequately demonstrated technology within the meaning of section 111 (a) of the Act.  The objective of a standard of performance is to have new plants perform to a level achievable by the performance of the BSER.  It is not to be a safeguard against use of any particular technology, industrial process, or fuel source, and the EPA has no such objective here.
Energy and Nonair Quality Environmental Impacts
Commenters 9381, 9396, 9592, 9666, 9780 and 10100 stated that the subject has not been adequately assessed the as required by Section 111(a)(1). Commenter 9194 cited 1973 and 1999 court decisions requiring that EPA fully assess non-air and economic impacts.
Commenters 9194, 9381, 9592, 9780 and 10100 noted that additional consideration of environmental impacts of CCS, such as reduced energy efficiency, increased coal use, increased water withdrawal and consumption, increased water discharges, and increased emissions of criteria and toxic pollutants, is required by EPA to meet statutory obligations.
Commenter 9396 cited a 2013 NETL report discussing the significant energy, efficiency, water use, air emissions and cost impacts that could result from partial CCS.
The EPA has carefully considered potential nonair impacts of the final standard of performance, as required by CAA section 111 (a)(1).  EPA has carefully considered the safety of transport and permanent sequestration of captured CO2 and has found reasonably that the regulatory structures of 49 CFR Part 195 (for CO2 pipelines), and Class VI and Class II injection wells (for geologic sequestration and EOR, respectively), with the further complementary monitoring and reporting standards of GHGRP subpart RR, assures safe transport and permanent sequestration.  EPA has also projected that, under a set of assumptions where new non-compliant coal-fired capacity is added,  there will be SO2 (and consequent secondary PM) reductions associated with use of partial CCS (due to the need for ultrahigh purity solvent).  See RIA chapter 5.3 and Table 5.1.   Issues of water use are addressed at preamble section V.O.2.
Commenter 9396 cited a NETL report to estimate that to meet EPA's proposed standard with an SCPC, it would require:
   *  a capture rate between 30 and 50%
   * an additional 180,000 to 300,000 tons of coal each year
   * a decrease in net fuel efficiency from 39% to 33-35% and heat rate from 8687 Btu/kWh to 9695-10379 Btu/kWh
   * an increase in water withdrawal of 16-30% and consumption by 14-26%
   * an increase of NOx, Hg, and PM by 2-7%
   * the capital cost by 26-39%
   * the operating cost by 30-43%
   * and cost between $79 and 102 per tonne of CO2 avoided.
The commenter asserted that these results indicate a full energy and environmental impact assessment is warranted and has not been conducted.
 These estimates reflect full CCS.  The final standard of performance has considerably reduced water use impacts, which the EPA has evaluated and found to be reasonable.  See preamble section V.O.2.
Commenter 9596 stated that EPA should withdraw the NPR in order to evaluate the potential impact of CCS on groundwater and other environmental factors because the current proposal is arbitrary and capricious, and not in accordance with the requirements of the statute.
EPA has carefully evaluated the risks of injected CO2 to underground sources of drinking water (which can include groundwater) in its rules for Class VI and Class II injection wells.  Owners or operators of Class VI wells must develop and implement a comprehensive testing and monitoring plan for their projects that includes injectate analysis, mechanical integrity testing, corrosion monitoring, ground water and geochemical monitoring, pressure fall-off testing, CO2 plume and pressure front monitoring and tracking.  Groundwater and geochemical monitoring is explicitly required.  Owners and operators must periodically review the testing and monitoring plan to incorporate operational and monitoring data and the most recent area of review reevaluation.
Commenter 10033 requested that EPA draw on lessons learned with MTBE to ensure that the benefits of CCS are carefully weighed against the costs and risks of geologic sequestration and CCS.
Storage of a chemical in in-ground, unregulated tanks is in no way comparable to the detailed and comprehensive regulatory requirements for CO2 geologic sequestration in Class VI wells, or the regulatory requirements for use of CO2 for EOR in regulated Class II injection wells.
Commenters 7977, 9648 and 10681 stated that EPA has not addressed parasitic loads.
Commenter 10681 further asserted that the final rule should allow parasitic loads on an IGCC system to be treated similarly to a utility boiler. Commenter 9648 stated that EPA must conduct a lifecycle energy consumption and emissions inventory evaluation and demonstrate that the 25 percent and 50 percent partial capture rate associated with BSER for IGCC and conventional coal-fired utility boilers, respectively, are based on actual performance levels, and the risks associated with implementing a complex technology that delivers the needed emission reductions.
Similarly, Commenters 7977, 9196, and 9780 stated that EPA must investigate how the CCS energy penalty of approximately 30% may impact the technical feasibility of CCS integrated with electricity generation and must be addressed by EPA. Commenter 10039 stated that the energy penalty is at least 40%, requires upsizing of EGU equipment, and results in higher emissions of pollutants. Commenters 9003 and 9648 also noted that additional energy requirements can increase criteria air pollutants and toxic air pollutant emissions, as well as raise nonattainment concerns.
Commenters 10017, 10050, 10552 noted that it is inconsistent and wasteful for EPA to mandate a specific technology (CCS) that consumes a large power load in order to operate. Commenter 7977 also discussed the environmental impacts of increased coal use.
Commenter 10618 cited the DOE and GAO estimates, up to 30% and 32% respectively, for the energy penalty associated with CCS. Commenter 8966 provided a citation stating that the energy penalty may range from 12 to 28%. Commenter 9772 cited a 2013 CRS Report identifying energy penalties from 16 to 40%. Commenter 10680 cited a CRS report identifying energy penalties 19 to 30%, or 10 to 100 times other currently employed control systems.
Commenter 8957 estimated that if plant that sequesters and retains 40% of its own emissions, it will only result in a 12% reduction from the uncontrolled plant for an equivalent net electrical output. The Commenter concludes that therefore, CCS is not currently economically viable due to the significant energy penalty nor is it necessarily environmentally beneficial.
Commenter 10048 stated that the additional power needed to offset the energy penalties, resulting in additional baseload units, carbon emissions and costs, should not be considered reasonable until the energy penalty is minimized.
The EPA has carefully addressed the issue of parasitic loads and finds the potential energy impacts to be reasonable at a per plant level.  See preamble section V.O.3.
Conversely, Commenter 10108 suggested that the BSER determination has met the needs to assess the environmental impacts and notes that the energy penalty is anticipated to decrease as coal plants as efficiency and the availability of advanced technologies increase.
 The EPA largely agrees with this comment.
Commenters 9777 and 9780 also provided referenced estimates of some potential environmental impacts, including a 90%, 87% and 46% increase in water consumption for PC units, for SCPC units and for IGCC plants, respectively, as well as water requirements to compress and transport supercritical CO2.  Commenter 9777 also cited NETL water consumption requirements for EGUs with CCS and stated that EPA should reconsider whether CCS is BSER due to water demands.
See preamble section V.O.2.
Similarly, Commenters 9666 and 10039 stated that CCS will nearly double the amount of water required for energy generation at units subject to the proposed standard. Commenter 10039 stated that EPA must consider the impact on water supply and water quality. Commenter 9497 stated that the proposed rule does not address how water requirements may affect reliability, especially in areas with water shortages.
Commenter 9777 provided results from a study that indicate CCS would increase water withdrawal by 5-7% and consumption by 88-100% by 2030. The commenter stated that water increases raise concerns about CCS feasibility due to water availability, water rights, and costs of long term water purchases, especially in states with water shortages. Commenter 9777 recommended that operational data from a full scale plant would help address concerns regarding water consumption.
Commenter 9666 further stated that the placement of CCS needs to be balanced with water requirements and water availability, and EPA cannot adopt an NSPS that precludes construction of new sources at water-restricted areas in the U.S. in keeping with the CAA, relevant case law, and EPA's past practice (See Sierra Club, 657 F.2d at 330).
See section V.O.2 to the preamble to the final rule.
Commenter 9770 stated EPA's environmental assessments never looked at the water management issues that result from CCS. The commenter observed that the EPA and DOE have never inquired of states whether they would anticipate, given that more than half of the states in the U.S. are in their second year of drought, whether this brackish water might be needed to augment surface and other groundwater resources. The commenter stated there are questions about the threat that injection of CO2 underground would pose to deep saline aquifers. According to the commenter, our municipal utilities have an obligation to protect existing and future drinking water resources located in deep saline aquifers, in addition to providing reliable, affordable and environmentally responsible electricity. The commenter agreed with AWWA regarding the potential threats to future municipal and private drinking water resources from CCS and about how those threats are relevant to EPA's BSER determination
See preamble section V.O.2 for the EPA's consideration of the issue of water use.  Drinking water resources are the focus of protection under the Class VI and Class II UIC regulations.  Preamble section V.N. explains why those rigorous standards result in protection of underground sources of drinking water, and that the siting and monitoring regime which achieves that protection also prevents releases of sequestered CO2 to the ambient air.
Commenter 9666 also stated that EPA has incorrectly attributed a larger water consumption to CCS at gas-fired power plants than coal-fired power plants, thus ruling out CCS as BSER for gas and not for coal plants. However, water consumption would be expected to increase by 70% at gas-fired plants and 90% and 87% for PC and SCPS units. The commenter remarked that the BSER determination effectively bans new coal-fired EGUs, reducing nation's baseload energy diversity and almost exclusively promoting natural gas due to permitting burdens for nuclear and hydroelectric energy generation.
 Water use issues are addressed at preamble section V.O.2.  The final BSER determination does not ban new coal-fired EGUs, and (as expressed by AEP) may provide a means for continued use of coal in new facilities as part of the nation's energy portfolio.
Commenter 9195 provided the following list of questions in relation to sole source aquifers:
   * How did EPA address the cross statutory issues related to the injection and sequestration of CO2 if the injection must go through a sole source aquifer?
   * Please explain how EPA's Office of Air and Radiation and EPA's Office of Water communicated and considered the impact of the proposal on EPA's own special program dedicated to protection of sole source aquifers.
See preamble section V.N.
Commenters 9648 and 9770 stated that EPA has not assessed the impacts of permanent storage of compressed gases. Commenter 9648 stated that the proposed rule transfers air pollution to other environmental media.  Commenter 9648 further stated that altering pressure gradients could cause numerous health and environmental impacts.
Commenter 9648 also cited the SAB's concerns on cross-media issues and recommended that EPA request that NRC conduct an assessment.
Commenter 9648 also stated that a commercial sized partial CCS may not be feasible with power plants with limited space.
EPA has carefully assessed the issues of geologic sequestration, and strongly disagrees with the commenters' assertions that EPA has not studied the issue, and the cursory assertion in comment 9648 that geologic sequestration of captured CO2 could lead to numerous adverse health and environmental impacts.  In particular, the Class VI standards require very proscriptive site evaluation and on-going monitoring.  Owners or operators of Class VI wells must develop and implement a comprehensive testing and monitoring plan for their projects that includes injectate analysis, mechanical integrity testing, corrosion monitoring, ground water and geochemical monitoring, pressure fall-off testing, CO2 plume and pressure front monitoring and tracking, and, at the discretion of the Class VI director, surface air and/or soil gas monitoring. Owners and operators must periodically review the testing and monitoring plan to incorporate operational and monitoring data and the most recent area of review reevaluation. Robust monitoring of the CO2 stream, injection pressures, integrity of the injection well, ground water quality and geochemistry, and monitoring of the CO2 plume and position of the pressure front throughout injection will ensure protection of USDWs from endangerment, preserve water quality, and allow for timely detection of any leakage of CO2 or displaced formation fluids.
Commenter 10661 stated that EPA must address will increase in ammonia emissions, coal ash and boiler slag from CCS deployment, which cannot be captured using control technologies.
The NETL cost estimates include costs for disposal of fly ash and bottom ash.  See NETL (July 2015) at p. 43.  Moreover, ash is generated as a result of coal combustion, not capture of the resulting CO2.  With respect to ammonia emissions, new steam generating EGUs that choose to comply with the final standard of performance by implementing partial post-combustion CCS are likely to use commercially-available amine-based capture systems. Some concern has been raised regarding emissions of amines and amine degradation of amines (e.g., ammonia, NH3) from the capture process. To reduce the amine emissions, MHI introduced the first optimized washing system within an absorber column in 1994, and developed a proprietary washing system in 2003. In that system, a proprietary reagent is added to the water washing section to capture amine impurities such as amine, degraded amine, ammonia, formaldehyde, acetaldehyde, carbonic acids and nitrosamines. MHI has continued to improve this technology for further reduction of amine emissions and established an "advanced amine emission reduction system".
Research performed by MHI at Alabama Power's Plant Barry indicated that an increasing SO3 content in flue gas caused a significant increase of amine emissions. During testing, at Plant Barry MHI applied its proprietary washing system and confirmed that the amine emission were drastically reduced. Others have also studied emissions and control strategies and have determined that a conventional multi-stage water wash and mist eliminator at the exit of the CO2 scrubber is effective at removal of gaseous amine and amine degradation products emissions. Additional research continues in this area
Commenter 9201 asserted that EPA failed to examine the impacts of increased methane emissions from natural gas development needed to supply the power sector. Furthermore, the commenter suggested that the GHG reductions from new high performing SCPC or IGCC would be about 20 percent below the national average for the existing coal fleet. Commenter 9201 therefore remarked that if EPA adjusted the methane global warming potential used in assessment studies to the most recent factor, shale gas has a greater GHG footprint than coal used for electricity over the 20-year time horizon.
The comment that the promulgated NSPS will lead to increase CH4 emissions due to increased use of natural gas has no basis.  New natural gas capacity is being added for reasons unrelated to this standard of performance.  See RIA chapter 4.  The commenter also evidently assumes CH4 emissions associated with natural gas production and transport are uncontrollable, which the EPA does not believe to be the case.
Commenter 10680 stated that upstream emissions from coal mining, processing and transport will be considerably higher because CCS plants will consume more coal.
Issues of parasitic load are addressed at preamble section V.O.3.  DOE/NETL estimates that a new SCPC unit would utilize about 4% more coal in order to meet the final 1,400 lb CO2/MWh standard (to provide the same net power output). However, since the EPA has specified that the BSER for new fossil fuel-fired steam generating units is "a highly efficient supercritical pulverized coal (SCPC) unit implementing partial CCS", a new unit meeting the final standard of performance will utilize less coal than a comparably-sized existing coal-fired plant that is less efficient.
Commenter 10693 stated their support for policies that require significant control technologies and the phasing out of conventional coal fired plants due to the health and air quality impacts associated with coal mining and use. Similarly, Commenter 8924 supported the EPA in addressing carbon pollution and requested that the final rule regulate coal fired plants to reduce emissions to the levels that they are capable of.
 The final standards of performance represent a level of emission reduction capable of being achieved using a best system of emission reduction adequately demonstrated.  That is all that the EPA is empowered to do under section 111 (b).  The standard has nothing to do with phasing out conventional coal fired plants, and, as AEP indicated in its public statements, may provide a means for new coal capacity in the future.
Commenter 6501 stated their support for the proposed CO2 limits due to the health and environmental impacts of air pollution and climate change.
 The EAP acknowledges the commenter's support.
Commenter 9516 stated that the proposed rule allows CCS sources to credit electricity from unregulated sources used to power the gasifier and compressor when determining compliance.
The EPA notes that steam generating unit means any furnace, boiler, or other device used for combusting fuel and producing steam (nuclear steam generators are not included) plus any integrated equipment that provides electricity or useful thermal output to the affected EGU(s) or auxiliary equipment.
Commenter 9682 stated that in the context of GHG regulation under the NSPS program, the energy-requirement and environmental-impact assessments prescribed by the statute are the same. The commenter noted that the whole reason for burning and thus emitting carbon dioxide is that fossil fuels are stores of energy. As a result, the commenter stated that what should be two distinct inquiries into "energy requirements" and "environmental impacts" impermissibly collapse, in the context of fossil-fuel burning, into one and the same assessment.
 The EPA has analyzed these two factors separately, and permissibly so.  Issues of water use and safety of sequestered CO2 are not the same issues as energy use due to energy required to operate CO2 control technology.  See preamble sections V.O.2. and 3.
Use of Purportedly Extra-Statutory "Purposes" to Justify Standard of Performance
Commenter 9514 stated EPA properly considered the costs of partial CCS in light of the benefits that will accrue from considering the social cost of carbon and the co-benefits from reduced emissions of other harmful pollutants, including SO2, NOx, and PM2.5.  The commenter also stated EPA also appropriately considered, in compliance with the CAA, the co-benefits of reduced emissions of SO2 and NOx that would result from the proposed rule's CO2 emission limits.   The commenter stated EPA's recognition of co-benefits is consistent with the methodology it applied in the MATS rulemaking, which also addressed the rule's positive impacts on emissions of related pollutants. According to the commenter, this methodology is also consistent with scientific studies linking policies to reduce greenhouse gases with shorter-term air quality co-benefits.
 EPA is finding that highly efficient SCPC and partial CCS is the BSER because it removes more emissions at reasonable cost (considering especially capital cost and LCOE, on a per plant basis), and does not have collateral adverse nonair health and environmental impacts, or impose undue energy burdens.  This determination does not rest on any consideration of monetized emission reductions, nor does section 111 (a) dictate any particular method (or metric) for considering costs.  The EPA has also found that if new coal capacity is added, there are net quantified benefits under a range of assumptions, in the form of both CO2 reductions and reductions in emissions of criteria pollutants controlled incidentally by the standard.  See RIA chapter 5.  This may be another reason to find the standard to be adequately demonstrated considering costs.  The EPA notes that SO2 is a criteria pollutant (and indeed, already regulated under NSPS for this industry), so no issue is raised regarding considering benefits of control of a pollutant not otherwise within the scope of section 111 standards.
Commenter 9514 stated that although EPA is not required to engage in a traditional cost-benefit analysis, the degree of the pollution reduction benefits that a proposed standard would achieve must be considered along with the costs of achieving it. The commenter referenced Sierra Club, 657 F.2d at 314, 327-28 (upholding costly SO2 standards that would provide significant pollution benefits); and Essex Chem. Corp., 486 F.2d at 437 (acid mist standards were reasoned and cost benefit analysis was not required).
EPA believes that its cost analysis, and its conclusions that the costs of the final standard are reasonable and not exorbitant, are in accord with both of these cited cases.
Commenter 9666 stated EPA does not separately measure the benefits associated with the control of CO2 emissions that would purportedly result from the proposed rule. Instead, the commenter noted, EPA estimates the combined benefits of reducing CO2, fine particulate matter, SO2, and NOx emissions. According to the commenter, if the purpose of the rule is to address CO2 emissions from EGUs, EPA cannot properly introduce its estimates of the purported benefits of controls of other emissions.
 The EPA disagrees with the commenter's statement that EPA cannot properly introduce estimates of benefits associated with reductions in emissions of pollutants other than CO2.  As a preliminary matter, the EPA notes that the determination that the costs of the rule are reasonable are based on the analysis in sections V.H. and I. of the preamble to the final rule.  However, the EPA has also found that if new coal capacity is added, there will be net quantified benefits under a range of assumptions, in the form of both CO2 reductions and reductions in emissions of criteria pollutants that will occur due to implementation of the standard.  See RIA chapter 5.  This may be another reason to find the standard to be adequately demonstrated considering costs.  The commenter's statement that a BSER determination is limited to a single pollutant and that the positive effects on emissions of another air pollutant cannot be considered when deciding what is "best" does not make sense. Suppose technology A removed 100 units of CO2 and no other pollutants (or had a negative impact on other pollutants, and technology B removed 99 units of CO2 and significant amounts of other air pollutants as well. The commenter suggests EPA would have to ignore the impact of technology B on air pollutants other than CO2 in deciding which one is the "best" system of emission reduction.  This approach would not be consistent with the requirement that EPA must consider collateral impacts in determining which technology is "best" under section 111.  See Essex Chemical Corp., 486 F. 2d at 439; Portland Cement. 486 F. 2d at 386. Moreover, the EPA notes that SO2 is a criteria pollutant (and indeed, already regulated under NSPS for this industry), so no issue is raised regarding considering benefits of control of a pollutant not otherwise within the scope of section 111 standards.
Commenter 9593 stated EPA cannot bolster its determination that partial CCS is adequately demonstrated with an extra-statutory assertion that it can choose a technology or set a related emission limitation in order to achieve "meaningful reductions." According to the commenter, the amount of reductions that may be achievable is unrelated to a determination that a technology has been adequately demonstrated. The commenter stated EPA must set an emission limit at the level that is achievable by the demonstrated technology, not a limit that would result in GHG reductions that EPA deems meaningful. Additionally, the commenter stated EPA's criterion related to attaining "meaningful" reductions also directly conflicts with EPA's analysis that the proposed GHG NSPS, if adopted, will not reduce GHGs in any event because of what EPA predicts power plant deployments are likely to be in the next several years.
The amount of emission reductions achieved is certainly a relevant factor in determining if a system of emission reduction is "best".  See. e.g., Sierra Club, 657 F. 2d at 326 ("we can think of no sensible interpretation of the statutory words `best technological system' which would not incorporate the amount of air pollution as a relevant factor to be weighed when determining the optimal standard for controlling ... emissions").   For the same reason, lowest emitting performers are best in determining the MACT floor under CAA section 112 (d) (3).  See NRDC v. EPA, 479 F. 3d 875, 880 (D.C. Cir. 2006.
Other BSER Options
Commenters (1377, 5853, 6118, 6644, 6871, 8024, 8032, 8348, 8957, 9001, 9194, 9201, 9381, 9428, 9666, 9767, 9780, 10052, 10098, 10100, 10238, 10387, 10500, 10501, 10618, 10929) stated that the EPA should consider other technologies rather than CCS as BSER.
Commenters (2470, 8348, 8501, 8923, 8949, 8971, 9034, 9194, 9197, 9201, 9381, 9407, 9472, 9472, 9593, 9595, 9596, 9665, 10017, 10048, 10098, 10100, 10466, 10500, 10680) noted that  technologies such as SCPC, USCPC and IGCC generation have been adequately demonstrated and can serve as the basis for a BSER determination. Commenter (10618) stated that ultra-supercritical technologies are beginning to emerge as a cost-effective design preference, and have good prospects for growth. Commenters (9381, 9472, 10618) provided data showing CO2 reductions from SCPC and USCPC designs compared to typical existing coal-fired EGUs.
Commenters (8348, 9197, 9665, 9666, 9772, 10388) recommended that EPA adopt a BSER determination for coal-fired boilers and IGCC units based on the emission rates achievable by IGCC, supercritical, and ultra-supercritical technologies without CCS.
Commenters (8024, 8957, 9001, 9428, 10048, 10238, 10387, 10501) suggested that EPA reconsider its proposal or withdraw and re-propose this rule to include these existing technologies.
 See preamble section V.P.1.
Commenter (10618) questioned the maturity and performance of the IGCC process, stating that while IGCC is technically feasible, it has not been adequately demonstrated. The commenter discussed the status of the Kemper and Edwardsport facilities, stating that both have experienced significant cost escalations throughout their design and construction and neither has been demonstrated to be equivalent or more efficient than other coal-based generation technologies. The commenter noted that a NETL database (cited in text) indicates at least 16 potential IGCC projects have been cancelled in the U.S. in recent years.
 The EPA is not selecting IGCC as BSER.  See preamble section V.P.1.
Commenters (6962, 9768, 9766, 10029, 10035, 10664) suggested biotech uses for captured CO2. The commenters provided information about reuse to develop biofuels and other products, and recommended that these technologies be considered as BSER for carbon storage. Commenters (9766, 10029, 10664) noted that by foreclosing the beneficial reuse of captured CO2 to produce algae-based fuel, EPA has failed to take advantage of the opportunity and has misapplied Section 111.
Commenter (10029) provided cost benefits of biotech uses for CO2 compared to costs for carbon sequestration. The commenter asked that beneficial reuse technologies are not categorically excluded technologies and may be used by affected EGUs, alone or in combination with other technologies, to meet the proposed CO2 emission limit.
The final rule provides that types of storage of captured CO2 other than sequestration at an entity reporting under the subpart RR rules may be utilized, provided that an applicant makes a case-by-case demonstration that the storage method is as effective as geologic sequestration.  See §60.5555(g) of the final rule.
Commenters (9107, 9497, 10035, 10106, 10237) discussed alternative technologies to reduce CO2 emissions from coal combustion. Commenters (9107, 9497) discussed a coal gasification processes. Commenter (10106) suggested co-firing of coal and natural gas as a form of emissions reduction. Commenter (10237) discussed concentrated solar power (CSP) as a means to achieve carbon reductions.
Commenters (10664) suggested that an affected EGU should be allowed to use more than one technology to achieve the standard
The  final standard is a performance standard which can be met by whatever means the source chooses.  EPA has specifically noted that natural gas co-firing is a potential alternative means of compliance for both PC and IGCC facilities, so that EPA agrees with the suggestion in comment 10106.
Commenters (7977, 10618, 10680) stated that a BSER determination based on highly efficient generation technologies alone would produce significant emission reductions and other advantages. Commenter (9772) stated that EPA should not take away options for improving the efficiency of replacement baseload generation plants.
Commenter (10618) discussed the emission reductions possible with an NSPS based on the best performing existing units in the EPA's CAMD database. The commenter provided a table showing potential CO2 reductions in the case of replacement of existing units with ultra-supercritical units, and discussed other environmental benefits resulting from higher efficiency technologies.
Commenter (9486) compared the energy requirements of CCS and those emitted by a well operated USCPC unit, and stated that the actual emissions of CO2 from a newer technology coal fired EGU on a unit of energy delivered to the grid basis are essentially the same as those from a unit utilizing CCS. Commenter 10680 stated the parasitic load that CCS requires will increase emissions.
Commenter (10618) stated that efficiency-based improvements would be more readily transferred to existing units than CCS technologies.
Commenter (9665) stated that these technologies, particularly IGCC units, also can be constructed to be CCS ready, which would enable them to be retrofitted with CCS equipment in the future. Commenter (9772) noted that highly efficient technologies would also lower barriers to future implementation of CCS as that technology matures.
Commenter (10618) stated that an NSPS based on higher efficiency technologies would drive future innovation, increase operating flexibility, and reduce development risks.
Commenter (10618) stated that a BSER determination based on high efficient generation technologies would enable even more advanced generation and emission control systems, including CCS, to be developed, demonstrated, and commercialized.
Commenters (8024, 9033) stated that a new generation of supercritical, ultra-supercritical and IGCC units is needed to support the deployment of second-generation CCS technologies, which DOE projects may cost roughly 50 percent less than current first generation technologies. Commenter (9033) has estimated that using best efficient technology and then upgrading the existing fleet, the industry can combine to exceed proposed targets for reduction in CO2 prior to 2020 and the next NSPS review.
Commenters (7977, 10618) stated that given the predicted high parasitic load of a CCS, higher efficiency technologies would use less coal, water, and raw materials with less resulting emissions, wastewater, and combustion byproducts.
Commenter (10030) stated that an NSPS predicated upon efficiency could be defensible as BSER based upon technology and economics.
 Use of highly efficient boilers is part of the BSER, but partial CCS is as well.  See preamble section V.P.1.  However, if a developer chose to construct highly efficient SCPC using natural gas co-firing, the standard of performance is achievable, and such a unit can be designed to be CCS ready.
Commenters (8348, 8923, 8957, 9033, 9201, 9381, 9590, 9593, 9665, 9772, 10100, 10680) noted that selecting high efficiency boiler designs as BSER would provide the advantage of significant reductions of CO2 emissions over older plant designs.
Commenter (9201) stated that because most of the current coal-fired EGU fleet is comprised of subcritical technology, a migration to new, higher efficiency SCPC technology as smaller and less efficient units are retired would produce real emissions benefits.
Commenter (9665) noted that there would be no downside to that approach, because few coal-based units will be built in the near future.
Commenters (9381, 10100) stated that for the same power output, a higher efficiency coal plant will require less CO2 to be captured; this means a smaller, less costly capture plant; lower operating costs; and less CO2 to be transported and stored.
 The final standard of performance is based on performance of a highly efficient SCPC with partial CCS.  This BSER will result in even greater emission reductions than SCPC alone, no matter how efficient.  See preamble section V.K.
Commenter (10017) stated that the reduction levels using current technology are not only adequate, but necessary in order to ensure that the EPA develops a standard that is consistent with the approach used to develop the natural gas NSPS. The commenter noted that the emissions of new SCPC and IGCC units when compared to the average emissions from coal-fired power plants represent a reduction of 25 and 36 percent respectively. The commenter stated that these reductions are more than twice the reductions proposed for natural gas plants.
 There are persuasive reasons not to base BSER for NGCC plants on performance of CCS.  See preamble section IX.C.
Commenters (10098, 10618) stated that dismissal of other technologies is inappropriate.
Commenter (10098) stated that basing the NSPS on energy efficiency technologies would spur innovations that would allow power plant operators and contractors to meet GHG emission limits in the most cost-effective manner. The commenter stated that the EPA failed to explore this possibility in the proposed rule, making its rejection of this option arbitrary and capricious.
Commenter (10618) stated that EPA's lack of evaluation of highly efficient generating technologies is inconsistent with Section 111(b)(3), which requires EPA to issue and take into account information on technologies that could be applied to the specific source category for which an NSPS is being developed.
Commenter (10017) stated that the NSPS is a technology-based standard, not an air quality standard driven program. The commenter stated that the EPA should not use the NSPS in an attempt to reach some predetermined reduction standard or issue standards that support only certain industries or technologies. The commenter recommended that the EPA should recognize existing operating technology to set the NSPS standard.
 The EPA agrees that section 111 (b) is a technology-based standard.  Nonetheless, in determining what system of emission reduction is "best", it is at the least reasonable to consider the extent of air pollution reduction.  Partial CCS is a demonstrated technology available for deployment now at reasonable cost without collateral adverse impacts on other environmental media or on energy requirements.  It achieves significantly more emission reductions than SCPC alone.  See preamble section V.K.  Partial CCS is therefore part of a best system.  Commenter 10618's reference to CAA section 111 (b)(3) is obscure.  That provision requires EPA, from time to time, "issue information on pollution control technologies for categories of new sources and air pollutants subject to the provisions of this section".  This provision is unrelated to the process of setting a standard of performance, and in any case, the EPA has shown that partial CCS is a pollution control technology amendable for use (and actually being used) by fossil fuel fired steam electric generating units.
Commenters (10085, 10618) suggested that the EPA revisit the application of BSER and review information available through BACT determinations, EPA reports, demonstrated performance of international efforts, and the CAMD database.
Commenter (10618) discussed their review of CAMD data for coal-based EGUs, and the comparison of CO2 emissions between units grouped by decade and the AEP Turk Plant.
Commenter (10618) provided a table summarizing international efforts evaluating highly efficient generating technologies.
Commenter (10618) provided a list of three EPA reports that evaluate highly efficient generating technologies.
Commenters (9201, 10098, 10618) discuss EPA reports and guidance that found these technologies to be effective methods of reducing GHG emissions. Commenters (9201, 10618) stated that consideration of these reports and other related information would clearly indicate that highly efficient generation technologies are the BSER upon which a balanced NSPS could be based.
Commenter (9201) provided information about emission rates for facilities using SCPC units from the EPA CAMD database.
 See preamble section V.P. 1 and earlier comment responses in this unit.  Please note in particular the analysis in section V.P.1 showing that new coal capacity would already reflect supercritical technology, so that a standard based on performance of that level of control would simply ratify a status quo, not result in emission reductions over baseline emission levels.
Commenters (10098, 10618) disagreed with the EPA's rationale to not promote highly efficient technologies because a standard using highly efficient technologies could impede the advancement of CCS technology. The commenters stated that basing the NSPS on energy efficiency technologies would spur innovations that would allow power plant operators and contractors to meet GHG emission limits in the most cost-effective manner. Commenter (10618) stated that further development of highly efficient technologies could actually benefit the development of CCS. Commenter (10618) asked if the EPA proposing an NSPS based on the use of the BSER, or is EPA proposing a CCS development rule.
 The final standard of performance is based on the section 111 (a) statutory criteria: a best system of emission reduction adequately demonstrated, and the level of performance achievable through use of that system of performance.
Commenters (8032, 9201, 9590, 10092, 10097, 10098, 10395, 10618) stated that the EPA has ignored information about highly efficient generation technologies.
Commenter (10618) stated that the EPA has not provided a serious, objective evaluation of the technology. The commenter stated that the EPA has not defined or identified highly efficient generation technologies, identified or assessed key variables that impact efficiency, assessed overall environmental benefits, or quantified the magnitude of emission reductions with the use of energy efficiency technologies, thus providing no basis for the Agency to compare these technologies with CCS.
Commenter (10618) noted that the EPA referenced nine international projects and databases listing dozens of other international efforts related to various aspects of CCS development, but in the evaluation of highly efficient generating technologies as the BSER, EPA referenced zero projects.
Commenter (10098) stated that by failing to explore the use of energy efficiency technologies, EPA's rejection of this option is arbitrary and capricious.
 See preamble section V.P.1 and note that highly efficient supercritical PCs represent a baseline of performance for a new source here.
Commenters (9201, 10680) stated that the EPA dismisses emissions reductions from SCPC and IGCC as providing "little meaningful CO2 emissions reductions." Commenter (9201) noted that the 40 percent reduction required from new coal plants in contrast to the proposed standard for new natural gas-fired plants that are 25 percent higher than the performance of the ten best operating units. Commenter (10680) stated that the EPA's different approaches in setting the coal and natural gas standards cannot be reconciled and, as a result, are unreasoned and arbitrary.
 See preamble section IX.C.4.
Commenter (9665) noted that EPA would be better served to adopt a non-CCS BSER standard for new fossil fuel-fired utility boilers and Integrated Gasification Combined Cycle (IGCC) units. The commenter expressed concern that the partial CCS standard is legally vulnerable and could jeopardize the validity of the entire NSPS rule.
Commenter (10085) stated that to avoid legal scrutiny, the EPA should look at coal-fired EGUs that have been constructed within the past ten years and look at what control technologies were determined to be best available control technologies (BACT) at the time of construction.
 The EPA believes it has made reasoned findings that partial CCS is part of the best system of emission reductions for this source category.
Commenter (9665) recommended an emission limit of 1,700 lb. CO2/MWh on a gross output basis for these high efficiency units.
Commenter (9472) discussed the results of an attached report that analyzed CO2 emissions data for all coal-fueled units that have commenced operation since 2007. The commenter stated that the data was analyzed using EPA methodology to determine emissions rates that would be achievable over a ten-year period. The commenter stated that in the report, the following emissions rates are achievable for new coal-fueled power plants without CCS:
-1,915 lbs CO2/MWh for supercritical boilers burning bituminous and subbituminous coals;
-2,080 lbs CO2/MWh for subcritical boilers burning bituminous and subbituminous coals; and
-2,150 lbs CO2/MWh for all boilers burning lignite coals.
The commenter recommended that the EPA should adopt the emissions limits for the particular subcategories set forth above.
Commenter (9201) stated that emissions rates for conventional non-CCS coal units are still too low given operational realities, and should be set at a minimum between 1,800 and 2,000 lbs. CO2/MWh.
Commenter (10664) suggested that the proposed rulemaking be revised to be outcome based. The commenter recommended that the EPA set the standard, provide a mechanism to demonstrate that the standard has been met, and allow reuse technologies to be an option for affected EGUs, alone or in combination with other technologies to achieve the proposed CO2 emission limit.
Commenter (9194) stated that the CO2 emission rate achievable by a new SCPC unit should be adopted for the GHG NSPS for coal-fired EGUs.
Commenters (8024, 9201) suggested that the EPA propose an alternative NSPS limiting CO2 emissions to the emissions rate achieved by new supercritical, ultra-supercritical and IGCC coal technologies, which would be consistent with current EPA GHG BACT Guidance.
Commenter (10951) stated that EPA should be incenting the construction of a new generation of highly efficient super-critical and ultra-supercritical coal plants.
 See preamble section V.P.1.
Commenter (9593, 9780) stated that the EPA can best move forward with the proposed NSPS by adopting the emissions standards achievable by supercritical coal-fired boilers, which achieves significant reductions when compared to the subcritical boiler technology in the existing coal-fired fleet, and evaluating in the future whether CCS has become adequately demonstrated.
Commenter (9033, 9320, 9426) recommended EPA set CCS aside until the eight year review of the NSPS to avoid conflict between EPA and DOE timelines for the commercialization of CCS technologies.
Commenter (8348) stated that as CCS technology develops, the EPA can then give consideration to a more aggressive CCUS performance standard that could be applied to each EGU classification at a level of performance proven achievable for each particular classification, whether coal or natural gas-fired.
Commenter (8957) stated that if and when CCS becomes commercially viable, it may be more efficient to set appropriate NSPS across all source categories, including NGCC. The commenter stated that until CCS is commercially available, EPA should not pursue it for this rulemaking.
Commenter (3176) recommended further research and development for CCS without requiring CCS now.
 See preamble section V.P.1.
6.3.7 EIA Analysis
Commenter 8925 noted that based on EPA's reliance in the EIA upon the EIA Annual Energy Outlook 2013, no new conventional coal facilities are projected beyond what is currently under development through 2020 and because coal + CCS is more expensive than conventional coal and provides no additional economic value under current and proposed federal regulations, this implies no new coal with CCS would be built through 2040, in the absence of additional incentives (e.g., financial subsidies or emission limits). The commenter argued that no deployment of electric generating units with CCS for at least 8 and perhaps up to 26 or more years suggests little financial incentive for commercial research or vendor activity, and that combined with uncertain funding for government-funded research on CCS, this commercial slowdown suggests slowing progress on CCS.
This comment reflects analysis in RIA chapter 4, and is thus consistent with EPA's analysis that no new non-compliant coal would be built due to economic reasons.  However, commenters (including commenters to the 2012 proposal) indicated there are other reasons for adding capacity, including preserving fuel diversity, and as a hedge against rising natural gas prices.  The final standard of performance is structured to assure that coal remains cost competitive with other low-carbon baseload dispatchable non-NGCC technologies.  The on-going research into CCS, active vendor efforts in the field, and prior regulatory history indicate that a standard of performance can be a spur to development and deployment of the new pollution control technology which forms the basis of a standard of performance.  See preamble sections V.F, V.I.4, and V.L.
Commenter 9201 stated EPA's assessment on the impact of its proposal relies upon flawed modeling and assumptions that produce a static default assumption that no new coal-based power would be built even in the absence of this proposal. The commenter referenced that analysis used in the MATS rule and noted that only 50 MW of coal capacity had been retired as of February 2014 as compared to the higher EPA estimates. Citing multiple studies of natural gas demand, the commenter stated that EPA policies that force the retirement of coal base load power plants, such as EPA's proposed NSPS, pose a permanent structural barrier to assuring the electric grid remains diverse enough to minimize both reliability crisis and higher and more volatile prices that reverberate throughout the economy writ large.
 The commenter is incorrect in stating that the standards set by this rule "force the retirement" of coal power plants or any generating capacity. The standards for new sources under 111(b) only impact newly constructed generating capacity and have no bearing on existing generating capacity.
6.3.8 Effect of the Proposed NSPS Rule on CCS Development, Demonstration and Deployment
Commenter 9033 asserted that requiring CCS for coal has the potential to distort the market because the extreme capital cost of the CCS equipment and additional operating cost, as documented by the NETL studies, making NGCC more competitive than coal with CCS.
 NGCC is already significantly more competitive than coal.  See RIA chapter 4.    Preamble section V.I.4 addresses the issue of whether the incremental cost of partial CCS could make new coal uncompetitive with NGCC, considering current and forseeable market conditions.
Commenters 9592, 9683 and 10095 stated that imposing a mandate before CCS is ready will result in project developers choosing a technology that is proven and has lower cost, which reduces the potential market for CCS technology developers and may result in an abandonment of the CCS technology.  Commenter 9592 also provided a reference that IEA's 2012 Technology Roadmap for High-Efficiency Low Emission Coal-Fired Generation stated that wide international deployment of ultra-supercritical and advanced ultra-supercritical units must precede the widespread deployment of CCS technology.
Commenters 8032, 9196, 9426 suggested that the proposed rule will actually slow the development of CCS and other clean coal technologies.  The commenter insisted that creating a mandate will have the effect of forcing out investment and research into developing technologies and practices because they are not contemplated by the EPA rule.
Commenters 9505, 10031, 10088 suggested that instead of encouraging development, the requirement for the deployment of partial CCS will foreclose further demonstration projects of this technology at commercial power plants.  The commenter further noted that significant penalties for noncompliance discourages [practically prohibits] any future investment in such units.  At a minimum, the commenter believes the mandate will significantly delay deployment of a cost effective and commercially available CCS technology.
Commenter 10046 stated that the availability, or lack thereof, of alternatives to building coal units with CCS systems is a key consideration in determining whether a mandate will force, and thereby promote, the technology's development, or consign it to the dust bin.  The commenter further suggested that since EPA proposes to require that new coal plants add a technology that is decidedly immature, the inevitable response will be to build new gas units exclusively.
Commenters 1959, 9407, 9471, 9194, 9596, 10500, 10952 stated that mandating CCS for new coal-fired power plants before the technology is commercially viable and adequately demonstrated could ultimately impede, rather than accelerate, its development.
Commenter 10500 stated that hindering development of CCS at home will increase worldwide emissions of CO2.
 These comments are at odds with historic developments of a regulatory requirement spurring massive technological innovation and development.  See preamble section V.L.  The EPA notes that CCS technology is further developed than FGD scrubber technology was in 1971 when EPA based a standard of performance on that technology as BSER, and for this reason (among others) regards comments such as those of commenter 1959 as misplaced.
Commenters 9326, 9472 and 10095 listed several reasons why EPA should not base the standard for coal on CCS technology, including that the proposed NSPS will effectively ban new coal-fueled power plants and therefore a more efficient second generation CCS will likely never be demonstrated in the U.S. Commenter 9472 stated that overcoming challenges such as available space for CCS, proximity to pipeline infrastructure, suitable storage or EOR availability has limited and will likely continue to limit the opportunity to demonstrate second generation CCS on existing coal plants. Therefore, the commenter asserted that EPA is mistaken in stating that the standard serves as an incentive for future CCS technology development. Commenter 9326 also stated that the proposed rule eliminates the potential for modernizing the coal-fired power fleet with modern high-efficiency super- and ultra-critical pulverized coal boilers.
Commenters 8024, 10046 stated that this regulation will essentially stop the development of CCS. The commenter noted that without new coal plants, it is unlikely technology developers will continue to invest in CCS development.  Commenters 8024, 10036 noted that since the proposed regulation provides a significantly lower cost alternative (NGCC without controls) to the application of CCS to coal, there is unlikely to be a market for at least 10 years, and most R&D cannot be sustained for that long. Commenter 10046 stated that the EPA should withdraw its proposal.
 See preamble section V.I.4.  Issues of siting availability are addressed in preamble section V.M. and the Geographic Availability TSD.
Commenters 8501, 9201, 9422, 9734, 10036, 10243 asserted that EPA is providing a disincentive and likely freezing any new investments in the development and deployment of CCS by offering the choice between CCS-controlled coal units and uncontrolled NGCC units. .
Commenter 10243 stated that without a strong financial mechanism to support CCS, the proposed standard does not allow for R&D time that will provide confidence to investors.
Commenters 9201, 9426 stated utilities are effectively barred from developing CCS projects by the combination of EPA's regulatory requirements, their need to respond to the fundamental economics and concerns of providing affordable power, the continued availability of the option to build NGCC units without any carbon constraints, and because utilities do not value fuel diversity simply for the sake of being diverse.  As a result, the commenter asserted that coal generation is not incentivized to achieve higher efficiency potential such as ultra-supercritical coal, and the deployment of CCS will vanish along with America's ability to be a leader in CCS development in the future.
Commenter 9033 noted that in today's market of moderate natural gas prices, it is very unlikely that any commission will allow the recovery of development costs on existing plants based on a new plant rule that allows uncontrolled natural gas alternatives that are obviously less expensive.
Commenters 9326, 10036, 10046, 10880 stated that the regulations do not reflect the current status of the proven economic viability of CCs technologies for deployment across the broad range of coal generating equipment.  The commenters noted that this creates a situation where it is highly unlikely that power producers will be able to justify the financial risks associated with building a high-efficiency power project without the assurance that the technology can meet the new standards.
Commenter 10046 stated that a CCS-based emission rate standard such as the one proposed by EPA will in fact lead to a delay in CCS investment, and consequently, will not promote the development of CCS, but retards it. The commenter further noted that since much of the US power industry operates in deregulated markets, the financial risk concerns identified with CCS will hinder development of the technology in these markets.
Commenter 10046 stated that a CCS mandate moves the CCS technology risk to cover the entire EGU, because the plant cannot be operated except in compliance with the CCS mandate.
Commenter 10036 noted that in light of existing, alternative, lower cost fuel options, lack of adequate government cost-share funding support to accelerated development and lower costs of CCS technology simply extends the time when technology commercialization is probable. The commenter stated that the proposed rule limits investment choices because the timeline for potential return on investments is unknown or significantly extended.
Commenter 8501 stated that the proposed rule will likely defer investment in energy efficient coal based generation.
The final rule does not change the fundamentals of wholesale electricity markets. An independent power producer (IPP) developing an electric generation unit in a competitive wholesale electricity market bears the risk when considering whether to develop that resource. The IPP makes a decision to develop the generation based on its assessment of risk and its ability to recover costs through a bilateral contract or the spot market. A vertically integrated utility, whether operating in an RTOISO or more traditional market structures outside an RTO/ISO, would be subject to cost-of-service regulation by a state PUC or other jurisdictional regulator in order to obtain cost recovery. RTOs and ISOs have mechanisms in place to ensure adequate resources to meet demand and reliably operate the grid (e.g., capacity and energy market rules that ensure generators have the opportunity to recover their costs, including fixed costs).  Moreover, as shown in RIA chapter 4 and discussed in preamble section V.H.3, new non-compliant coal capacity is unlikely to be constructed in the foreseeable future for reasons unrelated to the present standard.  Commenters 9201 et al. indicate, for example, that even ultrasupercritical capacity is not currently financially viable.
Similarly, Commenter 8925 asserted their concern about the proposed rule's precedent, which could discourage companies from participating in future technology demonstration efforts by using only two partially constructed, government supported technology demonstration projects as a key part of its basis for establishing emission limits.
Commenter 8348 stated that as written, the proposed rule will immediately eliminate coal as an option for new power plants with a resulting loss of interest by the industry in continued CCUS research and development.  The commenter goes on to stress the importance of investing in next generation carbon capture technology R&D.
Commenters 9426, 10046, 10395 stated that the proposed rule discourages the private sector's willingness to invest in CCS technology development, and without that investment, the technology may never be commercialized.
Commenters 9407, 10952 disagree with the EPA that that "the industry needs a stick" to demonstrate CCS to the point of availability and cost reasonableness. The commenters stated that the projects EPA cites in the proposal in attempt to justify CCS as BSER all originated without the "stick" that EPA now believes is necessary.
The AEP experience at the Mountaineer project suggests otherwise, when the company cited absence of a clear legal mandate for CO2 reduction as a chief reason for abandoning the project.
Commenter 9780 stated that only coal-based units with CCS that receive government funding will be built in the future since the costs of CCS will prevent new coal-based units. Additionally, the commenter stated that current CCS projects will help DOE and private industry study how to trim retail costs and reduce costs for second-generation carbon capture technology, suggesting that the technology is not adequately demonstrated.
Commenters 10086, 10870 stated that the EPA is not expecting new coal plants to be built until 2022. The commenters stated that with no new plants being built, there will be no demand, or research and development, for CCS technology. The commenter stated that the capital cost cannot come down if there is no wide spread deployment of the technology.
Research into CCS is dynamic and on-going and the EPA does not expect it to cease.  See preamble section V.H.8.b.
Commenter 10952 (NRECA pp. 5-6) maintains that a CCS mandate ultimately would perversely influence worldwide GHG emissions because of a chilling effect bringing about true CCS demonstration and commercialization.  The commenter posits a case whereby China will add large volumes of new coal capacity, no U.S. domestic coal capacity is added, net CO2 increases from Chinese coal combustion swamp U.S. reductions attributable to the difference between coal and gas-fired EGU emission rates, the result being "a missed opportunity to foster worldwide CCS application, minimal and inconsequential reductions in U.S. CO2 emissions, and an increase in worldwide CO3 emissions that without this proposal we could have been on tract (sic) to curb significantly going forward."
As it happens, the United States and China have signed a bilateral agreement whereby China has committed to significant reductions in CO2 emissions over the next decades.  To the extent potential international response to domestic actions is a relevant consideration under section 111 (a), this development is at direct odds with the commenter's hypothetical.
Commenter 7502 stated that it is evident that the proposed regulations would spur further innovation and investment in such technology [low carbon technologies] in the near future.
Commenter 9035 stated that the combination of a regulatory driver and financial support is needed to spur investment in CCS projects. The commenter suggested potential funding mechanisms.
Commenter 9035 stated that Public Service Commissions have been reluctant to approve CCS construction, but should be more willing to approve ratepayer cost recovery for CCS projects if there is regulatory certainty.
Commenters 9035, 10103 stated that in order to support a diverse set of affordable low-emitting sources of electricity, further research, development and demonstration of CCS is needed. Commenter 9035 stated that the proposed rule should be assessed on its effectiveness in supporting, and not inhibiting, the deployment of carbon capture, CO2-EOR, and other carbon-cutting technologies. Commenter 10103 asked that the EPA ensure the CCS technology is appropriately proven and available for use.
 The EPA largely agrees with these comments, which provide support for the proposition that a regulatory standard promotes development of the new technology on which it is based.
Proposed Emission Limit of 1,100 lb CO2/MWh
Several commenters (0784; 1902, 2471, 3236; 8957, 9033, 9192, 9472, 9497, 9602, 9678, 9725, 10050, 10085, 10097, 10104,10395, 10504, 10552, 10680; 10974; 11062; 10975; 11063; 10963) stated that the proposed limit of 1,100 lb CO2/MWh for coal based EGU is not achievable.
One commenter (9033) stated that based on heat rates projected for IGCC and USC on lower rank coals, the 1800 lb/MWh standard is unachievable. The commenter provided a table of expected CO2 emissions for selected US fuels for a modern PC power plant operating at full load conditions that shows that the 1800 lb/MWh limit may be achievable at full load conditions for bituminous coals, barely achievable for subbituminous coals, and unattainable for lignites. According to the commenter, the unavailability of CCS means no new units could even be considered. Two commenters (9497-5231; 10104-4644) stated that CCS has not yet been commercially proven and that setting the standard at the current proposed level of 1,100 lbs/MWH will effectively ensure that no new coal-fired plants are built, including promising high-efficiency technologies that would in themselves reduce CO2 output, such as ultra-supercritical power plants.
The commenter (9033) stated that EPA set the standard for theoretical best performing units in only two classes and fails to account for the change in heat rates of units that will occur and cause them to exceed the limit. According to the commenter, all combustion equipment incurs an increase in heat rate with time and operation and it is conceivable that units meeting the requirements when new will fail the standard over time. Commenters (9033, 9472) cite the following factors as impacting plant heat rate, and thus CO2 emissions, making the proposed EPA limit difficult to achieve:
Partial Load Operation. Net plant heat rate increases as the plant operating load is reduced, with a corresponding increase in the specific CO 2 emissions.
Base load Operation. All power plants have load variation that impact a plant's heat rate and CO2 emissions.
Cycling Operation. A typical PC cycling plant may operate 30% of the time at 100% load, 55% of the time between 50-75% load, with the balance at lower loads. The average capacity would be about 70% and the plant would have an average heat rate about 4-5% higher than at 100% load.
Degradation Due To Plant Age. Normal wear and tear is to be expected which has an impact on the plant heat rate.
Site Factors. Other factors can have a negative impact on plant heat rate and CO2 emissions. For example, areas with limited water resources could require an air-cooled condenser vs. water cooling. Local water temperature can also have an impact on condenser operating pressure and heat rate.
The commenter (9033) provided a table summarizes the impact of an increase in plant heat rate due to the above factors on the specific CO2 emissions for a state-of-the-art USC PC power plant. A plant that is required to cycle would likely have a heat rate 5% higher than its design 100% load heat rate. It is likely that the bituminous plant would also exceed the limit when site specific factors, impacts of startup, shutdown, and age deterioration are also factored in. The cycling impact could be more significant in the future as renewables assume a larger portion of total power generation. One commenter (10100-1182) stated that the use of cycling units is increasing and do not have the efficiency of baseload units.
According to the commenters (9033, 10085), the Clean Air Markets Database used by EPA to support the proposed 1800 lb CO2/MWh limit shows that while there were a limited number of plants that met this target, the bulk of the reporting plants exceeded it by a wide margin.
The commenter (9033) compares the 4 SCPC plants that the EPA cited in justifying the proposed 1800 lb CO2/MWh target. What stood out was the high capacity factor for these four plants. The commenter stated that they were clearly operating as base load plants, with capacity factors in the mid 80% for three of them and that none of them would have met the proposed target if they operated as typical cycling units.
The commenter (9033) notes that EPA states that marginal units can achieve the standard by applying improvements, such as double reheat, coal drying (for lignites), and cofiring with natural gas. These modifications all add additional equipment at the expense of increased capital/operating cost and potentially decreased availability and makes coal-fired technology less competitive.
Because permits are customarily permanent, the commenter (9033) stated that setting an output standard based on "as new" performance values for equipment that is known to lose efficiency over time will ensure that eventually no plant will meet its permit limits.
 One commenter (9472) stated that EPA should not base a standard for coal on CCS technology and should withdraw the proposed NSPS. The commenter provided information showing the projected CO2 emission rate that would result in one exceedance in 10 and 20 years for each boiler category (lignite, subcritical and supercritical). The commenter recommended the following emissions rates: -1,915 lbs CO2/MWh for supercritical boilers burning bituminous and subbituminous coals; -2,080 lbs CO2/MWh for subcritical boilers burning bituminous and subbituminous coals; and -2,150 lbs CO2/MWh for all boilers burning lignite coals. The commenter (9472) provided the following data:
-emissions data for subcritical and supercritical units firing PRB and eastern bituminous coal and at levels greater than 1,800 lbs/MWh.
-the relationship between annual CO2 emitted and average heat throughput with the lowest emissions achieved at the highest heat throughput. The data for one unit show CO2 emissions increasing almost continuously as heat throughput decreases, with recent data exceeding 1,800 lbs/MWh for the least heat throughput.
-full, high and low loads showing that for most units CO2 emission rates increase when operating at less than maximum load and that CO2 emissions can increase by 100 lbs/MWh and in some instances by as much as 200 lbs/MWh.
-the cumulative distribution of CO2 data at or below a given CO2 rate for three categories of EGU units: subcritical, supercritical and lignite-fired boilers, comparing fuel type (i.e. bituminous coal or subbituminous coal).
Several commenters (6870; 9190; 9192; 9497; 9590;  9725; 6649; 10097; 10104; 10395; 10501; 10552;  10680) stated that EPA has proposed for new coal EGU' s a standard (1,100 lb CO2/MWh) that no existing coal base load EGU can achieve-not even the newest demonstrated coal technologies such as supercritical pulverized coal (SCPC) and integrated gasification combined cycle (IGCC). The proposed emission standard is at least 40 percent lower than the performance level that is achievable by these demonstrated coal technologies. One commenter (9678-765) stated that EPA cannot promulgate a standard lower than 1,200 lb CO2/MWh if that standard cannot be achieved by adequately demonstrated technology. Commenter (10504-3606) stated that new IGCC generation has an estimated emission rate of 1,700 lbs CO2/MWh, which far exceeds the proposed standard of 1,100 lbs CO2/MWh for coal-fired units.
Several commenters (1902; 8349; 9602; 9774; 10043; 10083; 10555; 10665) stated that the new coal limits cannot be met with the latest generation technology including those new coal technologies in Europe. The commenter has provided EPA the last 7 years of new plant information that demonstrates that none of these coal-fired plants come close to meeting the 1,100 lb/MWh limit. EPA should withdraw and re-propose the NSPS rule and set the standard based upon a new coal plant of 1950 lb/MWh, which is achievable. A limit of 1,950 lbs. CO2/MWh would make the rule consistent with demonstrated supercritical and ultra-supercritical technology. No new coal plant could achieve a limit of 1,100 lbs CO2/MWh without the use of CCS and no full scale, commercial coal-fired power plants operate in the U.S. with this technology.
Several commenters (2471; 8974; 10024; 10393) suggested a 1950 lb/MWh emission standard. One commenter (2471-4198) stated that this would still be technology-forcing. EPA should consider allowing an EGU to meet part of the limit through financial carbon-reduction mechanisms or instruments, such as through the purchase of Renewable Energy Credits.
One commenter (7977) stated that EPA consider 1,700 lbs CO2/MWh as the limit for coal-fired boilers. This emission limit would accomplish nearly 20 percent CO2 emission reductions compared to the national average of 2,100 lbs CO2/MWh for the current U.S. coal-fired fleet. This standard is being achieved by only the cleanest and most recently commissioned coal-fired units in the nation, setting an aggressive target for new generation and requiring technology advancement through the New Source Review program.
One commenter (9678) stated that EPA has not defined why reductions on the level of those that could be achieved by IGCC, supercritical, or ultra-supercritical units are not significant. EPA does not explain why a reduction of 700 lb CO2/MWh is significant, while a reduction of 400 to 500 lb CO2/MWh is not. Nor does EPA explain how this determination relates to the analysis contained in the RIA for the proposed rule (e.g., that, overall, the proposed standards will result in negligible reductions in CO2 emissions). Thus, EPA's decision to consider only technologies that can achieve an emissions standard of 1,200 lb CO2/MWh on a gross output basis does not appear legally defensible. One commenter (9592-732) stated that EPA should have compared SCPC emissions to the typical CO2 emissions rate of existing coal-fired generating units. The CO2 emission rates of a new SCPC unit are significantly lower than the typical existing coal-fired EGU and would meet EPA's desire for significant CO2 emission reductions as shown by the table below.
One commenter (10017; 10050) stated that EPA uses two distinct approaches for developing standards for fossil fueled EGUs. The standard for NGCC technology is based upon actual emission data while the standard for coal base load technology is based upon calculations for hypothetical coal units using unproven CCS technologies. Consistent methods should be used for determining the proposed standards. One commenter (10050) stated that EPA rejects basing a coal base load plant standard on SCPC and IGCC as not providing as much emission reductions as practicable. The reductions achieved are real, substantial and as much as practicable with adequately demonstrated technology. For NGCC technology, EPA does not attempt to seek as much reduction as practicable and instead allows emission levels 20 percent higher than the levels achieved by the best performing units. EPA's different approaches in setting the coal and natural gas standards cannot be reconciled and, as a result, are unreasoned and arbitrary.
One commenter (8937) stated that the proposal fails to establish a workable pathway for coal. Rather than restrict construction of coal fired EGUs to those that are fortunate enough to receive sufficient government assistance, EPA should set a standard that allows efficient coal based EGUs to be built while the CCS technology is being fully developed into a stand-alone economically viable technology. As EPA has indicated on its' Clean Energy Site, the average CO2 emission rate for coal fired EGUs in the U.S. is 2,249 lbs CO2/MWh. That figure should be the starting point for establishing an interim target for new coal fired units while CCS is being fully developed and deployed.
Two commenter (9736; 10876) stated that the proposed rules, when examined based on high heating value (HHV) heat rates - appear to favor one CT design over another, which seem to preclude at least the frame-design option from consideration for future capacity additions. This "disfavoring" of frame-design units is short-sighted as the optimum design for most NGCC units is based on use of both a frame-design CT and a heat recovery steam generating (HRSG) unit. As EPA is apparently favoring NGCCs for new generation, this presents a dilemma for smaller entities that need additional generation: a near-term solution to power supply needs - absent the aforementioned "disfavoring" - could be to install a frame-design CT, with the goal of "stepping up" that unit to an NGCC unit at a later date by adding a HRSG unit. In this fashion, the initial costs of installing new capacity would be lower, and power supply capacity could grow as the community's needs grew. A higher standard be established that would not preclude frame-design units.
One commenter (0784) stated that EPA inadequately considered the total amount of carbon currently being released into the atmosphere with the closing of older coal-fired electric generation units and the retrofitting of others.
One commenter (9497) stated they have lignite reserves that may be amenable to UCG with CCS and reinjection back into the coal seam or use in EOR. EPA's proposed rule would inhibit further research and development of this potential energy source by setting an initially insurmountable hurdle in the 1,100 lb/MWh CO2 emission standard. This is a clear example of the potential innovation-stifling impact of the proposed rule. UCG may represent a valuable technological path, but with a stringent CO2 limit in place, there may be no viable way to start on the path without violating the standard. The commenter requests that EPA modify its proposed rule to allow for RD&D and scale implementation of alternative coal based technologies, including UCG. One commenter (9723-6902) stated that a limit of not less than 2,200 lb/MWh should be considered by the EPA for lignite coal-fired EGUs.
One commenter (0784) encouraged EPA to phase in carbon emission standards for new coal-fired generation units based on the best available proven technologies and suggested that 1,800 lbs/MWh is an appropriate initial point.

 One commenter (10618) stated that the rates being considered by EPA (1,000 to 1,200 lb/MWh) have not been proven to be technically feasible and have certainly not been adequately demonstrated for coal-based electric generation technologies. The commenter recently completed construction of an ultra-supercritical unit, which is employing state-of-the-art advanced coal technology. Based on the subbituminous fuel used, the projections for load fluctuation and periodic unit startups, operations to date, and available information regarding equipment degradation over a units operational life, the commenter estimates that an annual gross CO2 emission rate of 1,900 lb/MWh would incent the development of more highly efficient generation technologies, while properly balancing the other factors (including costs) associated with the determination of the BSER.
Commenters (9665; 10098) supports EPA's proposed compliance option under which utility boilers and IGCC units could average emissions on an 84-month rolling average basis. Any source choosing the 84-month alternative standard would be continuously mindful of the source's obligation to meet the standard over the long term. It would be highly unlikely that a source would intentionally operate a unit at less than the optimal level it could practically achieve since any "excess" emissions would need to be made up in later years of operation. A source that operated above the standard would be required to underrun the standard by at least the same amount over the same period of time that it operated above the standard. Therefore, EPA should not establish an 84-month alternative standard at a level lower than 1,100 lb. CO2/MWh. It is also unnecessary for EPA to establish an upper limit on CO2 emissions under the alternative standard, or to require compliance with the 12-month standard. Again, a source is ultimately penalized under the 84-month alternative standard if a unit exceeds the required standard by needing to offset the excess emissions with emission levels commensurately lower than the standard. This provides sufficient incentive for regulated sources to not exceed standards indiscriminately, but only where justified.
One commenter (8024) stated there is no rational basis in climate change policy for exempting CO2 emissions from natural gas generation while penalizing coal-based generation with uneconomic NSPS. Comprehensive global climate modeling analyses show that methane leakage from natural gas exploration, production, transport, and generation processes can offset all or more of the CO2 differential between coal and gas generation. The proposed rule is fundamentally unsound for this reason.
The premise of most of these comments is that SCPC or IGCC boilers, operating alone, cannot achieve the proposed standard of performance, and because CCS is not feasible, this means these units cannot achieve the standard.  CCS is in fact demonstrated and feasible, and the final standard of performance can also be achieved by alternative means not involving CCS.
This final standard of performance for newly constructed fossil fuel-fired steam generating units provides a clear and achievable path forward for the construction of such sources while addressing GHG emissions and supporting technological innovation. The standard of 1,400 lb CO2/MWh-g is achievable by fossil fuel-fired steam generating units for all fuel types, under a wide range of conditions, and throughout the United States.
Two commenters (1624; 9423) favor an efficiency based standard. One commenter (9423) stated that EPA did not appropriately consider an efficiency-based standard for PC and circulating fluidized bed (CFB) units but the standard for NGCC turbines is precisely a standard based solely upon efficiency. The heat recovery portion of a NGCC unit does not reduce emissions, but instead improves efficiency in producing electricity (or steam) by extracting heat from the exhaust gas. EPA has relied upon defining an efficiency level for NGCC units as BSER, yet rejects defining a standard based upon efficiency measures for coal- fired EGUs. The commenter also stated that EPA is applying an emission standard based on combined cycle turbines to a completely different source type of EGU. IGCC units, the basis for the 1100 lbCO2/MWh limit, should be either listed as a separate source category or the BSER standard for IGCC should be listed in Subpart KKKK, because the source of emissions is from the combined cycled turbine and not the gasifier. Combined cycle turbines generally produce more electrical output per the same amount of fuel burned in an EGU that utilizes a simple steam cycle to produce electricity, because the combined cycle uses the steam cycle and a mechanical cycle to produce electricity. The claim that NGCC is inherently lower-emitting is completely a function of the basis of the standard that EPA chose, which is an output based standard of lb C02/MWh. EPA is stacking both CCS and an "inherently lower emitting unit," a combined cycle turbine, to establish an output based emission standard that EPA is erroneously applying to a completely different source type of EGU (subcritical, supercritical pulverized coal boilers, and circulating fluidized bed units).
One commenter (9426) stated that the EPA has proposed to apply to pulverized coal ("PC") units the 1,100 pounds of CO2 per megawatt hour ("lb CO2/MWh") standard, which is based on technology applicable only to IGCC units. Any standard that applies to PC units based on a finding that it is achievable with a technology that only IGCC units can use is also contrary to law.
Commenter 9426 states that the standard of performance can only be met using a technology suitable only for IGCC.  The commenter is incorrect.  Both pre- and post-combustion CCS are demonstrated technologies.     This final standard of performance for newly constructed fossil fuel-fired steam generating units provides a clear and achievable path forward for the construction of such sources while addressing GHG emissions and supporting technological innovation. The standard of 1,400 lb CO2/MWh-g is achievable by fossil fuel-fired steam generating units for all fuel types, under a wide range of conditions, and throughout the United States. Comments regarding there being "no requirement for emission reduction" have been addressed elsewhere.
One commenter (10100) stated that, assuming that EPA finalizes a standard for coal-fired EGUs based on partial CCS, they support a standard of 1,200 lb CO2/MWh for fossil fuel-fired utility boilers and IGCC units.  These standards are within the ranges proposed by EPA and more accurately account for unit cycling, performance degradation, and other factors.  If EPA does not adopt the higher performance standards, EPA should consider a sliding scale based on generation thresholds to determine the performance standard for EGUs on an individualized basis.  For example, the highest limit should apply to units operating at low capacity factors (i.e., in the 33 percent to 45 percent range).  The emissions limit could be reduced incrementally as the generation threshold increases.
The final standard of performance is less stringent than this commenter recommends, and so provides a greater degree of flexibility. This final standard of performance for newly constructed fossil fuel-fired steam generating units provides a clear and achievable path forward for the construction of such sources while addressing GHG emissions and supporting technological innovation. The standard of 1,400 lb CO2/MWh-g is achievable by fossil fuel-fired steam generating units for all fuel types, under a wide range of conditions, and throughout the United States.
One commenter (8957) stated separate emission limits must be established for each type of fossil fuel-fired units. Additionally, dual fuel capability should be more adequately addressed for boilers and turbines. The requirement for a turbine to burn at least 90% natural gas to be an affected source needs to be removed. Most turbines are capable of firing multiple fuels without major modifications, so a turbine can simply fire 11% petroleum or other fuel to completely avoid the regulation. EPA should set a performance standard of 1,000 lbs C02/MWh (gross) or 1,050 lbs C02/MWh (net) on a 12-month annual average basis for NGCC and 1,800 lbs C02/MWh (gross) or 1,925 lbs C02/MWh (net) on a 12-month annual average basis for coal-fired units. After it becomes an economically feasible control technology, CCS will become the BACT to reduce C02 emissions for both coal-fired and natural gas-fired power plants that are subject to the Tailoring Rule. The commenter agreed with EPA that NSPS should be the floor for determining BACT and when it becomes an economically feasible control technology, CCS will become the BACT for PSD permits.
One commenter (10043) requested that EPA increase the emissions limit for new NGCC units from 1,000 to 1,250 lbs. CO2/MWh. While it is possible to purchase a new NGCC unit that meets the 1,000 lbs CO2/MWh threshold in the short term, it is unclear whether new NGCC units can sustain that high level when used to firm up delivery of wind and other intermittent generation sources
One commenter (10095-2618) stated that for NGCCs, EPA must set an emissions limit that is achievable and considers economic-, environmental-, and energy-related impacts. EPA must explain how the standard is achievable under the most adverse conditions which can reasonably be expected to occur. Historical operating data show that many units operate above the proposed standard when experiencing adverse conditions. Also, the proposed standard is constricting considering the wide operational variability NGCCs experience over the units' lifespan and does not represent the best balance of economic, environmental, and energy considerations. Finally, EPA has created unintended consequences by providing rolling three-year average applicability criteria.
 This final standard of performance for newly constructed fossil fuel-fired steam generating units provides a clear and achievable path forward for the construction of such sources while addressing GHG emissions and supporting technological innovation. The standard of 1,400 lb CO2/MWh-g is achievable by fossil fuel-fired steam generating units for all fuel types, under a wide range of conditions, and throughout the United States. See preamble section V.J and the `Achievability' TSD available in the rulemaking docket.
One commenter (7990) stated that EPA base the applicability requirements on the source's design and purpose prior to completion, because new EGUs must know what performance standards will apply to them during the licensing process. New EGUs undergoing New Source Review should be allowed to accept limits in operating permit conditions in order to remain below the Propose Rule's applicability provisions. This methodology is consistent with the current approach under the Title V program.
The commenter is mistaken.  The NSPS applies immediately. This final standard of performance for newly constructed fossil fuel-fired steam generating units provides a clear and achievable path forward for the construction of such sources while addressing GHG emissions and supporting technological innovation. The standard of 1,400 lb CO2/MWh-g is achievable by fossil fuel-fired steam generating units for all fuel types, under a wide range of conditions, and throughout the United States.
One commenter (10119) stated that EPA fails to establish that fossil fuel-fired boilers and IGCC facilities cannot achieve an emissions rate lower than 1,100 lbs CO2/MWh for coal-fired EGUs, which is based on a 25% CO2 capture rate at a new IGCC facility. According to the commenter, using the same technology necessary to capture 25% - a single-stage water-gas shift ("WGS") reactor and two-stage acid gas removal system - a facility would be expected to achieve a CO2 emission reduction of up to 75%, or an emissions rate of approximately 380 lb CO2/MWh-gross. The commenter stated that according to the proposed rule, an IGCC facility using this technology thus could dial in a far greater amount of CO2 capture and achieve a far lower CO2 emissions rate than EPA has proposed. EPA's proposed emissions standards do not reflect a minimal 25% CO2 capture rate and lack support.
One commenter (10394-1700) stated that their state has established emission performance standards (EPS) at 1,100 lbs CO2/MWh of electricity for local publicly owned electric utilities, which, unlike EPA's proposed limits, also applies to existing utilities, and in general includes emissions from boilers, combustion turbines, reciprocating or other engines and fuel cells. The commenter stated that the emission limit for large natural gas-fired units (those with a heat input threshold greater than 850 MMBtu/h) should be more stringent than EPA proposed. The commenter recommends an emission rate limit of 950 lbs CO2/MWh. According to the commenter, several permits recently issued for large natural gas-fired units have been for projects with lower emission rates and a recently permitted 1-on-1 combined cycle unit will meet the limit of 950 lbs CO2/MWh. The commenter stated that the limit for the smaller combined cycle units (heat input rating below or equal to 850 MMBtu/h) should be more stringent than proposed and be set at 1,050 lbs CO2/MWh. Based on the commenter's experience, the smaller combined cycle units can be less efficient than the larger turbines; however, their overall efficiency will still be higher than the simple cycle units. The commenter has recently permitted a 1-on-1 combined cycle unit that will meet the lower limit of 1,050 lbs CO2/MWh net (gross output), 12-month rolling average, inclusive with manufacturer turbine degradation.
 This final standard of performance for newly constructed fossil fuel-fired steam generating units provides a clear and achievable path forward for the construction of such sources while addressing GHG emissions and supporting technological innovation. The standard of 1,400 lb CO2/MWh-g is achievable by fossil fuel-fired steam generating units for all fuel types, under a wide range of conditions, and throughout the United States.
One commenter (9406) stated that although the proposed emission limit for coal-fired EGUs is based on the emissions reductions that can be achieved through CCS, EGUs are permitted to meet those standards using any combination of means. Although no new coal-fired EGUs are being planned, before the drop in natural gas prices, many states, including Pennsylvania, had informed developers that new coal-fired plants would need to be built to carbon capture ready standards. If a developer wanted to build a new coal-fired power plant for purposes of energy diversity, it could readily design it as a carbon capture ready plant and employ a wide variety of other means already described in GHG BACT determinations to achieve the proposed 1,100 lb CO2/MWh performance standard. For instance, many existing coal-fired plants can co-fire coal and natural gas to reduce emissions rates. Coal-fired plants can also use biomass fuels produced by sintering and other processes to reduce GHG emissions. At least one natural gas combined cycle plant combined solar power to reduce its overall GHG emissions produced per megawatt hour. A carbon capture ready supercritical coal-fired unit, coupled with a highly efficient NGCC unit, solar, or wind capacity and using partial biomass fuel could likely be designed to meet the proposed standard of performance. EPA could consider these alternative means of meeting its proposed standard.
The EPA largely agrees with this comment.  Co-firing with natural gas is an alternative compliance pathway for meeting the final standard for both SCPC and IGCC.
One commenter (8020; 8939; 10103 ) supports allowing plant owners to choose either compliance option: 1,100 pounds of C02 per Megawatt-hour ("lb/Mwh") over a 12-operating month rolling average, or between 1,000 and 1,050 lb/Mwh over an 84-operating month rolling average.
One commenter (1900) stated that while a 1,100 lb CO2/MWh-gross averaged over a 12-month operating period seems adequate, perhaps it could be extended to 24 months to give these companies more time to meet this demand. It may also be appropriate to set the limit for the rolling 7-year average to a stricter amount, perhaps closer to 950 lb CO2/MWh. This would cause EGU companies to take more immediate action so they don't have to meet such a strict limitation in the future. By setting a larger gap between the limitations, more action is likely to be taken in a shorter amount of time.
 The EPA is not finalizing the option of the 84-month compliance period.
One commenter (7977) stated that pursuant to Section 111(b) of the CAA, EPA must set an achievable standard for fossil fuel units that: is consistent with Congressional intent; encourages the use of local fuels; expands energy resources that could be burned in compliance with emission limits; and makes technology and fuel choices less restrictive.
The commenter states a number of factors which are not enumerated in section 111 (a), including encouraging the use of local fuels, and making technology choices and fuel choices less restrictive.  These factors are not part of a best system of emission reduction, as defined in section 111 (a).
One commenter (9513) stated that EPA needs to pay attention to detail and cannot forego the opportunity to reduce hundreds of thousands or millions of tons of CO2 emissions simply because those opportunities don't generate reductions of hundreds of millions of tons by themselves. For example, the agency proposes to establish the new emission limitations to two significant digits where 1,000 lbs/MWh is represented as 1.0 x 103 lb/MWh and sources are allowed to round down to comply. This would relax the NSPS by an additional 1-5 percent (depending on whether EPA allows sources to apply the rounding to the test results expressed in Imperial (English) or metric units). To illustrate, an emission rate of 1049.99 would round down to 1000 and comply with the proposed limit if expressed in U.S. units. If the determination is in metric units the effect would be smaller.  The commenter anticipates that this issue will be highly controversial, and yet EPA has not analyzed the impact.
This final standard of performance for newly constructed fossil fuel-fired steam generating units provides a clear and achievable path forward for the construction of such sources while addressing GHG emissions and supporting technological innovation. The standard of 1,400 lb CO2/MWh-g is achievable by fossil fuel-fired steam generating units for all fuel types, under a wide range of conditions, and throughout the United States.
One commenter (10047) recommended that EPA revise the proposed standard for coal-fired EGUs to a level equal to that met by the very latest and most efficient units permitted in the United States, and that it continue to monitor the progress of CCS or other CO2 control technologies, such that if a control technology is shown to be effective and economical in the future, EPA will be positioned to revise the NSPS as appropriate. Whereas coal-fired units were originally designed for an operating life of 35 years, recent history has shown that units can operate as long as 50 to 60 years through life-extension projects. Thus, there is the specter of half-century consequences of this NSPS. If EPA sets the CO2 standard at a level reflecting efficiency, it must be positioned to revise the standard quickly should CCS or some other control technology be shown to be economically viable in the future.
One commenter (10869) stated that the proposed optional limits (1100 or 1000-1050 lb CO2/MWh) could potentially allow a plant to implement CCS technology to reduce their emissions after the initial operation date. This approach recognizes the current state of CCS technology while providing an incentive to make it more widely available on a faster timeline than may have been the case without the carbon standard. The final standard should include firm timelines for power plants to demonstrate that they are using CCS and impose penalties if not implemented on time. The 40% rate of carbon capture implied by this standard is low. Note that installing CCS at a power plant will impose an efficiency penalty that would raise overall emissions. CCS capture rates will need to be 85% or more if this technology is to help contribute to U.S. power sector emissions reductions of 90%t or more by 2050. EPA will need to provide a pathway to a more ambitious level of carbon capture for coal-fired power plants; otherwise we risk locking in long-lived carbon-intensive energy sources.
Note that the EPA must review section 111 (b) no later than 8 years, and so will monitor on-going technical developments, as comment 10047 urges.
One commenter (10606) stated that to provide an opportunity for new natural gas-fired steam boilers to be constructed, EPA should promulgate an appropriate CO2 emission limit for natural gas-fired boilers, taking into account the maximum thermal efficiency of such a boiler. Natural gas burning emits CO2 at a rate of approximately 53 kg/MMBtu, equivalent to 116.7 lb CO2/MMBtu heat input. Therefore, an appropriate optional standard, based on heat input, would be 120 lb CO2/MMBtu (12 month rolling average) and would account for variations in the heating value and methane content of natural gas. A standard based on gross output would be approximately 1,300 lb CO2 per MWh (12 month rolling average). This proposed standard would allow the development of natural gas-fired steam generation in the future, while limiting CO2 emissions to about one-half the amount that would be produced with coal-fired generation facilities.
 This final standard of performance for newly constructed fossil fuel-fired steam generating units provides a clear and achievable path forward for the construction of such sources while addressing GHG emissions and supporting technological innovation. The standard of 1,400 lb CO2/MWh-g is achievable by fossil fuel-fired steam generating units for all fuel types, under a wide range of conditions, and throughout the United States. This standard is applicable to all new fossil-fuel fired steam generating EGUs  -  including those firing natural gas.
One commenter (10606) stated that an auxiliary or backup EGU should be exempt from the CO2 emission standard. Backup EGUs will be package boilers in almost all cases, due to the relatively low cost of such units. However, a package boiler could not comply with the proposed limit of 1,100 lb CO2/MWh gross output.
 Applicability issues are addressed in the preamble sections III.C and III.D.
6.4.1 Achievability of Proposed Standard with CCS Technology
Several commenters (9666, 9472, 9650, 10039; 10618; 10552; 10240; 10050; 10052; 8937; 9034; 10100; 5731; 9780; 9194; 9592; 9197; 10023; 9397; 8906; 10870; 8974; 9422; 10520; 9471; 10051; 10048; 9003; 10952; 10466; 0587; 9192; 8032; 10392; 9780; 10662; 7977; 8971) disagreed with EPA that BSER for coal fired EGUs  is CCS. Industry, in parallel, the U.S. Department of Energy, along with other public and private efforts, have recognized that potential CO2 emission reduction technologies, including CCS for fossil fuel-based electric generation processes, must overcome significant development barriers if they are to have any chance of becoming a technically feasible and commercially viable control option. No CCS technologies have been demonstrated in a fully integrated end-to-end configuration at scale on a coal baseload EGU. There are no commercial ventures in the United States that capture, transport, and inject industrial-scale quantities of CO2 solely for the purposes of carbon sequestration. Currently, there are no commercially viable power plant projects that employ permanent carbon sequestration. Of the examples provided by EPA in the proposed NSPS, none of the projects are currently operating.
One commenter (9780) stated that the only U.S. project already under construction, Southern Company's Kemper project, has seen significant cost overruns in the past 18 months. None of the other cited U.S. projects have achieved financial closure or broken ground, with the exception of the W.A. Parish facility, which chose to commence construction of the natural gas turbines early because it made economic sense to do so independent of the CCS project, which is still on hold. None of these projects is in operation. Kemper is not only a first-of-a-kind project, but also a one-of-a-kind project. Due to its many site-specific characteristics, the Kemper project cannot be consistently replicated on a national level. In its reliance on the Kemper project, EPA has ignored the unique nature of this project and has not explained how Kemper reasonably can serve as a model for other new EGUs in the rest of the country.
One commenter (9192) hosted a first-of-its-kind project at the Pleasant Prairie Power plant to test a chilled ammonia scrubber technology to separate and capture up to 90 percent of the CO2 emissions from a small portion of the flue gas from one of the boilers. The project did not include storage of any captured CO2. The project demonstrated that the process was capable of removing 90% of incoming CO2 from a slip stream of the host power plant's flue gas. The project operated at up to a flue gas flow equivalent of 1.7 MW electric power generation. This project represented an early step in developing a commercial-scale technology to capture CO2 emissions from existing coal-fired power plants. The pilot project confirmed the predicted performance of the chilled ammonia carbon capture system at an operating power plant. To date neither this technology nor any other has been retro-fitted at full scale at a commercially operating power plant. Therefore, the project did not demonstrate that carbon capture and storage is the best system of emission reduction.
One commenter (10618) operated the first integrated CCS project in the world on a coal- based generation plant. The commenter stated they provided comments on the 2012 proposal to alleviate misconceptions by EPA by placing into proper context the scope and outcome of its CCS program. The current proposed rule continues to misrepresent the scope, results, and lessons learned from the Mountaineer Plant CCS project. In their submittal, the commenter provided a number of qualifications regarding the results of that CCS project. While the project was successful, it is a far cry from being representative of what's required for full-scale deployment.
Commenter (10039) stated that EPA's finds CCS as BSER for coal fired EGUs in the absence of any operating data from any CO2 sources of the size of a pulverized coal EGU (above 3,000 mmBtu/hr heat input). US EPA does not present any data in the rule docket from the type and size of sources it proposes to require to meet the BSER limits of this proposed rule because neither carbon capture nor geological sequestration have ever been implemented at a coal fired EGU greater than 100 MW before.
One commenter (9666) stated that EPA's achievability determination is not supported by any technical or statistical analysis of emissions data from units implementing CCS because no such data exist. According to the commenter, EPA relies on a 2011 cost and performance report by DOE that assumes the performance of various CCS configurations and is not based on information gathered from actual operating experience. The commenter further stated that EPA's only achievability analysis is based on its estimates of CCS performance using pre-combustion CO2 separation technology, which can be implemented only at IGCC units and that EPA nowhere analyzes whether the proposed 1,100 lb/MWh limit is achievable for units firing PC.
One commenter (9472) stated that EPA is proposing to set a stringent CO2 performance standard which no new coal-fueled plant anywhere in the world has come close to meeting based on CCS technology that is not adequately demonstrated. The commenter stated that the EPA record shows that there are no coal-fueled power plants in the US -or even in the world - that are currently operating with a full-scale commercial application of CCS. According to the commenter, the flaw in the EPA proposal is concluding that CCS is adequately demonstrated based on the assumption that a few planned, but unbuilt, full-scale CCS project will successfully demonstrate in the future the effectiveness and reliability of this emerging, but unproven technology. The Agency is proposing to set a CO2 performance standard based on mere speculation or conjecture.
The commenter (9472) stated that EPA cannot base its BSER determination on small or experimental projects that seek to demonstrate CCS at pilot scale, for example, plants at Vattenfall, Germany; Southern Company's Plant Barry; and AEP sponsored Mountaineer Power Plant. The commenter stated that these pilot-scale slipstream projects have proven that CCS is a potentially viable technology but is insufficient to demonstrate that CCS can be implemented at full-scale utility applications.
The commenter (9472) stated that EPA cannot base its BSER determination on a few industrial applications of CCS. According to the commenter, none of the industrial projects referenced by EPA involve the full-scale commercial application of a CCS technology on a power plant that sells electricity into the grid and therefore cannot constitute an "adequately demonstrated" technology that can be used to set performance standards for coal-fueled power plants under section 111(b) of the CAA. For several industrial CCS projects cited by EPA, the commenter described how such facilities differed from coal-fueled power plants.