It is not surprising that most CCS projects that have been identified are receiving or have received government support of some form. Prior to this final action, there was no requirement that any EGUs reduce GHG emissions.  In a 2011 press release, Alstom Senior Vice President for Power and Environment Policies Joan MacNaughton was quoted as saying, "The Validation Plant at Mountaineer demonstrated the ability to capture up to 90% of the carbon dioxide from a stream of the plant's emissions. The technology works. But without clear policies in place outlining options for cost recovery, power generators are hard-pressed to invest in its continued refinement." Similarly, AEP Chairman and CEO Michael Morris was quoted in an AEP press release on the Mountaineer Project being put on hold  -  "But as a regulated utility, it is impossible to gain regulatory approval to recover our share of the costs for validating and deploying the technology without federal requirements to reduce greenhouse gas emissions already in place."  The EPA did not consider potential cost reduction from government subsidies when evaluating the reasonableness of costs for the final standard of performance.
Commenter 9514 stated that EPA properly determined that the costs of partial CCS can be accommodated by industry. According to the commenter, EPA's conclusion is supported by the broadly-maintained prediction that, due to current and predicted economic conditions, very few new coal-fired power plants will be built in the future, if any. The commenter stated that the costs of the partial CCS standard - approximately a 20 percent increase - on a few new coal-fired plants can easily be accommodated by industry. The commenter stated that the proposal will have little impact on consumer electric prices and given that so few plants will be built, from an industry-wide perspective the costs of meeting the standard based on full CCS are not exorbitant.
Commenter 10106 stated that while there may be some additional incremental costs for Wisconsin relative to some other states as a result of a requirement to implement CCS, these costs are also not at a level which would prohibit an operator from constructing a new power plant. According to the commenter, since electrical generation and service provision are highly regulated in the State of Wisconsin - including the presence of regulated monopolies for energy utility companies - no competitive advantage or disadvantage will be incurred for regulated entities within the state as a result of such a requirement. Furthermore, the commenter stated, interstate cost differences induced as a result of the proposed NSPS are not qualitatively different than those corresponding to other rules - for example the recently upheld Cross-State Air Pollution Rule.
The EPA largely agrees with these comments.
Commenter 9774 stated that EPA's NSPS analysis of CCS does not account for the cost and issues related to transporting CO2 to proven carbon sequestration sites. The commenter referenced the EPA estimate that the equipment costs necessary for removing CO2 at a 550MW supercritical coal generating unit is approximately $267 million, whereas a recent BACT analysis by the Wisconsin DNR yielded costs of approximately $405 million for construction of a CO2 pipeline to the closest potential sequestration site. The commenter provided additional information that CO2 sequestration costs for Wisconsin utilities resulted in an estimate of $550 million to $1 billion capital cost for a pipeline network that would be required to serve Wisconsin coal-fired generation. The commenter noted that these presented costs do not include the additional costs associated with operating CO2 pipelines, and EPA must also address the difficulties, logistics and significant additional expense of placing pipelines and facilities in urban areas.
Commenter 10095 stated that in the CCS cost estimates that incorporate EOR opportunities, EPA assumes that an EGU is only responsible for the costs of transmitting the captured CO2 to the facility's fence line where the point of sale occurs and the EGU will avoid CO2 transmission, storage, and monitoring costs. The commenter disagreed and provides the example that the Kemper County Energy Facility, which is uniquely situated in close proximity to EOR opportunities, constructed a 61 mile CO2 pipeline to transact with third party CO2 off-takers and reduce third party-related risks. The point of transaction occurs at two locations along the 61 mile pipeline-Pachuta and Heidelburg, Mississippi. The cost incurred by Mississippi Power to construct this pipeline was $108 million. Considering the Kemper County Energy Facility's proximity to EOR opportunities and the ability to transact with two CO2 off-takers along a single pipeline, the commenter stated that the cost incurred by future projects will almost certainly be higher. According to the commenter, EPA needs to reevaluate its cost estimates with consideration of pipeline construction costs incurred by the EGU even when engaging in relatively close EOR opportunities.
Commenter 7977 noted that the NETL costs exclude transportation costs of CO2, which could significantly increase the cost estimate for new sources implementing CCS technology. According to the commenter, Section 111(a)(1) of the CAA requires that EPA account for the "costs of achieving such reductions" and since EPA is proposing that CCS is the BSER for coal-fired EGUs, EPA must account for the cost of transporting CO2. The commenter also stated the proposed regulation relies on the expected typical pipeline distance to be 50 miles to possible geologic sequestration sites, however, according to the commenter, this distance underestimates the actual distances that may be necessary for the transmission of CO2. The commenter continued that EPA is required to comprehensively evaluate the impact of all associated transportation costs via pipelines, including availability and acquisitions of right-of-way for new pipelines, capital and operating costs, and actual length of transmission pipelines. Additionally, the commenter stated other costs, including the performance of expensive seismic studies, must be accounted for prior to a regulated entity being able to store CO2 long-term.
Commenter 9773 stated EPA's analysis of CCS is problematic in that it does not account for the cost to transport CO2 from utility plants to proven sequestration sites located more than 50 miles away. According to the commenter, since Wisconsin does not have even a single proven sequestration site, transporting CO2 out-of-state for sequestration is the only option. And the cost of such transport would be substantial. The commenter referenced an analysis by Wisconsin using DOE cost methods which determined that a pipeline network from Wisconsin to the Illinois Basin (the nearest potential sequestration site) would cost between $550 million to $1 billion. The commenter stated that such an investment would be cost-prohibitive and have a real and detrimental effect on Wisconsin ratepayers. The commenter suggested that to address this issue, when setting the NSPS, EPA must first fully consider and quantify the costs of transporting CO2 from where existing coal-fired generating units are currently operating to proven sequestration sites.
 See preamble section V.I.5. The EPA's cost estimates do in fact include costs associated with transportation and storage of CO2. For transport, costs reflect pipeline capital costs, related capital expenditures, and O&M costs. Sequestration cost estimates reflect the cost of site screening and evaluation, the cost of injection wells, the cost of injection equipment, operation and maintenance costs, pore volume acquisition expense, and long term liability protection. These sequestration costs reflect the regulatory requirements of the Underground Injection Control Class VI program and GHGRP subpart RR for geologic sequestration of CO2 in deep saline formations. We expect that when CO2 is sold for EOR applications, the buyer rather than the EGU operator will likely bear those costs. However, for the purposes of the cost analysis, the transportation, storage and monitoring (TS&M) costs are included for both EOR and non-EOR applications, recognizing that this likely slightly overstates the cost to the operator in circumstances where CO2 is sold for EOR. The EPA's cost estimates for transportation and sequestration thus cover all aspects commenters claimed the EPA disregarded.

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.
Commenter 9472 stated that EPA ignores the technical and permitting challenges of CO2 storage and therefore fails to assess fully the costs of CCS.  The commenter discussed technical concerns with EOR and saline storage and stated that EPA failed to consider several aspects of CO2 storage that limit the feasibility of utilizing CCS at a coal-fueled power plant.
See preamble section V.I.5.
Commenter 9666 discussed several concerns with the use of costs associated with the resale of captured CO2 for use in EOR. The commenter stated EPA cannot rely on the potential resale of captured CO2 for use in EOR to reduce the expected cost of its CCS mandate given the uncertainties facing EOR operators. According to the commenter, EOR operators are concerned that the proposed rule's requirement for EOR operators that purchase CO2 from EGUs to have to report emissions under the more stringent requirements of Subpart RR of 40 C.F.R. part 98, rather than Subpart UU with which they currently comply, "will create regulatory uncertainty and risk that will result in EOR operators avoiding the purchase of CO2 that is subject to those rules."  The commenter also stated that instead of benefiting financially from capturing CO2 emissions, EGUs would likely have to pay EOR operators to take the CO2, which removes any cost justification that EPA ascribes to CCS based on EOR. Furthermore, the commenter stated that EPA admits that resale for EOR is "non-economical" or unavailable for some locations in which new Subpart Da units may be built, therefore the cost of CCS with resale for EOR does not represent the cost of installing CCS on new units throughout the country, and should not be considered in determining the proposed NSPS.
Commenter 9426 stated that the EPA has only estimated the cost of IGCC units with partial CCS associated with EOR, and this is insufficient for setting a standard to apply to PC units or to any unit that is not using EOR, or for any unit seeking to store CO2 in saline geological formations.
Commenter 9197 disagreed with EPA assumptions that EOR is widely available and that EOR operators will pay significant premiums for CO2 from regulated EGUs. According to the commenter, EOR sites are not available in many parts of the country, while in others there may be significant infrastructure barriers (in particular, the need to construct new pipelines) that will substantially raise the costs of using this system of emission reduction. The commenter also stated there is a real possibility that EOR operators will not accept CO2 from EGUs due to the uncertainty and risk of reporting under Subpart RR related to MRV plans, and the burdens inherent in transitioning from a Class II well to a Class VI well under EPA's proposed Underground Injection Control Program policy.
See preamble section V.I.5. The BSER determination and regulatory impact analysis for this rule relies on GS in deep saline formations. However, the EPA also recognizes the potential for sequestering CO2 via EOR and allows the use of EOR as a compliance option.

The EPA disagrees that GHGRP subpart RR requirements will result in EOR operators avoiding the purchase of CO2 from affected EGUs.

The cost of compliance with subpart RR is not significant enough to offset the potential revenue for the EOR operator from the sale of produced oil for CCS projects that are reliant on EOR. First, the costs associated with subpart RR are relatively modest, especially in comparison with revenues from an EOR field. In the economic impact analysis for subpart RR, the EPA estimated that an EOR project with a Class II permit would incur a first year cost of up to $147,030 to develop an MRV plan, and an annual cost of $27,787 to maintain the plan; the EPA estimated annual reporting and recordkeeping costs at $13,262 per year. Monitoring costs are estimated to range from $0.02 per metric ton (base case scenario) to approximately $2 per metric ton of CO2 (high scenario). Using a range of scenarios (that included high end estimates), these subpart RR costs are approximately three to four percent of estimated revenues for an average EOR field, indicating that the costs can readily be absorbed. 75 FR 75073.
Furthermore, there is a demand for new CO2 by EOR operators, even beyond current natural sources of CO2. For example, in an April 2014 study, DOE concluded that future development of EOR will need to rely on captured CO2. Thus, the argument that EOR operators will obtain CO2 from other sources without triggering subpart RR responsibilities, which assumes adequate supplies of CO2 from other sources, lacks foundation.

In addition, the Internal Revenue Code section 45Q provides a tax credit for CO2 sequestration which is far greater than subpart RR costs. Section 45Q(a)(1) allows a credit of $20 per metric ton of qualified CO2 that is captured by the taxpayer at a qualified facility, disposed of by the taxpayer in secure geological storage, and not used by the taxpayer as a tertiary injectant. Section 45Q(a)(2) allows a credit of $10 per metric ton of qualified CO2 that is captured by the taxpayer at a qualified facility, used by the taxpayer as a tertiary injectant in a qualified enhanced oil or natural gas recovery project, and disposed of by the taxpayer in secure geological storage. The section 45Q credit for calendar year 2015 is $21.85 per metric ton of qualified CO2 under section 45Q(a)(1) and $10.92 per metric ton of qualified CO2 under section 45Q(a)(2).
Commenter 7893 stated that it is critical to understand that the option to sell captured CO2 to EOR operations does not exist for Interior coal-fired plants because there is no nearby oil or gas production. According to the commenter, the extremely high costs of partial CCS for new coal-fired facilities would not be offset by EOR.
Commenter 495 stated the EPA has not demonstrated the availability or feasibility of CCS in areas that will be most affected by the Proposed Rule, as the Midwest and other areas of the country have limited access to EOR sites, which directly impacts the cost of implementing CCS. The commenter also noted that EPA assumes the market for EOR will not become oversaturated if the Proposed Rule moves forward as there are a limited number of EOR sites and all of them are congregated in small portions of the county. The commenter noted that EPA estimates that transporting CO2 will cost in the range of $1 to $4 per ton, however, according to the commenter, pipelines are not inexpensive or easy to construct, and it is unclear whether the EPA's estimate includes the costs of right-of-ways, pipeline construction, permitting delays, and length of transportation, among others.
Commenter 840 stated the pipelines and storage needed to support safe sequestration of CO2 does not exist in many areas of the country and require substantial public planning and investment. According to the commenter, electric customers cannot shoulder this burden alone and CCS fails to satisfy the Clean Air Act's requirement for being achievable at a reasonable cost.
Commenter 10667 stated the proposed rule indicates, that the sale of captured CO2 for Enhanced Oil Recovery (EOR) offers the opportunity to defray a portion of the CCS costs, however, unfortunately, this option does not even exist for interior coal-fired plants due to the lack of nearby oil or gas production activities. The commenter provided areas of Alaska where EOR operations exist, noting that the captured CO2 would have to be shipped to one of those areas since there is no pipeline (also, the closest is 500 miles away). Thus, the commenter stated that leaves high costs of partial CCS for new coal fired facilities economically and logistically impractical and without any benefit from EOR.
Commenter 9427 stated EOR, the single geologic storage option that is potentially realistic at present, is only accessible to a limited geography and faces significant regulatory hurdles and risks. According to the commenter, EPA's cost estimates significantly underestimate costs, including because they unreasonably exclude "first of its kind" costs and overestimate any cost-mitigating effect of EOR.
 The EPA reiterates that the BSER determination and regulatory impact analysis for this rule relies on GS in deep saline formations. However, the EPA also recognizes the potential for sequestering CO2 via EOR and allows the use of EOR as a compliance option. In estimating impacts of the rule, the EPA relied on NETL studies referenced in Section V.I.2 of the preamble, which base transport costs on a generic 100 km (62 mi) pipeline and a generic 80 kilometer pipeline. For transport, costs reflect pipeline capital costs, related capital expenditures, and O&M costs. See preamble section V.I.5. Pipeline capital costs include materials, direct labor, right-of-way acquisition, surveying, engineering, supervision, contingencies, allowances for funds used during construction, administration and overheads, and regulatory filing fees. See preamble section V.M.5 regarding the availability of CO2 pipelines and elsewhere in this Chapter 6 regarding feasibility of GS in Alaska.
Commenter 10098 stated that EPA has no basis to assume that all CO2 captured can be sold to a willing buyer. The commenter stated that EPA has provided no analysis of the market for CO2, including where EOR is being used, whether supplies of CO2 are actually in demand, or a comparison of the cost of drawing from a natural CO2 reservoir versus purchasing captured CO2. The commenter also indicated that there is a contradiction between the proposed rule and EPA's assumptions for purposes of PSD permitting in which EPA has repeatedly rejected the assumption that the owner or operator of a coal-fired power plant can sell captured CO2 for EOR and that those speculative sales should be included in CCS cost estimates.
Commenter 10239 also stated concern with the deduction of a portion of CCS costs based on the assumption that EGUs employing CCS technology will sell their captured CO2 for EOR. According to the commenter, this is factually incorrect and inconsistent with the EPA's position in PSD BACT determinations and the GHG Guidance that a facility could not count on the availability of EOR when assessing the feasibility of CCS technology. The EPA offers no rational basis for reversing the Agency's prior position that there is no guarantee at the time of planning or even construction that EOR will be available to offset a portion of the costs of CCS technology.
The EPA reiterates that the BSER determination and regulatory impact analysis for this rule relies on GS in deep saline formations. However, the EPA also recognizes the potential for sequestering CO2 via EOR and allows the use of EOR as a compliance option. The EPA is assessing costs conservatively by not including any revenues from EOR, even though new plants may well avail themselves of EOR opportunities (e.g. Boundary Dam and Kemper).
Commenter 9664 stated that revenue generated by the sale of captured CO2 for use in EOR further reduces costs associated with the standard. The commenter references analysis performed by CATF in support of the Agency's 2012 proposal that showed that revenue from the sale of captured CO2 for EOR lowers by 12 percent the LCOE of applying a standard roughly equivalent to that currently proposed. According to the commenter, EPA may take into account byproduct revenue associated with a system of emissions reduction, in considering the costs associated with a standard reflecting that system.  The commenter stated that while the D.C. Circuit has yet to address directly whether EPA may take byproduct revenue associated with the choice of BSER into account in evaluating the costs of a performance standard, the court has held that the agency retains broad authority to weigh all of the statutory factors in a BSER determination, noting that questions of costs and benefits must be addressed taking a long-term perspective. The commenter then referenced the 2012 cost analysis for the new fuel economy standards for light-duty vehicles providing additional discussion, and concluded that it is well reasoned - wholly logical and appropriate - for EPA to consider revenue streams from the co-production of CO2 (from the sale by the regulated power plant of captured CO2 to an EOR operator for use and long-term containment in depleted oil or gas fields, e.g.) in evaluating the costs of a standard for which the underlying BSER includes carbon capture technology. The commenter also states that although EOR sales are not now available everywhere, it is expected that any new coal fired subpart Da unit would locate so as to take advantage of such revenue offsets to the cost of applying control technology to meet the standard. According to the commenter, EOR operations in the U.S. can accommodate and provide long-term containment for substantial volumes of CO2 as well as the cost-offsetting revenue attendant to the sale of the anthropogenic CO2 by the EGU operator.
Commenter 9035 stated it is crucial that power companies are enabled to sell captured carbon to CO2-EOR operators and that EPA continue to recognize a pathway for demonstrating the geologic storage of CO2 through EOR projects.
Commenter 9514 stated that while they do not intend their comments to endorse the practice of EOR, section 111 allows a broad consideration of costs, including the sale of byproducts, and EPA may properly take the possibility of EOR sales into account when evaluating the costs of the proposed performance standard. The commenter cited See Sierra Club v. Costle, 657 F.2d at 330. ("[S]ection 111 . . . gives EPA authority when determining the best technological system to weigh cost, energy, and environmental impacts in the broadest sense over time.").
Commenter 10108 stated EPA has considered revenues from compliance measures when conducting cost analyses in past rulemakings, and referenced the 2012 rulemaking revising the NSPS for oil and gas facilities, in which EPA considered revenues from increased recovery of natural gas when evaluating the cost-effectiveness of measures to reduce VOC emissions and in a 2012 regional haze FIP in which the Agency adjusted its proposed cost calculations to take into account fly ash sales that could be continued through more-efficient technology. As a result, the commenter stated that EPA's discussion of costs reasonably includes the potential EOR revenues from CCS even though it does not rely on EOR revenues in arriving at the $110/MWh cost figure it deems reasonable. According to the commenter, the cost of CCS with coal is reasonable even without EOR and the availability of non-EOR carbon sequestration sites is widespread in the United States, noting that almost all existing large sources of CO2 are located within 50 miles of a possible sequestration site.
Revenues from by-product sales can be relevant in assessing costs under section 111 (a). See New York v. Reilly, 969 F. 2d 1147, 1150-52 (D.C. Cir. 1992).  However, the EPA is (conservatively) not considering such potential revenues here in its assessment of costs.  See preamble section V.E.8.
Commenter 9772 stated the viability of using CO2 for EOR is "site and situation- - specific" and depends on a number of factors: location, geologic characteristics of the location, state of development and depletion of the target field, the amount of CO2 required and a number of infrastructure investments, including pipeline construction. The commenter referenced a study from the Global CCS Institute which noted, "total CO2 costs (both purchase price and recycle costs) can amount to 25% to 50% of the cost per barrel of oil produced. As such, operators have historically strived to optimize and reduce the cost of its purchase and injection wherever possible."
Commenter 9486 questioned, in the context of using captured CO2 for EOR, what the net reduction of CO2 would actually be given the proposal, and what the net cost would be for that reduction. The commenter stated that this rule, as it is currently structured, shifts the cost of CO2 emissions from one fossil fuel sector to another and the net decrease in CO2 emissions would not be cost effective under the BSER requirements.
The EPA is not basing its cost assessment on utilization of EOR.
Commenter 9678 stated that EPA has also not adequately addressed the regulations and guidelines that are applicable to EOR. Specifically, the commenter noted that EPA's Draft Underground Injection Control (UIC) Program Guidance on Transitioning Class II Wells to Class VI Wells could have a substantial impact on EPA's determination of BSER by affecting both the availability of CCS and the relative cost of CCS. The commenter discussed that if the guidance serves to decrease the availability of EOR for sequestration of EGU-produced CO2, then this could have a substantial impact on EPA's assessment of the availability and cost of partial CCS. The commenter also discussed that EPA has failed to note in the Proposed Rule that there are significant differences in the regulatory requirements that apply to Class II versus Class VI wells, including different levels of financial responsibility (for corrective action, post-injection site care and remedial response), reporting requirements, and post-injection site care and site closure. The commenter concluded that EPA must more fully assess the multiple barriers that still exist to long-term geological storage of CO2 and the impact of these barriers on the projected availability of partial CCS and the costs of the Proposed Rule, before it may determine the level of a NSPS based on the use of CCS technology.
Commenter 9425 stated EPA should not rely on the potential resale of captured CO2 for use in EOR to reduce the expected cost of its proposed CCS mandate. According to the commenter, many EOR operators are concerned that the proposed rule's requirement for EOR operators that purchase CO2 from EGUs to have to report emissions under the more stringent requirements of Subpart RR of 40 CPR Part 98, rather than Subpart UU with which they currently comply, will create regulatory uncertainty and risk. The commenter stated that EGUs may have to pay EOR operators to take the CO2 which would remove any cost justification that EPA ascribes to CCS based on EOR. The commenter also stated that EPA admits that resale for EOR is "non-economical" or unavailable for some locations in which new coal units may be built (79 FR 1478), and therefore, the cost of CCS with resale for EOR does not represent the cost of installing CCS on new units throughout the country, and should not be considered in determining the proposed NSPS.
Commenter 9596 stated that EOR sites are not available in many parts of the country, while in others there may be significant infrastructure barriers (in particular, the need to construct new pipelines) that will substantially raise the costs of using this system of emission reduction. The commenter also stated there is a real possibility that EOR operators will not accept CO2 from EGUs due to the uncertainty and risk of reporting under Subpart RR (in particular, complying with Subpart RR's requirement to prepare and comply with a MRV plan for geologic sequestration of CO2) and the burdens inherent in transitioning from a Class II well to a Class VI well under EPA's proposed Underground Injection Control Program policy.
Commenter 9197 stated that even where EOR is available and operators are willing to accept CO2 from regulated power plants, the added risks to well operators from EPA's policies could significantly reduce the amount that these operators will pay for captured CO2. Therefore, according to the commenter, it is likely that the costs of implementing the NSPS will be significantly higher than those cited by EPA in the proposed rule-especially for EGUs that are located far from viable EOR sites.
Commenter 9486 stated that it is common understanding that EOR can use no more than 20% of the CO2 expected to be captured by the full implementation of CCS, and as such, an EOR market with an overabundance of CO2 available will not generate the same revenue for EGUs from the sale of CO2 as U.S. EPA estimates. According to the commenter, without the monetary compensation associated with the sale of CO2 to oil companies, the cost for CCS becomes even more prohibitive.
Commenter 9678 questions whether Class II wells may automatically convert to Class VI by virtue of reporting under GHGRP subpart RR.  Reporting under subpart RR does not trigger the transition of a Class II well to a Class VI well. See preamble section V.N.5.a. Furthermore, on April 23, 2015, the EPA issued a memorandum from the Director of the Office of Ground Water and Drinking Water to regional UIC Program Directors in its regional offices, and summarized in section V.N.5.a of the preamble, that makes clear that the commenter's concerns with respect to the guidance are misplaced. The EPA is aware that the regulatory requirements differ for Class II and Class VI wells.  The compliance cost estimates for the final rule are based on the more expensive costs for Class VI geologic sequestration.  See preamble section V.I.5 and N.1.
Commenter 9425 and 9596 stated that EPA should not rely on the potential resale of captured CO2 for use in EOR to reduce the expected cost of its proposed CCS mandate, and EPA in fact is not doing so, as noted in other comment responses.  However, as explained in preamble section V.N.5 and elsewhere in this chapter, there are sound, objective reasons to believe that EOR operators will continue to pay for anthropogenic CO2.
Commenter 1591 stated that EPA is justifying the costs of CCS on NOAK costs when in fact there is not even a single FOAK plant of commercial scale in operation. According to the commenter, further compounding this error, EPA then improperly assumes that the other plants EPA cites as "under development" (more accurately characterized as "under consideration") will use the same technology as the FOAK plants.
Commenter 9666 stated EPA incorrectly assumes that any future Subpart Da unit equipped with CCS would face lower "next-of-a-kind" costs rather than the unreasonably high "first-of-a-kind" costs incurred by CCS units currently in development. According to the commenter, the units under development, however, each contain unique CO2 capture processes and other design elements. The commenter concluded that for these reasons, and other uncertainties that must be resolved (property rights, water, etc.), EPA cannot assume that "next-of-a-kind" costs for CCS will necessarily be lower than "first-of-a-kind."
Commenter 10098 stated that using NOAK cost assumptions is arbitrary and capricious. According to the commenter, the proposed rule's cost estimates in Table 6 are not those that would actually be incurred by a commercial-scale coal-fired power plant constructing and operating an experimental, demonstration-scale CCS unit, as would be required to comply with the proposed rule's emission limitation. Instead, the commenter suggested they are the costs for mature CCS technology that do "not include the unique cost premiums associated with FOAK plants that must demonstrate emerging technologies and iteratively improve upon initial plant designs." The commenter explained that the LCOE costs relied upon EPA are not the actual costs of complying with the proposed NSPS emission limitation but the conjectural, estimated costs of constructing and operating CCS at some time in the unspecified future, assuming that there is widespread adoption, and further assuming that there are several successful research and development projects.
 Commenter 9472 discussed how EPA ignores the limitations of the CCS cost estimates in the NETL analysis, stating that the substantial uncertainty and potential for significant variations in CO2 storage costs limit the usefulness of the NETL study in evaluating the cost basis for CCS in NSPS. The commenter also suggested that EPA recognize the limited opportunities for learning to date and use higher FOAK cost estimates while appropriately noting the uncertainty and limitations of those estimates.
Commenter 10618 stated that the use by EPA of CCS costs that are premised on the conjecture of NOAK projects does not remotely provide reliable, accurate estimates, is irrelevant for use in preforming any objective analysis of new generation options, and has the appearance of being nothing more than weak attempt to justify a preconceived BSER outcome that could not otherwise be validated through the use of more reasonable and accurate information. The commenter stated that EPA's cost analysis fails to demonstrate that CCS is the BSER and cites the following reasons:
   * an incorrect assessment of the development status of CCS, which results in using cost estimates for yet-to-be realized more mature nth-of-a-kind ("NOAK") type technologies, rather than initial first-of-a-kind ("FOAK") technologies;
   * a narrow reliance on two reports that are based on dated vendor supplied conceptual designs for CCS and IGCC technologies that have never been constructed or proven;
   * a failure to consider any of the costs and lessons learned from actual CCS related projects that have been constructed or that are actively being developed; and
   * a failure to consider more recent and relevant studies of the cost of advanced coal-based generation and CCS technologies.
Commenter 10618 also stated that EPA's cost analysis is flawed due to an incorrect assumption that CCS development has advanced beyond FOAK technologies. The commenter noted that reliable demonstrated FOAK costs for CCS and advanced coal generation technologies, such as IGCC, are not available. According to the commenter, the current state of CCS development has been widely recognized to be at the FOAK deployment phase, including by the Interagency Task Force on CCS. According to the commenter, in regards to IGCC, any cost estimates for future projects are speculative at best due to the early stage of development. The two IGCC projects under active construction and commissioning in the U.S. are both FOAK processes and have both experienced significant cost escalations throughout their development.  The commenter agreed that certain highly efficient generating technologies are cost effective as evidenced by the number of projects that are being successfully completed worldwide.
Commenter 10618 stated that reliable baseline costs, performance information, and lessons learned from FOAK CCS projects are required before the true scope of cost implications can be understood; however, because CCS development issues are far from being one-sized-fits-all, the completion of multiple commercial-scale projects on coal-based generating units is critical for informing for any meaningful cost estimate of future NOAK CCS processes. The commenter stated that EPA does not take into account the cost, performance, and other lessons learned from the AEP Mountaineer Plant CCS Validation Project in its reliance on the NETL report.  The commenter stated that the recent experience of CCS and advanced coal-based generation projects underscores the difficulty of developing reliable costs FOAK technologies, yet alone the significant uncertainty and challenge of being able to assess the cost of future FOAK and especially NOAK projects with any degree of accuracy. According to the commenter, this difficulty is highlighted by the projects that EPA relies upon in the proposed rule where there is a wide disparity in costs and where each project is experiencing significant cost escalations.
Commenter 10618 stated a number of recent assessments have concluded that CCS for fossil fuel-fired electric generation currently is and will remain at the FOAK level of development for many years. According to the commenter, these conclusions do not support EPA's use of cost estimates that the agency presumes represent technologies that have matured beyond FOAK projects. The commenter referenced the 2010 DOE/NETL CCS Roadmap which noted that the DOE RD&D effort "involves pursuing advanced CCS technology...so that full-scale demonstrations can begin by 2020" in order to "enable broader commercial deployment of CCS to begin by 2030." The commenter also referenced the DOE/NETL "Carbon Capture" website discusses the following in the very first paragraph: "first-generation CO2 capture technologies are currently being used in various industrial applications. However, in their current state of development, these technologies are not ready for implementation on coal-based power plants because they have not been demonstrated at appropriate scale, require approximately one-third of the plant's steam and power to operate, and are cost prohibitive." The commenter referenced another separate NETL report that notes "the definition of the NOAK plant is somewhat arbitrary as well, although it is often taken as the fifth or higher plant." According to the commenter, the minimal commercial-scale CCS projects that are actively being developed may be sufficiently unique as to limit the overall progress of the technology beyond FOAK applications. The commenter also stated that the DOE CCS Roadmap also estimates that commercial-scale CCS will add 80% to the cost of electricity for a new pulverized coal unit and 35% to the cost of a new IGCC unit and highlights the infancy of the technology as a potential emissions control option for coal-based generation, and therefore it is clear from this information that cost estimates for future CCS projects are far from being able to accurately represent NOAK processes.
Commenter 10618 stated that for any individual project, the cost estimate will change throughout the phases of development: (i) conceptual design; (ii) front-end engineering & design (FEED); (iii) detailed design; (iv) construction; (v) startup & commission; (vi) operational. According to the commenter, as technologies mature, the cost differential between conceptual design and operational cost will become less, and this cost differential for an individual project can vary significantly across the development cycle, as well as from project to project that employ FOAK technologies. The commenter provided tables that summarize costs of actual CCS projects that have been or that currently are being developed to demonstrate this variability and to highlight the fact that CCS technology is far from advancing beyond a FOAK level of development.
Commenter 9780 stated that the following important factors appear to be ignored in the NOAK cost projections: (1) CCS projects currently under construction have experienced significant cost overruns, which are not accounted for in the NETL FOAK cost analysis that is the baseline for projecting the nth of a kind costs EPA relies upon; and (2) the analysis does not reflect the cost premiums associated with early plant deployments, which carry significantly higher cost and engineering procurement and construction premiums not reflected in the cost analysis. The commenter provides analysis of the NETL report, noting that EPA has adopted the cost estimates while omitting several important cost considerations. The commenter also stated that EPA has not justified its assumption that the costs of CCS will decrease more quickly than other costs, and provided additional discussion that there is no reason to believe that substantial new assistance-driven demonstration projects will be undertaken to drive down costs of CCS on EGUs.
Commenter 10239 stated the EPA seeks to reduce the LCOE for partial CCS by using projected NOAK costs when there is currently no FOAK example of a commercial-scale coal-fired EGU applying any form of CCS.  The commenter stated that in the absence of an established technology, it is arbitrary and capricious for the EPA to ignore the unique cost premiums associated with FOAK plants that must demonstrate emerging technologies and iteratively improve upon initial plant designs.
Commenter 10952 noted that that EPA uses a few demonstration CCS projects as FOAK projects to then conclude that next projects can be evaluated at "next commercial offering costs," although it fails to use actual cost data associated with these first project costs.
Commenter 10952 stated that EPA cannot reasonably rely on Table 6 LCOE data that are based the theory that as technology matures with the construction of successive plants, the cost decreases. According to the commenter, for either full or partial carbon capture, technology adjustments, increasing material and labor costs, and unforeseen intervening factors can significantly inflate what the proposal describes as LCOE for a next commercial offering or a NOAK facility. The commenter stated  that the docket contains no information on the methodology utilized to arrive at the conclusion that "next commercial offering" cost would even approximate the LCOE data in Table 6, and why in fact the next commercial offering would not exceed even a FOAK facility. The commenter discussed each of the projects in the EPA analysis, noting that no facilities cited as FOAK are completed and most are years away from it, with no operational data available to gauge facility eventual costs, reliability and availability. The commenter presented a table to show capital costs associated with the facilities that EPA cites as FOAK, in addition to the Edwardsport IGCC project, and stated that the cost differentials between EPA's presumed NOAK and FOAK and Edwardsport costs are enormous. According to the commenter, based on actual FOAK costs data, EPA methodology presumes the next-of-a-kind unit LCOE would be between 53 to 58 percent of the FOAK unit LCOE, and for the Edwardsport facility, one that EPA describes as a successive IGCC technology application, the next-of-a kind unit LCOE would be 67 percent of the Edwardsport facility LCOE. Based on this analysis, the commenter stated that learning by doing cannot provide significant step changes in cost and performance to make carbon capture more economically viable.
Commenter 10029 stated that several billion dollars have been invested into research and demonstration of CCS and yet it has not been commercially introduced for its intended purpose of mitigating GHG emissions from fossil fuel powered electric generating units (EGU). The commenter cited a  Harvard Belfer Center discussion paper (2009) "Realistic Costs of Carbon Capture" which offers a general range for FOAK plants of $110/t CO2 avoided (with a range of $90- 135/t CO2 avoided) and for NOAK plants costs are expected to be $25-50/t CO2 avoided. According to the commenter, considering that we are likely several decades away from NOAK economies of scale it is prudent to focus on FOAK avoided carbon costs for near term analysis of EGU carbon mitigation.
Commenter 9780 also stated that EPA must correct significant flaws with the LCOE analysis, the largest of which is the use of something less than FOAK costs for a technology that has not been widely developed. The commenter stated that the costs are unreasonable when technology is not yet demonstrated and commercially deployed. According to the commenter, the following important factors appear to be ignored in the NOAK cost projections: (1) CCS projects currently under construction have experienced significant cost overruns, which are not accounted for in the NETL FOAK cost analysis that is the baseline for projecting the nth of a kind costs EPA relies upon; and (2) the analysis does not reflect the cost premiums associated with early plant deployments, which carry significantly higher cost and engineering procurement and construction premiums not reflected in the cost analysis. The commenter discussed additional concerns with the NETL LCOE analysis, such as the exclusion of capital cost contingencies. Additionally, the commenter stated that EPA has not justified why the departure from FOAK costs is warranted at this early state of CCS development. The commenter also noted that there is no reason to believe that substantial new assistance-driven demonstration projects will be undertaken to drive down costs of CCS on EGUs
Commenter 9734 stated EPA's reliance upon levelized cost does not provide an accurate estimate of actual plant costs. According to the commenter, although levelized costs are a convenient summary measure of the overall competitiveness of different generating technologies, actual plant investment decisions are affected by the specific technological and regional characteristics of a project, which involve numerous other considerations not taken into account when projecting levelized costs. The commenter stated that EPA has chosen to ignore the unique cost premiums associated with FOAK plants that must demonstrate emerging technologies and iteratively improve upon plant designs. The commenter then stated that EPA ignores the fact that because the Kemper and Boundary Dam projects are still being developed, it is premature to classify all subsequent plants as NOAK. The commenter provided information on the delays and cost overruns associated with the Kemper project and the AEP Mountaineer Station project. The commenter concluded that when the true cost of these projects including these cost overruns is taken into account (under a FOAK plant approach), it is clear that IGCC/partial CCS is exorbitantly expensive and thus cannot meet the definition of a "standard of performance.
Commenters maintained that the next plants with CCS would be First-of-a-Kind (FOAK), and that costs should be assessed on this basis.  They thus challenged any assumption that costs would be n[th]-of-a-kind (NOAK). However, the EPA notes here (and elsewhere) that, both in the proposal and in the final, the costs for new sources implementing any level of CCS are assumed to represent the "next-of-a-kind" or "next commercial offering", rather than n[th]-of-a-kind (NOAK). For the final cost estimates, the EPA relied on very recent updates to DOE/NETL studies (NETL, June 2015 and July 2015). Those studies stated: "[I]n all cases, the report intends to represent the next commercial offering and relies on vendor cost estimates for component technologies (emphasis added, June 2015, p. 20). Importantly, the most recently updated reports relied on vendor quotes from Shell Cansolv  -  the technology that is currently being used in the Boundary Dam project in Canada. The DOE/NETL studies also "applies process contingencies at the appropriate subsystem levels in an attempt to account for expected but undefined costs, which can be a challenge for emerging technologies." (Ibid, p. 20)
 The EPA understands that actual costs of new generation projects can deviate from the cost estimates provided in the final preamble. However, many of the factors that can lead to cost deviations for new EGUs utilizing partial CCS would also affect the costs for a new EGU that is not including the equipment needed to implement partial CCS. Local labor rates, quality and availability of local water, local seismic conditions, financing arrangements, weather delays, availability and cost of construction materials such as steel and cement, among many other factors, would affect the construction schedule and costs for a new EGU  -  with or without CCS. This is the case for any large construction project  -  or even home construction. The EPA does not suggest that the next constructed IGCC unit would definitely not suffer from the same non-CCS related issues that contributed to the cost overruns and schedule delays at Kemper and Edwardsport. However, the EPA does note that IGCC is not a component of the BSER for the final standard for new steam generating EGUs.  The final BSER is a highly efficient supercritical PC unit implementing partial CCS to meet a standard of 1,400 lb CO2/MWh-g. The AEP John W. Turk facility is an example of a highly efficient supercritical PC. In comments of AEP (p. 76), AEP represented the cost of the Turk facility as $2,885/kW. The DOE/NETL estimates for such a facility is $2,842/kW (NETL, 2015 p. 17  -  for a plant using bituminous coal). This close agreement in cost estimates is another indication of the reliability of the NETL cost projections.
Regarding the comment that billions of dollars have been invested into research and demonstration of CCS and yet it has not been commercially introduced for its intended purpose of mitigating GHG emissions from fossil fuel powered electric generating units (EGU). We note that there are several technology providers that offer "commercially available" carbon capture technology. The companies have brochures (see brochures of MHI, Shell Cansolv, Linde, etc. in the docket), they have websites that promote their products, they sponsor vendor booths at major power sector conferences, etc. As discussed in the preamble, it is often regulatory requirements that promote deployment and advancement of control technologies. The first commercial installations of flue gas desulfurization technology on boilers larger than 100 MW in 1968. The first NSPS for SO2 was promulgated in 1971. By the time of the promulgation of the SO2 NSPS in 1971, only three commercial scrubber units were operating on power plants in the United States. In 1971, only one scrubber vendor was in the utility FGD market.  By the end of the 1970s, sixteen U.S. firms supplied FGD systems to utilities. There was also a large step increase in patent activity in SO2 control technology patents following the 1971 SO2 NSPS. (See the TSD on "History of Flue Gas Desulfurization Use in United States: 1970-1976" available in the rulemaking docket.).
Certain commenters (9472, 1591) maintained that because there are no operating plants at commercial scale with CCS, by definition, the next plant would have to be FOAK.  Boundary Dam Unit #3 is a full-scale commercial SCPC utilizing full post-combustion CCS.  Other plants operating, or soon-to-be operated likewise provide substantial operating experience or other experience which forms a basis for next plants to draw upon.  See preamble section V.D.  The commenters also ignore the substantial public- and private-sector research which will have a positive impact on reducing cost and improving performance of the next CCS plants to be built.  See generally preamble section V.I.2.
 Other commenters (9666, 10618, 9472) maintained that every new plant will be unique, especially with respect to sequestration and also to some extent in choice of capture and compression technology, so that almost by definition, these plants will be FOAK.  EPA's cost estimates for sequestration reasonably rely on the very extensive rulemaking record developed for the Class VI regulation, and this robust record provides cost estimates which are reasonably representative.  See preamble section V.I.5 and N.  Certain sites may be more challenging, and both AEP and other commenters referred to the AEP Mountaineer demonstration project as an example, where siting of a sequestration site proved feasible but expensive due particularly to the number of monitoring wells needed.  This project involved a retrofit to an existing facility (see preamble section V.D.3.b), whereas a new source could making siting decisions which pose less of a challenge.  The Class VI permits issued to date, for example, required many fewer monitoring wells than AEP found to be needed.   There are also compliance pathways to meet the final standard of performance which do not involve sequestration if a source is determined to site at a location which is unsuitable for sequestration.  In addition, the EPA does not accept that each compression and capture technology is so unique as to be a new first-of-a-kind decision with each deployment. Both post- and pre-combustion carbon capture are well established technologies based on recognized processes which are actively marketed.  See preamble section V.F.  For example, Southern Company's Mississippi Power has stated that, because the Selexol(TM) process has been used in industry for decades, the technical risk of its use at the Kemper IGCC facility is minimized noting that "The carbon capture equipment and processes proposed in this project have been in commercial use in the chemical industry for decades and pose little technology risk."
 Commenter 10618 criticized EPA for basing decisions on what it characterized as dated vendor reports.  The EPA does not accept the characterization, but has made every effort to obtain the most up-to-date information on cost, in part in response to this and similar comments.  In particular, cost estimates for post-combustion CCS reflect cost information from recent vendor quotes of the Shell Cansolv post-combustion capture process  -  the process that is currently being utilized at the Boundary Dam #3 facility.  The EPA has also carefully monitored the most recent marketing materials and estimates, which, as explained in preamble section V.I.2.c, are corroborative of the NETL cost estimates.
 A number of commenters (e.g. 9780, 9374) stressed that actual projects have had huge cost overruns, and that these plants should form the basis for cost estimates, not projected, hypothetical plants as reflected in the NETL estimates. Some commenters (e.g. 9666) maintained that IGCC costs were especially speculative. The EPA has carefully considered this issue.  Kemper, an oft-cited example in the comments, had cost-overruns not related to CCS (per the report to the Mississippi Public Utility Commission cited in an earlier comment response in this unit).  AEP involved a retrofit to an existing facility, which occasioned costs (especially related to siting of monitoring wells) that a new source could avoid at the outset.  Boundary Dam ultimately came in on budget for the capture portion of the project, and has predicted publically that costs of a next plant would be 30% less.  See also preamble section V.I.3.
 Commenter 10952 states that there is no information in the record supporting an assumption that next plants to be built would have NOAK costs.  This is mistaken. SaskPower Executive Michael Monea has stated publically that the next post-combustion CCS plant using Shell Cansolv compression and capture process can expect to see at least a 30% reduction in cost, as just noted. EPA's cost estimates for post-combustion partial CCS are based on recent vendor quotes for this Cansolv process. More generally, these comments assume that learning by doing, with consequent reduction in costs, simply does not apply here.  The EPA disagrees.  The NETL assumption of NOAK is not unique.  Technology vendors are currently providing cost estimates in the marketplace which not only have the same premise  -  that costs for next plants will be less than those of the FOAK plants  -  but are lower than the NETL estimates. See preamble section V.I.2.c.  The NETL estimates are also consistent with techno-economic models of other established entities, meaning, again, that these other entities likewise are using NOAK cost estimates.  See id. section V.I.2.b.
 Commenters 9780 and 9666 state that the NETL estimates do not account for capital cost contingencies, which are typical for FOAK plants.  The commenter is mistaken.  The NETL estimates used for the final rule use high-risk financial assumptions for all CCS cost estimates.  NETL 2015 at p. 18.
 Finally, a number of commenters cite to statements of various non-industry entities for the proposition that CCS will be unavailable until such dates as 2020.  These quotations had a different context, referring to full CCS, or to CCS retrofits.  See generally preamble section V.G.3.
Commenter 10108 stated that EPA's determination that the costs of CCS are reasonable is supported by current experience as well as expected future costs. The commenter stated that the CCS component of SaskPower's Boundary Dam project, scheduled to come online later this year, is actually 6% under budget. The commenter also stated that SaskPower recently stated that by 2016 other units at the Boundary Dam facility could be repowered with CCS without government subsidy, and it estimates that the cost of its next carbon capture project will be 20-30% lower than Boundary Dam. According to the commenter, this leading case study offers a promising perspective on the present and future costs of CCS, and corroborates EPA's conclusion that "next-of-a-kind" CCS facilities, like many other emission control and energy technologies in the past, will experience reductions in cost over time.
The EPA agrees that the Boundary Dam experience is indicative that cost of next plants will reflect present operating experience and be substantially less as a result.  The EPA's information, obtained from the project developer, likewise is that the CCS portion of the project came in at budget. Boundary Dam Unit 3 (BD3) was recently awarded POWER Magazine's "Plant of the Year" award. (http://www.powermag.com/saskpowers-boundary-dam-carbon-capture-project-wins-powers-highest-award/). In recognizing the Boundary Dam Unit 3 plant, POWER noted that "the SaskPower team has taken what actually constitutes a giant leap for the coal-fired power industry". In the article SaskPower notes that this first-of-its-kind carbon capture plant was finished on budget; challenges associated with the existing power plant were the cause of cost overruns. They also noted that the performance far exceeds the expectations at the project's inception.
Commenter 10098 stated that the proposed rule's levelized cost of electricity (LCOE) figures are arbitrary and capricious. According to the commenter, EPA's estimates incorporate a number of errors, including a lack of foundation for its CCS cost estimates, a lack of real-world construction and operations data and improper assumptions that artificially reduced EPA's cost estimates and ignore the higher costs associated with a first-of-a-kind technology. The commenter referenced the source relied upon by EPA in their claim that "partial" CCS, with an emission rate of 1,100 lb CO2/MWh, will only add $18 to the cost of electricity for a pulverized coal boiler and noted that the only study relied upon by EPA that even speaks to the costs of "partial" CCS shows that cost of electricity will increase by twice as much as the proposed rule's estimate. Therefore the commenter stated that EPA's $18/MWh cost estimate is arbitrary and capricious because it not only lacks support, but is clearly contradicted by the administrative record.
Commenter 10039 stated that US EPA's reliance on US DOE/NETL "Cost and Performance" reports as a basis to justify partial CCS costs as reasonable is misplaced and inappropriate.  According to the commenter, US DOE estimates of levelized costs of electricity (LCOE) which are used to establish the reasonableness of CCS technology costs make several assumptions for the purposes of their calculations which skew the analysis by identifying the low end of the costs of CCS. The commenter stated that US DOE estimates of LCOE are not universally applicable as they are not derived based on national averages or even realistic scenarios, and they also do not address realistic costs for permitting, insurance, construction, and easement costs of CO2 pipelines and storage areas because it makes assumptions about locally available storage areas and the sharing of that storage capacity that unrealistically result in significant underestimation of the cost of a CO2 storage site on a $/tonne of CO2 stored perspective. The commenter stated that the US DOE report utilizes the least cost storage location option of the four to assess LCOE estimates despite the fact that two of the four locations have significantly higher costs. According to the commenter, picking the lowest cost location is arbitrary and capricious as it has no basis in actual EGU siting criteria and does not represent a national average. Therefore the commenter suggested US EPA abandon the US DOE CCS cost analyses as they are arbitrary and biased estimates of the cost of CCS.
Commenter 10952 stated concern with the use of DOE funded demonstration projects in determining the LCOE estimates to reach its BSER conclusion, and questions EPA's focus on NOAK costs provided in Table 6 of the proposal. The commenter stated that according to the DOE studies of which EPA relies, the margin of error of the derived LCOE data ranges from -15 to +30 percent, and this wide margin of error makes any chosen LCOE costs within this wide range arbitrary. The commenter noted that for Table 6 costs, EPA has chosen the midpoint from the data extrapolated from these studies for its LCOE predictions, but even at that midpoint level the LCOE for SCPC EGU with partial carbon capture is 20 percent above a SCPC EGU without carbon capture, and this increase is well above any level determined to be judicially permissible, as EPA recognizes in Portland Cement 486 F.2d. 387, where only a 12 percent capital cost increase was a level considered permissible. The commenter also noted that if the actual LCOE for SCPC with partial capture is 30 percent above the LCOE midrange prediction, again a LCOE within the stated margin of error, the resulting partial carbon capture cost would increase the SCPC facility by 24 percent. The commenter also noted that the Table 6 LCOE data, and the proposal overall, do not factor in CO2 transport and sequestration costs where EOR is not available.
Commenter 10952 references a study which concludes that EPA misused the DOE studies to derive CCS cost estimates, and that the DOE studies were intended to be used to derive preliminary estimates of feasibility and costs and were never meant to determine actual costs to be used as a basis in a national rulemaking that will dictate the nation's future energy policy. The commenter also stated the DOE reports upon which EPA relies were not peer reviewed and underlying assumptions were not made available for comment in connection with this rulemaking. According to the commenter, these DOE studies were intended to be used to derive preliminary estimates of feasibility and costs and were never meant to determine actual costs to be used as a basis in a national rulemaking that will dictate the nation's future energy policy.
Commenter 9678 stated that they do not agree with EPA's reliance on LCOE estimates in evaluating the cost-effectiveness of its proposed emission limits and BSER determinations. According to the commenter, LCOE provides a useful metric in many contexts, but not for purposes of determining BSER. The commenter stated LCOE is an economic tool designed not to discern the costs of various alternative levels of BSER, but rather to evaluate the competitiveness of a technology in the broadest possible terms. The commenter stated that the use of LCOE in this rulemaking also departs from past Agency practice, as in previous CAA section 111 rulemakings, EPA considered both the overall costs involved per year and the cost-effectiveness of a CAA section 111 standard in terms of cost-per-ton of air pollutant removed.
Commenter 9666 stated that the problem with the use of the LCOE metric is that it averages the cost of generation over the lifespan of the generating unit and fails to account properly for significant differences in upfront capital and related financing costs, which are typically much higher for coal-fired units, especially with the integration of CCS, than for NGCC facilities. According to the commenter, because corporate decisions on generating technologies will be driven in large part not only by a LCOE metric but by upfront financing and capital constraints, EPA erred by not factoring these considerations into its cost analysis.
Commenter 9197 stated that based on DOE estimates, the projected cost of electricity from new coal-fired facilities with CCS is likely to be far higher than that of most other alternative baseload technologies. According to the commenter, the need to overbuild/oversize systems in order to comply with the NSPS in the context of a 24-hour duty cycle and the need to rely on third party CO2 pipeline and sequestration service providers will increase cost estimates. The commenter referenced EPA LCOE estimates and DOE EIA estimates for LCOE.
Commenter 7977 referenced a 2013 State of Kentucky Energy and Environment Cabinet analysis which concluded the levelized cost of electricity (LCOE) with CCS technology is higher than the LCOE without CCS. According to the analysis, estimates indicate that the addition of CCS to either an IGCC or USCPC facility would increase cost per kWh by 40 percent to 58 percent respectively.
Commenter 10095 stated that NETL document used as the source for CCS cost assumptions highlights the changing landscape of CCS costs and the need for multiple cost reference points. The commenter stated that EPA did not analyze the full range of the cost estimate in setting a nationwide BSER and performance standard applicable to all new coal-fired generation, noting the -15 to +30 percent accuracy of the NETL report. The commenter stated that while EPA estimates the capital cost would increase by 35 percent for SCPC to incorporate partial CCS, no previous EPA NSPS proposal has increased the cost of constructing a new affected facility by 35 percent. The commenter presented their own analysis, in which they conclude that EPA potentially underestimated the average costs of partial CCS by 23 percent for SCPC. The commenter stated that EPA's LCOE analysis is flawed as it is based on one source and does not consider the full range of cost estimates. Using the upper range of NETL cost estimates, the commenter argued that generation technologies with partial CCS may be costlier than other new non-fossil, low emitting baseload generation technologies such as nuclear.
Commenter 10239 stated the EPA's attempt to justify the proposed standard by comparing the levelized cost of electricity from new coal-fired power plants with and without CCS is arbitrary, capricious, and unlawful. According to the commenter, because of the serious defects in the EPA's levelized cost analysis, the Agency has no basis for using the analysis to justify the proposed rule. The commenter provided cost information from the 2011 NETL study in which partial capture would increase costs by 43.3% and stated that the only evidence from NETL suggests that the costs of partial CCS would be more than twice as high as the EPA's estimate of $18/MWh. In the absence of any supporting evidence to contradict the NETL study, the commenter stated that EPA's cost estimate for partial CCS is arbitrary and capricious. Commenter 10239 also stated the EPA lacks any real-world data on which to base its cost estimates as there are no commercial-scale coal-fired EGUs employing CCS anywhere in the world. As a result, the commenter argued EPA has no factual basis for projecting levelized cost of electricity estimates. According to the commenter, it would be arbitrary and capricious to rely on estimates generated from facilities currently under construction because of the well-documented cost overruns occurring at virtually all of those facilities. According to the commenter, EPA's decision to propose partial CCS creates even more cost-estimate challenges, as the facilities under construction intend to capture higher proportions of CO2. The commenter also stated the EPA offers no rational basis for reversing its prior conclusions in the GHG Guidance and in comments on PSD permitting decisions that CCS is prohibitively expensive, citing "At present CCS is an expensive technology, largely because of the costs associated with CO2 capture and compression, and these costs will generally make the price of electricity from power plants with CCS uncompetitive compared to electricity from plants with other GHG controls."
Commenters challenged EPA's use of both the LCOE metric at all, and certain of the data used to generate the LCOE estimates.  Many of these comments are addressed in preamble section V.I.1.  In response to comments indicating that capital costs are of special import for SCPC, and more so than for other types of units (e.g. 9666), EPA has in fact evaluated capital costs associated with the final standard as a separate metric, found them to be comparable to those experienced (successfully) by this industry for other NSPS, and reasonable. See preamble section V.H.4.
 With regard to use of NETL studies to generate data used in the LCOE comparison, commenter 10095 said mistakenly that these estimates do not include transport and sequestration costs for a non-EOR case.  The commenter's error is explained in preamble section V.I.5.
 The EPA also carefully reviewed the assumptions on which the transport and storage cost estimates are based and continues to find them reasonable. The RIA presents an illustrative analysis using NETL estimates as demonstrative of the range of costs which, as the commenter points out, may vary by region. For transport, costs reflect pipeline capital costs, related capital expenditures, and O&M costs. Pipeline costs used in the NETL studies upon which the EPA analysis was based were comparable to costs quoted by industry experts. See Carbon Dioxide Transport and Storage Costs in NETL Studies (DOE/NETL-2013/1614), p. 16. Sequestration cost estimates reflect the cost of site screening and evaluation, the cost of injection wells, the cost of injection equipment, operation and maintenance costs, pore volume acquisition expense, and long term liability protection. These sequestration costs reflect the regulatory requirements of the Underground Injection Control Class VI program and GHGRP subpart RR for geologic sequestration of CO2 in deep saline formations. In the cost estimates, each formation in each basin has a maximum theoretical capacity to store CO2 and this capacity significantly exceeds the mass of CO2 being stored by a single project. Therefore it is reasonable to assume that multiple storage projects could be implemented in a formation. In fact, the sequestration costs conservatively assume storage in a formation until the total mass of CO2 injected from all projects approaches 40 percent of the theoretical storage capacity. See Carbon Dioxide Transport ant Storage Costs in NETL Studies, p. 19. The transport and storage costs provide a conservative estimate of storage costs and are consistent with cases modeled in the NETL report.
 Another erroneous comment (10952) maintained that the NETL studies are not peer reviewed.  The initial NETL study "Cost and Performance Baseline for Fossil Energy Plants, Vol. 1: Bituminous Coal and Natural Gas to Electricity" (2006) was subject to peer review by industry experts, academia, and government research and regulatory agencies. Subsequent iterations of the study were not further peer reviewed because the modeling procedures used in the cost estimation were not revised.  The SAB determined here that this peer review was adequate under both DOE and EPA peer review guidance.  See chapter 2 RTC dealing with comments referencing the Information Quality Act.
 Other commenters noted that the NETL studies present costs as a range, and urged the EPA not to use point estimates for these figures.  EPA agrees with these comments, and is using the range of cost estimates presented in its assessment of costs.  See, e.g., Table 8 to the preamble to the final rule.  In this regard, the EPA notes that costs for nuclear power are also presented as a range.  This approach is consistent with expert advice to EPA from the EIA, and with the methodology used by leading techno-economic modelers in the field, notably Lazard Global Power and the Global CCS Institute.  The nuclear LCOE estimates of these various entities are likewise relatively consistent.  See preamble sections V.H.5 and I.2.b.
 Commenter 10095 stated that, at the least, NETL should not be used as the exclusive basis for generating cost information for LCOE comparisons.  The EPA has, in fact, looked to other techno-economic models and current vendor marketing and cost information, and finds these other sources of information to be corroborative of NETL estimates (and, in notable instances, to provide lower cost estimates than those of the NETL studies  -  although the EPA LCOE estimates continue to be based on the NETL results).  See preamble section V.I.2.and 3.
Commenters 10098 and 10239 referenced the source relied upon by EPA in their claim that "partial" CCS, with an emission rate of 1,100 lb CO2/MWh, will only add $18 to the cost of electricity for a pulverized coal boiler and noted that the only study relied upon by EPA that even speaks to the costs of "partial" CCS shows that cost of electricity will increase by twice as much as the proposed rule's estimate. However, the EPA notes that the commenter calculated the change in LCOE to meet an emission rate of 1,055 lb CO2/MWh on a net basis ... not for an emission rate of 1,100 lb CO2/MWh on a gross basis as proposed by the EPA (and adopted as the form of the final standard of performance). In any case, for the final rule, the EPA relied on updated cost estimates by the DOE/NETL that were based on recent, up-to-date vendor quotes. This new information predicts that the final standard will result in an increase of the levelized cost of electricity (LCOE) at the compliant plant of $16.8/MWh.
 Commenter 10239 states that no real world operating experience is reflected in the NETL estimates making their use arbitrary.  The same commenter indicates that estimates should not be based on units under construction.  The cost estimates used by the EPA for post-combustion partial CCS reflect the most recent vendor quotes for the CanSolv process that is in current operating use at the commercial-scale full CCS Boundary Dam #3 facility.
Commenter 7977 referenced a 2013 State of Kentucky Energy and Environment Cabinet analysis which concluded the levelized cost of electricity (LCOE) with CCS technology is higher than the LCOE without CCS. The EPA agrees with that conclusion (see Table 8 in the final rule preamble). The commenter references a report that concludes that "the addition of CCS to either an IGCC or USCPC facility would increase cost per kWh by 40 percent to 58 percent respectively". The EPA notes that those studies assume "full CCS" (i.e., capture and storage of 90% or more of the CO2 from the facility).  The EPA did not find "full CCS" to be a component of the BSER as the projected costs exceed the projected costs of other non-NGCC, base load generating options.
Commenter 10098 stated that as there are no existing commercial-scale coal-fired EGUs utilizing CCS, the actual construction and operating costs of CCS for a commercial-scale power plant will not be understood until coal-fired EGUs actually finish construction and operate. According to the commenter, by failing to present a range of potential costs that include the cost overruns that can be expected with a first-of-a-kind technology, EPA provides an illusion of artificial certainty in its $18/MWh estimate. The commenter stated that the accuracy of this number cannot be defended, for lack of any real-world data, and EPA should acknowledge this.
Commenter 9666 stated that the problem with using the LCOE metric is that it averages the cost of generation over the lifespan of a generating unit and fails to account properly for significant differences in upfront capital and related financing costs, which are typically much higher for coal-fired units, especially with the integration of CCS, than for NGCC facilities. According to the commenter, because corporate decisions on generating technologies will be driven in large part not only by a LCOE metric but by upfront financing and capital constraints, EPA erred by not factoring these considerations into its cost analysis. For these reasons, the commenter noted that EPA's cost analysis is in error and inadequate.
Boundary Dam #3 is a commercial operating facility utilizing full CCS.  The cost estimates used for the LCOE analysis for post-combustion CCS is based on recent vendor quotes of the Shell Cansolv post-combustion capture process  -  the process that is currently being utilized at the Boundary Dam #3 facility.  The EPA has also carefully monitored the most recent marketing materials and estimates, which, as explained in preamble section V.I.2.c, is corroborative of the NETL cost estimates.
 EPA regards the LCOE metric as a highly reasonable, and widely utilized metric that takes into account all costs to construct and operate a new power plant over an assumed time period and an assumed capacity factor. Levelized costs are often used to compare the cost of different potential generating sources.  However, in response to this comment (from commenter 9666) and similar comments, EPA also explicitly considered capital costs alone.  See preamble section V.H.4 explaining why the EPA finds potential capital cost increases reasonable on a per-plant basis.
Commenter 9664 stated that EPA's standard does not produce unreasonable levelized cost of electricity impacts. While the levelized cost of electricity (LCOE) for new coal-fired generation that includes partial CCS is more than constructing coal plants without CCS, or new natural gas-fired generation, the commenter noted that it is competitive with new construction of other low-carbon electricity generating power plants, including nuclear, the principal other option considered for baseload electricity generation. The commenter cited several court decisions that the impact of a standard on the LCOE is a factor that EPA can consider in evaluating a standard's cost, consistent with the D.C. Circuit's precedent.
 The EPA largely agrees with this comment.
Commenter 9321 stated that for coal refuse designed EGUs with CFB boilers, it is not economically feasible to incorporate identified efficiency technologies. According to the commenter, it is not practical to establish an aggressive greenhouse gas emission rate for coal refuse designed EGU's as the economics will inhibit the development of these projects and this same economic issue will also surface if the application of efficiency improvements to existing coal refuse fired EGUs is required. The commenter stated that the required use of CCS would also be cost prohibitive and would discourage the development of plants to remove the coal refuse piles and this same economic issue will also surface if the application of CCS to existing coal refuse fired EGUs are required.
See preamble section III.E.
Commenter 9664 stated that EPA's standard meets the D.C. Circuit's test - they are not "exorbitant" when evaluated in terms of the resulting cost of electricity, or as compared with the social cost of carbon.
Commenter 9514 EPA stated that 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. According to the commenter, while Section 111 does not require strict cost-benefit balancing, it allows EPA to consider costs broadly, including consideration of the pollution reductions described above, as well as the social cost of carbon and co-benefits. The commenter stated that these considerations provide further support for the conclusion that a partial CCS standard will not impose exorbitant cost, in satisfaction of section 111's standards
 The EPA largely agrees with these comments.
Commenters 10098 and 10239 disagreed with the use of social cost of carbon to reduce the cost of "partial" CCS by 5% per the Social Cost of Carbon document developed by OMB. Commenter 10098 stated that any reliance on this deeply flawed policy is arbitrary and capricious, as the document is completely unreviewable for reasonableness or accuracy due to OMB's "black box" approach. The commenter provided additional information on social cost of carbon estimates. Commenter 10239 also stated that the social cost of carbon analysis has numerous flaws and should not be utilized in projecting the LCOE.
First, the chief metrics used to show that costs of the rule are reasonable are projected LCOE and projected capital cost increases.  The Social Cost of Carbon (SC-CO2) does not enter into any of these comparisons. Second, the (SC-CO2) is not a policy, it is an estimate of the net economic damages resulting from CO2 emissions, and therefore is used to estimate the benefit of reducing those emissions. Third, EPA strongly disagrees that the (SC-CO2) technical support documentation ("SC-CO2 TSDs) is "unreviewable for reasonableness or accuracy."  To the contrary, the SC-CO2 TSDs are comprehensive and technically rigorous in explaining the sources of data, the assumptions employed, the analytic methods applied, and the statistical assumptions employed.  Terming this a `black-box' process is a significant mischaracterization.  Indeed, to ensure that the results are reproducible, EPA has provided technical assistance and modeling results to external stakeholders upon request. EPA also notes that opportunities for public comment have been provided on all aspects of the SC-CO2 estimates, including prior rulemakings dating back to 2009 that made use of the estimates. As a general practice, EPA requests comments on all aspects of the regulatory impact analysis, thereby providing ample opportunity for the public to comment on SC-CO2 estimates used in these analyses. In addition, OMB provided a stand-alone comment period on the 2013 estimates.  For additional responses to comments regarding the transparency of the SC-CO2 estimates and their consistency with federal guidance, such as OMB Circular A-4, see Response to Comments Section 4, Comment 4.5-5
Commenter 10098 stated that in the RIA, EPA improperly reduced the cost of "partial" CCS by 38% through a series of assumptions that are not only unsupported but contradicted by EPA's own GHG BACT determinations regarding CCS. The commenter cited the EPA estimate of $29/MWh for the cost of partial CCS, noting that the origin of this estimate is not explained in the RIA, making the entire exercise arbitrary and capricious.
The EPA's estimates for the cost of partial post-combustion CCS reflect cost information from recent vendor quotes of the Shell Cansolv post-combustion capture process  -  the process that is currently being utilized at the Boundary Dam #3 facility.  The EPA has also carefully monitored the most recent marketing materials and estimates, which, as explained in preamble section V.I.2.c, is corroborative of the NETL cost estimates. The EPA does not believe that utilizing this recent, well-documented, and corroborated information on cost to be arbitrary and capricious.
Commenters 10098 and 10239 stated that EPA's cost estimates are arbitrary and capricious because EPA deducts 3% of the costs based on flawed assumptions that "partial" CCS will reduce emissions of other pollutants as a co-benefit without further explanation of this claim. The commenters countered that CCS would actually increase emissions of conventional pollutants, referencing a 2011 NETL study and PSD permit determinations.
As shown in Chapter 5 of the RIA, under assumptions where new non-compliant coal capacity is added, use of partial CCS results in significant reductions of criteria pollutants, in particular, SO2.
Commenter 8954 and 9472 discussed high costs associated with CCS. Commenter 8954 noted the EIA cost estimates to build a new IGCC coal plant with CCS of $6,599 per kilowatt is more than six times the price of a new NGCC unit without CCD and more expensive than hydro, solar, onshore wind and nuclear options. As a result, the commenter concluded that the proposed standard for coal is far too expensive for anyone to consider building a new coal plant. Commenter 9472 stated CCS is exorbitantly costly and EPA has significantly underestimated the cost of CCS by misinterpreting DOE cost estimates and has failed to recognize the first-of-a-kind nature of CCS costs. The commenter estimated the addition of CCS to a single new coal-fueled electric generating unit costs in the range of $1 billion.
Commenter 9401 referenced EIA data that adding CCS to a new power plant can cost up to $1 billion and increase its capital cost by 60 percent. The commenter also stated that the Administration's CCS task force reported that CCS would add $400 million (IGCC) to $900 million (pulverized coal) to the cost of a typical coal plant, increasing the capital cost of the plant by 25 percent and 80 percent, respectively.
Commenter 10243 stated costs to install CCS on a new coal-fired power plant are prohibitively high, and CCS projects in the U.S. are viable only as a result of government assistance.
Commenter 9780 stated the costs of partial CCS are not reasonable and partial CCS is too expensive to be BSER. Commenter 10050 also stated CCS costs are exorbitant and unreasonable.
Commenter 10043 noted deficiencies with the exorbitant costs of CCS and the insufficient cost analysis conducted by the EPA regarding the effects of the Proposed Rule.
Commenter 9194 stated, as demonstrated in the NETL studies employed by EPA, CCS technology is resource intensive and overly expensive for use with utility-size EGUs.
Commenter 1959 stated costs should be considered, and the additional costs associated with CO2 capture are very large unacceptable and would roughly double the cost vs. a PC plant without CCS.
Commenter 8966 stated Implementation of partial CCS is exorbitantly costly in both economic and environmental ways. 1. Pre-CCS planning and design costs are significant even before factoring CCS system expenses. 2. In addition to special planning and design costs, the cost of a CCS system itself is immense. 3. CCS implementation raises a host of safety, liability, and other practical issues that EPA failed to take into account. According to the commenter, these are issues that must be resolved as a prerequisite to wide deployment and use of the technology. Their importance cannot be marginalized by EPA.
Commenter 10662 stated EPA's proposal constitutes a significant energy action with great adverse effects and fails to consider the increase in construction, operation, and energy penalty costs associated with CCS technology. The commenter noted the potential for increased electricity costs, the reliance on subsidies, the need for additional research, the lack of commercial scale applications, and the parasitic load.
 A number of commenters (e.g. 8954, 9401) stated that adding CCS to coal-fired plants is exorbitantly costly and can add costs of up to $1 billion.  Commenter 9401 cites in support that Administration's CCS Task Force.  The Task Force report addressed full CCS, not partial CCS.
The EPA is not selecting full CCS as BSER for reasons of cost.  See preamble section V.P.  However, as shown in preamble Table 8 and discussion underlying that table, cost of partial post-combustion CCS compares reasonably to that of other non-NGCC baseload dispatchable technologies.  See also Global CCS Institute, "The Costs of CCS and Other Low-Carbon Technologies" (2015) stating that "CCS is a cost competitive power sector emissions reduction tool when considered among the range of available low and zero emissions technologies" (p.1);   statement of Alstom Vice President  Macnaughton endorsing "findings from a recently-conducted cost analysis showing that the cost of electricity generated by coal and natural gas plants equipped with CCS is competitive with other low or no-carbon energy carbon energy sources, such as wind, solar, geothermal, hydro and nuclear".
 In response to commenter 1959 and 9401, the EPA has carefully considered capital costs as part of its consideration of cost.  See preamble section V.H.4.  The commenters, again, are basing their figures on the capital costs associated with full CCS, and therefore are much higher than those associated with the standard in the final rule, which the EPA has evaluated and found to be reasonable, in particular because they are in the same range as capital costs for this industry in earlier NSPS, which costs were found to be reasonable both by EPA and by reviewing courts.
 Comments that the EPA is ignoring (unspecified) issues of safety and liability associated with partial CCS are misplaced.  Costs reflect a carefully documented item-by-item assessment of equipment and construction needs.  Issues of liability of sequestration sites are addressed, to the extent of EPA authority, in the Class VI well standards, in particular the closure and post-closure provisions.  See preamble section V.N.
 The EPA has also carefully considered the issue of parasitic load (termed `energy penalty' by commenter 10062) and found those impacts to be reasonable.  See preamble section V.O.3.  See also the following response.
Commenters 7433, 9593 and10017 stated that EPA also overlooks the substantial energy penalty that CCS systems would impose on the generating capacity of an individual facility. Commenter 7433 stated when CO2 capture and storage is compared to other technical options for reducing CO2 emissions, 10-40% more energy is needed for producing the same amount of electricity; therefore, it is expected that CCS would raise the cost of producing electricity by about 20 to 50%.
The EPA has carefully analyzed the issue of parasitic load.  The actual figures are considerably less than the commenters posit, and EPA has found the energy requirements of the rule, including consideration of energy requirements related to parasitic load, are reasonable.  See preamble section V.O.3.
Commenter 9381 stated CCS as EPA envisions it for use at power plants has not been adequately demonstrated and its current costs are wholly disproportionate to the costs of a conventional power plant and are currently prohibitive. The commenter stated that electricity generated from coal with CCS is almost 50 percent more expensive than energy generated from conventional coal. According to the commenter, it is estimated that CCS technology would add between approximately $800 million to $1 billion to the cost of a coal-fired EGU and would use as much as 30 percent of the electricity generated from the plant for CCS operation as parasitic load.  With costs of this magnitude, the commenter noted it is highly doubtful that any merchant power companies or regulated electric utilities will invest in a new coal-fired power plant with CCS, nor will they be able to obtain financing. This could impact reliability and prevent states from diversifying their energy portfolios.  Moreover, the commenter stated, CCS technology will not be deployed, refined or improved so as to make it technologically or economically viable.
The commenter (Nextera Energy) cites in support a 2012 article titled The Twilight of Coal-Fired Power (May 1, 2012).  Comment p. 3 n.2. That article was addressing the now-withdrawn 2012 proposal of EPA, and the costs cited again appear to reflect full CCS (and certainly do not reflect the costs of the standard based on performance of partial-CCS adopted in this final rule).  See The Twilight of Coal-Fired Power at p. 11 and Fig. 7.
Commenters 8179, 8200, 8206, 8231, 8242, 9190, 9590, 9725. 10050, 10552, and 10680 disagreed with EPA's assumption that the costs for CCS will decrease with the next plants constructed, as the commenters stated that actual experience in development of control technologies shows that second generation technologies will cost more as new risks are identified in performance and reliability. The commenters referenced comments by the Duke Power CEO that CCS is "too expensive" to consider adding to its recently commissioned Edwardsport IGCC plant, and noted that the Kemper County Energy Facility has experienced cost overruns of over 100 percent since 2010 and remains uncompleted.
Commenter 9666 stated that because CCS has never been applied as an integrated system at EGUs on a commercial scale, experience from the first generation of CCS systems at units like Kemper County and Boundary Dam is likely to reveal performance and reliability issues that may require costly additional measures to address.
Commenter 10952 stated that because the projects, Kemper, TCEP, and HECA, of which EPA relies, are not in operation, the ultimate costs of employing carbon capture on an EGU are unknown. The commenter stated that EPA has not and cannot explain this dramatic departure from its earlier rulemaking, or from the technology development timelines and milestones developed by this administration and described in the Task Force report, especially with input from DOE whose knowledge and expertise in these areas of technology development dwarfs EPA's, to conclude carbon capture is adequately demonstrated.
Commenter 9396 stated that due to the excessive cost-increase of CCS demonstration projects, particularly the Kemper project, EPA should use a very substantial cost uncertainty when evaluating project costs that include CCS. The commenter also stated that the cost estimates for the Kemper facility are outdated and understate the cost of the facility.
Commenters 9666 and 10395 stated that because the projects that EPA relies on (Kemper, TCEP, HECA) are not in operation, the ultimate costs of employing carbon capture on an EGU are unknown.
Commenter 2471 stated that EPA references the Kemper, Boundary Dam, TCEP and HECA projects, however each of these projects are oil and gas recovery projects and EPA does not consider the risks and costs to inject CO2 in locations with little or no oil and gas recovery opportunities.
Commenter 7977 referenced the Edwardsport and Kemper projects, noting that the actual costs accrued were much higher than the original cost estimates.
Commenter 8925 stated that FOAK costs have been significantly underestimated and provided additional background information on the Kemper and Boundary Dam projects.  For the Kemper project, the commenter stated that based on the current estimate, it will cost $9,922/kW which is considerably more than those estimated in the DOE/NETL "baseline" studies cited in the EPA proposal. The commenter referenced the DOE/NETL 2011 report titled "Cost and Performance of PC and IGCC Plants for a Range of Carbon Dioxide Capture" which cites an IGCC with 60% CO2 capture having a "total overnight cost" of $3,024/kW. Total overnight costs do not include so called "owner's costs" or costs outside of the plant boundary limits such as transmission lines and fuel delivery systems.  According to the commenter, if those costs are removed from the Kemper estimate, and the $245.3 million DOE subsidy is also removed, the equivalent "total overnight cost" of the Kemper would be $3.768 billion or $7,190/kW -- over twice the DOE/NETL baseline estimate.
Commenter 8925 provided background information on the SaskPower Boundary Dam project. According to the commenter, the anticipated total cost of the Boundary Dam project was $1.24 billion (CDN).  SaskPower has received a $240 million (CDN) subsidy from the Canadian federal government to support the project.  According to the commenter, project overruns were reported in October 2013 and the total projected cost now stands at $1.36 billion (CDN) for the 110 MW unit.
Commenter 9497 stated that in approving the Kemper project, the Mississippi Public Service Commission (MPSC) explicitly recognized and guarded against the cost escalation being experienced at Kemper. As a result of the construction cost cap imposed by the MPSC, the company has written off over $1.5 billion. According to the commenter, this protective shifting of risk is unlikely to appeal to a broad range of utilities or be practical for the broader implementation of partial CCS technology in its current state.
Commenter 9497 noted that the actual cost of the Kemper facility is greater than the cost assumed in EPA's RIA for an IGCC with CCS.  The commenter calculated that the $4.6 billion plant cost translates to $7,846 per kW, more than double the cost assumed by EPA for an IGCC with partial CCS, noting that the calculated cost per kW for Kemper is conservative because it excludes the CO2 pipeline cost, which is likely to be a necessary component of any IGCC with CCS. The commenter stated that EPA's use of a cost assumption for IGCC with CCS that is at odds with both EIA's cost estimates and the actual cost of Kemper deems the RIA unreliable.
Commenter 9497 stated that the MPSC experience with the Kemper project demonstrates that the projected cost of a project with CCS technology can drastically change during deployment. The commenter suggested that in four years, the costs of this technology will be more knowable and the capture efficiency will be better understood.
Commenter 9497 provided additional information on the Kemper project, including a discussion on the imposition of a cap on construction costs, beyond which incurred costs could not be recovered from ratepayers.  The commenter stated that MPSC imposed performance standards and expectations on Kemper that shift risk to the utility. The commenter stated their belief that most other state commissions would likely insist on similar protections and that these requirements are unlikely to promote broader implementation of partial CCS technology across a wider range of utilities.
Commenter 9723 stated since the CCS projects, including Kemper, Boundary Dam and HECA, have required funding through governmental programs, it is clear there is more time needed to develop economic CCS technologies before it would be considered BSER.
Commenter 9773 stated that the four facilities that EPA references are under construction, or proposing to construct, are receiving government financial assistance to be viable and are not using commercially available CCS technology. The commenter provides information on the subsidies for Boundary Dam, Kemper, TCEP and HECA. According to the commenter, this required level of public funding to support these named projects does not support EPA's position that partial capture CCS meets the cost criteria to be BSER. The commenter also stated that incentivizing developers to install CCS via public grants and tax incentives of this magnitude is not sustainable when applied on the national scale required to power the nation's future industrial, commercial and residential demand.Commenter 10095 referenced the Kemper, TECP, and HECA projects, noting that since all of these projected receive federal funding, none can be said to be independently accommodating the cost of CCS.  The commenter also stated that two of these projects do not have power purchase agreements.
Commenter 9666 stated that EPA's assumption that a control technology's costs necessarily decrease with implementation experience is fundamentally flawed. In practice, experience with developing control technologies often reveals new risks that increase costs or compromise the system's performance. The commenter referenced EPA's suggestion that Kemper and Boundary Dam are FOAK projects and that future NOAK projects will have lower costs.
Commenter 9780 referenced the cancellation of AEP Mountaineer pilot project due to cost estimates increasing drastically. The commenter stated that the existence of plans that will never be put into action provides no additional support to the CCS BSER determination.
Commenter 8024 stated the recent cancellation of the Wolverine Power 600 MW coal-based power plant provides another example of the uneconomic nature of CCS applied to a conventional power project. The commenter provides extensive information regarding the BACT analysis for the permit application, noting that the subsequent engineering cost analysis of the application of CCS to the project concluded that CCS was not economic, and should not be pursued even with government support. According to the commenter, there are similar cases of BACT reviews evaluating and rejecting CCS on economic grounds, such as the proposed Taylorsville coal gasification facility in Illinois. The commenter noted that project - subsequently cancelled - offered the opportunity to capture a pure stream of CO2 from the gasification process, without the need for costly post-combustion capture technologies, and Illinois EPA rejected the application of CCS on economic grounds.
Commenter 10618 stated each example of a potential commercial-scale CCS on a coal-based generating unit has experienced a significant escalation in costs. According to the commenter, the wide disparity in the cost estimates of current efforts is indicative that CCS is not a one-size-fits-all technology, that project-specific cost drivers are significant, that reliable estimates of CCS costs are evolving, and that future CCS costs are highly speculative.Commenter 8966 stated that in close consultation with Alstom, a manufacturer of the chilled ammonia-based CCS system, AEP commissioned a front-end engineering and design (FEED) study to develop a commercial-scale CCS system at the plant, capturing carbon from approximately 20% of the flue gas output. A single installation of the system was estimated to cost over $1 billion, and even despite installation, the facility would likely exceed the 1,100 lb/MWh standard, even assuming 100% carbon capture efficiency. In light of these astronomical costs, AEP decided to cancel the commercial-scale project. To achieve a level of carbon capture that would suffice under the rule, a multi-billion dollar investment would likely be necessary for a single new large-scale coal power plant, which is several times greater the cost of the plant itself. AEP's sudden reversal of plans is a strong indicator that other prospective operators will similarly turn away from coal-fired plants when they experience the "sticker-shock" associated with the massive costs of a commercial-scale CCS system.
 Commenters 9666 and 10952 maintained that the EPA should not base cost estimates on plants not in operation.  A number of commenters (e.g. 2471) indicated more generally that the EPA should not base its cost considerations on plants engaged, or planning to engage in, EOR.  As noted in other responses, EPA has sought the most up-to-date information on costs, and the cost estimates for post-combustion CCS are for the CanSolv compression and capture system which is the system in place and operating at Boundary Dam.  The EPA is not considering EOR revenues in its assessment of costs.
 Commenter 9666 anticipated reliability concerns when Boundary Dam commences operation.  In fact, the company has reported, with considerable enthusiasm, that the plant is operating even better than anticipated.  See preamble section V.D.2.a.
Commenter 8925 referred to cost overruns at the Boundary Dam project as an instance of the EPA underestimating costs associated with CCS.  In fact, the EPA has documented that all cost overruns related to the boiler, not to the carbon capture system.  Any cost overruns assigned to the capture side were financing costs that were due to delays caused by the boiler side.  The installation of the capture equipment came in on schedule and on budget. See Memorandum to Docket re Conversation between Dr. Nick Hutson (EPA) and Mike Monea (SaskPower).  Commenter 8925 stated that the plant received government funding, which is correct but not pertinent to the question of total cost.  The Boundary Dam facility is a FOAK plant, built with multiple redundancies, and its costs are reflective of FOAK.  Boundary Dam facility personnel have stated publically that they expect at least a 30% cost on the next CCS plant.

A number of commenters referred to Kemper as the prime example of CCS costs being exorbitant (e.g. 9497, 8925).  As noted in other responses, cost overruns at Kemper reflected a series of idiosyncratic decisions that essentially resulted in construction commencing before proper planning had occurred, resulting in improper sequencing of construction efforts and enormous resulting excess costs.  The motivation for this cart-before-the-horse approach was to obtain the IRC 48g tax credit for a particular calendar year.  The EPA believes that these cost increases are avoidable by following normal practice rather than just-in-time sequencing, and therefore that the cost overruns at Kemper are not predictive of what next plants would experience.  Moreover, the Independent Monitor's Prudency Evaluation report identifies cost issues associated with IGCC (idiosyncratic, as noted) but not with the CCS system.  Kemper cost information consequently is not a good predictor of cost overruns for CCS systems for this reason as well.

Commenters 8966 and 9780 indicated that AEP terminated the Mountaineer project based on projected cost overruns.  AEP's public statements at the time were that the CCS technology was reliable, but that the company was withdrawing at least in part because of regulatory uncertainty.  Preamble section V.D.3.b.  The EPA also notes the positive statements from AEP executives regarding the project and CCS generally:  "AEP still believes the advancement of CCS is critical for the sustainability of coal-fired generation.".  Alstom's contemporaneous remarks were equally positive: See also statement of Alstom senior Vice President for Power and Environment Policies Joan Macnaughton's statement (August 4, 2011): "AEP's decision to put Mountaineer II on-hold (sic) is a bellwether to our leaders on the consequences of uncertain climate policy.  The Validation Plant at Mountaineer demonstrated the ability to capture up to 90% of the carbon dioxide from a stream of the plant's emissions.  The technology works."  The press release further states that Vice President Macnaughton "presented findings from a recently-conducted cost analysis showing that the cost of electricity generated by coal and natural gas plants equipped with CCS is competitive with other low or no-carbon energy carbon energy sources, such as wind, solar, geothermal, hydro and nuclear."  In its public comments here, AEP cited high costs associated with siting monitoring wells and other cost issues associated with developing a suitable sequestration site.  The Mountaineer project involved a retrofit of an existing facility (id.), and issues relating to siting of a sequestration repository can be avoided.  In addition, none of the Class VI permits issued to date by the EPA required the number of monitoring wells need for the Mountaineer site, again indicating that the monitoring and sequestration experiences at that site are site-specific.

Commenter 8024 refers to the State of Michigan's determination that CCS was not part of BACT for the Wolverine facility.  This issue is addressed in preamble section XII.C.
Commenter 9231 stated the proposed rule should take into consideration the type of electricity markets that exist in the various states/regions of the country. The commenter explained that typically, in regulated markets (rate based markets); the cost of compliance to the greenhouse regulations is passed through to the ratepayer through the state public utility/service commission (PUC) rate mechanisms. While the PUC would compare the cost of various technologies and/or fuel sources, the PUC would also take into account the need for energy diversity for security, price stability, and reliability reasons. The commenter also stated that in the case of deregulated markets (market based rates), the investor would have to bear the cost and risk associated with compliance which could put that particular state or region at risk in terms of energy diversity. According to the commenter, if not done properly, the proposed rule could determine winners and losers for not just EGU's but general industry competiveness between states and regions relative to that areas energy mix.
See response RTC 3.3-3.The NSPS is a nationwide standard that is applicable and achievable in all parts of the U.S.  Responses to comments regarding differences between regulated and deregulated markets are provided elsewhere in this RTC.
Commenters 9190, 9725, 10050, 10552, 10667 and 10680 stated that capturing and compressing CO2 consumes a substantial fraction of the plant's electrical generation output so a plant with CCS will have to be substantially larger than one without CCS and will require more fuel to power it. The commenter stated that the Deputy Assistant Secretary of Energy for Clean Coal recently testified before Congress that CCS technology would increase the cost of producing electricity from a coal base load plant by 70-80 percent.
Commenter 9593 also stated EPA also overlooks the substantial energy penalty that CCS systems would impose on the generating capacity of an individual facility.
Commenter 10043 stated that another major cost of CCS is the "parasitic load" that ranges from 20 percent to 30 percent of a power plant's output to energize the associated emission control technologies. The commenter noted that future research and development may bring this cost down, but the reductions will not be significant enough to offset the major financial burden created by power lost to operate the CCS technology. The commenter provided the example that for an 800MW supercritical coal unit, its average energy costs would increase from approximately $42/MWh to $54/MWh (a 29% rate increase) assuming parasitic consumption for carbon capture at the low end estimate of 20% and $2/ton for transportation of 50% of the unit's CO2 emissions. The commenter stated that the result is the loss of 1.1 million megawatt-hours per year an impact much too large for the EPA to simply disregard under the CAA-and that does not include costs for the sequestration and storage itself. The commenter concluded that beyond the direct costs of installation and operation, CCS will have an exorbitantly costly impact on the electric generation industry and ultimately the nation's ratepayers as the country will no longer utilize electricity generated using reliable and stable coal resources.
Commenter 9590 stated capturing and compressing CO2 consumes a substantial fraction of the plant's electrical generation output, so a plant with CCS will have to be substantially larger than one without CCS and will require more fuel to power it. The commenter also stated that the cost of deploying CCS technology is exorbitant and unreasonable, and tis factor alone disqualifies CCS as BSER for coal base load power plants.
Commenter 10870 stated the Boundary Dam Unit 3 will produce 160 MWe gross and only 110 MWe net, a 31% parasitic load with most of it consumed by the CCS system. According to the commenter, this is well above the normal 7-12% parasitic load expected of a plant without CCS. The commenter also stated that without experience on full-scale CCS systems, any estimate of capital costs and operation and maintenance costs is suspect. The commenter also stated concern with the exorbitant cost of operation and maintenance of CCS.
These comments are addressed in preamble section V.O.3. As shown there, the results in preamble Table 14 show that a new SCPC unit without CCS can expect a parasitic power demand of about 5.2 percent. A new SCPC unit meeting the final standard of performance by implementing 16 percent partial CCS will see a parasitic power demand of about 6.3 percent, which is not a significant increase in energy requirement. Of course, new SCPC EGUs that implement higher levels of CCS will expect higher amounts of parasitic power demand. As shown in Table 14, a new SCPC EGU implementing full CCS would expect to utilize over 14 percent of its gross power output to operate the facility and the carbon capture system. But, the EPA does not find that a new SCPC implementing full CCS is the BSER for new fossil-fired steam generating units. The EPA notes in addition that the DOE testimony referred to by commenters was with regard to full CCS, not the degree of partial CCS identified as part of BSER in this action.
Commenter 10618 stated their concern that EPA's cost evaluation relies only on the two NETL reports become even more pronounced when considering the large difference of the estimated costs projected by EPA in the proposed rule and the actual costs that active CCS projects are incurring. The commenter provides a table to summarize their comparison. The commenter stated that EPA's cost analysis is flawed due to a narrow review of available information and a failure to consider the cost of actual projects. The commenter stated that EPA's cost analysis relies on only two DOE/NETL reports that are based on conceptual designs for technologies that, at least in the case IGCC and CCS, have never been constructed. According to the commenter, much of the cost analysis language contained in the preamble is verbatim from these reports, albeit without appropriate references. The commenter then provides a list of flaws in the EPA's cost analysis as well as review points of the EPA's references that the commenter considers to have either been ignored or misinterpreted by the EPA. Then the commenter cites a couple references/reports showing that development costs may increase as new information is discovered, urging the EPA to consider that in their analysis.
Commenter 9425 stated EPA relies on a 2011 cost and performance report by the DOE NETL that is merely modeling predictions that estimate the performance of various CCS configurations and is not based on information gathered from actual operating experience. According to the commenter, the cost of CCS at smaller demonstration facilities cannot be reliably scaled up to inform predictions about the cost of CCS at commercial units.
Commenter 10087 stated EPA arbitrarily considers CCS costs from NETL for coal, but does not consider that according to NETL, electricity generated from natural gas CCS plants is less expensive than coal. The commenter also stated EPA arbitrarily omits the fact that according to this DOE/NETL study, natural gas with CCS produces less expensive electricity than coal with CCS.
Commenter 10095 stated in trying to specifically justify not using EIA's CCS cost estimates, EPA claims, no estimates were provided by EIA for IGCC with partial or full CCS, and that the DOE NETL reports provided detailed cost estimates for a range of CO2 capture levels for both new SCPC and IGCC facilities. According to the commenter, both of these rationales are flawed. The commenter noted that EIA did provide cost estimates for IGCC with full CCS, and that EPA did not directly use DOE NETL's partial CCS cost estimates. Instead, the commenter explained, to estimate partial CCS cost, EPA linearly scaled DOE NETL's no and full capture CCS cost estimates. According to the commenter, this exact analysis (i.e. linearly scaling) could have easily been performed using EIA's cost estimates.
Commenter 9666 stated the series of NETL reports, perhaps valid for use in a technology screening study, are not adequate upon which to base a national energy strategy. According to the commenter, none of the NETL reports appear to have been subjected to an authentic peer review, and a legitimate peer review would address how (a) capital costs were derived, and escalated or revised to reflect changing market conditions, and (b) input data from vendors or suppliers was used, changed, or adjusted to conform with the study scope. The commenter also stated that the DOE/NETL cost reports that EPA cites as the basis for its CCS cost estimates are merely modeling predictions and do not reflect actual experience implementing CCS.
Commenter 9423 stated cost estimates provided by EPA related to CCS D0E/NETL studies from May 2010 through August 2012 do not include cost overruns that have been publicized for some of the projects EPA cites as currently under construction or under development. According to the commenter, if EPA were to update the cost estimates to include cost overruns, and given the accuracy range of estimates of -15 to +30 percent from the center point cost in Table 6 on p. 1476 of the January 8, 2014 notice of proposed rulemaking, the actual cost could be beyond the cost criteria of BSER
 Commenter 9425 states that the NETL study used at proposal costs a system which has never been implemented in practice and therefore is too uncertain.  Partly in response to this and similar comments, and also in order to use the most up-to-date information, EPA's final cost estimates reflect the latest iteration of the NETL studies which are based on recent vendor quotes of the Shell Cansolv post-combustion capture process  -  the process that is currently being utilized at the Boundary Dam #3 facility.
Commenter 9666 states that the NETL cost studies are not peer reviewed and therefore unreliable.  The commenter is mistaken.  The EPA Science Advisory Board Work Group considering the adequacy of the peer review noted EPA staff's statement that "the NETL studies were all peer reviewed under DOE peer review protocols", further noted EPA staff's statement that "the different levels of review of these DOE documents met the requirements to support the analyses as defined by the EPA Peer Review Handbook," and concluded that "peer review on the DOE documents" was conducted "at a level required by agency guidance."
Commenter 9423 urged the EPA to use the full range of the NETL cost estimates.  The EPA has done so in its LCOE analysis.  See preamble at Table 8.  Likewise, the EPA uses the full range of cost estimates for nuclear and other low carbon technologies.
Commenter 10087 states that the EPA ignored NETL estimates that electricity generated from natural gas is cheaper than that generated from coal.  This is true whether or not CCS is utilized, as the EPA noted repeatedly at both proposal and in this final rule.  See e.g. RIA chapter 4.
Commenter 9678 stated the costs of CCS technology particularly as applied to NGCC units demonstrate that CCS is not BSER for natural gas-fired units. According to the commenter, given the efficiency and low-emitting nature of NGCC units, application of CCS would result in an excessive cost per ton of CO2 avoided, which means that CCS is not BSER for NGCC or other natural gas-fired units at the present time and may not be reasonable on a cost basis for a long time, if ever.
The EPA agrees that partial CCS is not BSER for new natural gas-fired units.
Commenter 10618 discussed how the costs required to comply with the requirements of an Underground Injection Control (UIC) permit increased costs of the CCS project by 30%. The commenter encouraged the EPA to review three reports that AEP submitted to the Global CCS Institute and included citations of how to access each
Commenter 9423 stated EPA has failed to include other costs associated with CCS, such as seismic studies, right-of-way costs, permitting, pore space ownership, liability, and water resources.
Commenter 10083 stated CCS comes at a high cost to both the utility and the electric customers that the utility serves. The commenter noted at a minimum, these costs include completing all necessary environmental assessments, permitting to complete the project, designing the plant to accommodate CO2 capture, routing the captured CO2 to the injection site, preparing the injection site, and then the actual injection of CO2 into the storage area. The commenter provided additional information on the situational and locational differences in the western states for siting and using CCS technology required by EPA's GHG NSPS to permit and build a coal-fired EGU.
 The commenter is mistaken. The EPA's cost estimates do in fact include costs associated with transport and geologic sequestration. For transport, costs reflect pipeline capital costs, related capital expenditures, and O&M costs. Sequestration cost estimates reflect the cost of site screening and evaluation, the cost of injection wells, the cost of injection equipment, operation and maintenance costs, pore volume acquisition expense, and long term liability protection. These sequestration costs reflect the regulatory requirements of the Underground Injection Control Class VI program and GHGRP subpart RR for geologic sequestration of CO2 in deep saline formations.  See preamble section V.I.5.
Several commenters discussed financing concerns for CCS projects. Commenter 9597 stated no company, or consortium of companies for that matter, can undertake a $5 billion project without financing., and acquiring financial backing for a project reliant on CCS is going to be extremely difficult and definitely not on good terms. Commenter 10500 stated the costs of CCS are unreasonable and cooperative like AECC cannot receive Rural Utility Service ("RUS") funding for new coal-unit projects. According to the commenter, this high cost prohibits entities from investing in and developing CCS and, therefore, it does not incentivize money lenders approving loans to construct the technology. Commenter 10086 stated that without adequate demonstration of the control, developers, and hence, financiers will have no assurance of future compliance for coal-fired projects and therefore, in addition to the technical concerns regarding CCS, any new generation projects will not be able to obtain capital financing. Commenter 10238 also stated that it would be very difficult to obtain non-governmental financing on a project that has yet to be commercially available and adequately demonstrated.
The EPA has carefully evaluated the issue of financing, and is utilizing cost estimates which reflect "high-risk" financial assumptions rather than conventional financing which are used for cost estimates for non-CCS technologies.  See NETL (July 2015) at p. 18.
According to commenter 8966, CCS systems require significantly more space than traditional emission controls and the footprint of CCS equipment may exceed that of the EGU itself. The commenter stated that this characteristic can pose particular implementation difficulties for facilities planned on sites surrounded by land unsuitable for construction or otherwise occupied. Further, the commenter explained, new projects must incur the additional land or right-of-way (ROW) acquisition costs to house the CCS equipment, as well as additional legal costs associated with obtaining zoning or other siting permits that may be unnecessary if no CCS system were installed, and these land acquisition requirements may be significantly higher for or on-site storage of captured CO2.
The EPA's cost estimates include costs associated with transport and geologic sequestration. For transport, costs reflect pipeline capital costs, related capital expenditures, and O&M costs. See preamble section V.I.5. Pipeline capital costs include materials, direct labor, right-of-way acquisition, and miscellaneous costs. Sequestration cost estimates include pore volume acquisition expense, and also reflect the regulatory requirements of the Underground Injection Control Class VI program and GHGRP subpart RR for geologic sequestration of CO2 in deep saline formations.
Commenter 9194 stated CCS is excessively costly to the consumer, which EPA has attempted to disguise by inappropriately comparing coal with CCS to nuclear and biomass generation instead of comparing coal with CCS to the newest, cleanest coal plants without CCS.
Commenter 10036 stated that the nuclear power sector is not a useful benchmark for cost viability. According to the commenter, EPA used dissimilar techniques in comparing the cost of nuclear power to the cost of coal-fueled power and if the two sectors are compared on a consistent basis, the cost of coal systems with partial CCS fails EPA's own test of reasonableness. Commenter 9677 stated that a unit built with CCS is just too expensive (that is, unreasonable cost.). The commenter stated that EPA evaluates cost for the proposed rule by comparing a unit with CCS to other non-natural gas power generation processes. The commenter equated that approach with comparing apples to oranges. The commenter suggested costs be considered on an incremental basis; the cost of a fossil fuel fired unit vs cost of the same unit with CCS.
 The EPA disagrees; the comparison with nuclear  -  the other main dispatchable baseload non-NGCC electricity-generating unit, is reasonable.  See preamble section V.I.1.  The EPA has also compared capital cost increases for SCPC with and without partial CCS, and found that increase to be reasonable.  See preamble section V.H.4.
Commenters 9407, 9600 and 10952 stated all real identifiable costs associated with the proposed partial carbon capture as applied to coal-fired EGUs show cost increases from 50 to 100 percent above generation costs without carbon capture. According to the commenter, this proposal has failed to demonstrate that CCS is available at all much less at a reasonable cost.
Commenter 9407 and 10097 stated the proposal including information contained in the rulemaking docket presents no information that could lead to a rational conclusion that full or partial carbon capture can be deployed as part of a BSER immediately and, at a reasonable cost. According to the commenters, EPA has failed to provide any explanation in this rulemaking's docket to document what carbon capture technologies in other industries it is utilizing and how it is technically appropriate to extrapolate those technology applications to coal-fired steam electric generation that must operate under required and specific duty cycles that do not mimic those required in other industries. Thus, the commenter stated, there is an insurmountable problem with the proposal since the information provided in this rulemaking docket includes no reasonable basis to conclude that carbon capture is technically available at a reasonable cost for use as BSER in the immediate future and perhaps not available as a BSER for many years to come.