Chapter 6
Standards for Fossil Fuel-fired Electric Utility Steam Generating Units (Boilers and Integrated Gasification Combined Cycle Units) 
Contents
6.1	General	3
6.2	Proposed NSPS for New Fossil Fuel-Fired Utility Boilers and IGCC Units is Not an NSPS	3
6.3	CCS	6
6.3.1 Literature on CCS	6
6.3.2 Similarity to Controls Required in Previous NSPS Rulemakings	13
6.3.3 The Range of Emission Limits EPA Is Considering Cannot Be Achieved by a Coal-Fired EGU without the Use of CCS	17
6.3.4 CCS Technical Issues	19
Post-combustion CO2 Capture	30
Oxy-combustion	32
Pre-Combustion CO2 Removal	32
CO2 Transport	33
Geologic Sequestration	46
Enhanced Oil Recovery and CO2 Utilization	71
6.3.5 CO2 Transport and Geologic Sequestration Legal and Regulatory Issues	93
Geologic Sequestration Property Rights	93
CO2 Transport Legal and Regulatory Issues	96
Safe Drinking Water Act's Underground Injection Control (UIC) Program and Resource Conservation and Recovery Act	109
Greenhouse Gas Reporting Program	120
Liability	130
Other CO2 Transport and Geologic Sequestration Legal and Regulatory Issues	135
6.3.6 CCS Is/Is Not BSER	140
Cost	147
Adequate Demonstration	204
Promotion of Technological Development	227
Nationwide, Long-Term Perspective	233
Energy and Nonair Quality Environmental Impacts	236
Use of Purportedly Extra-Statutory "Purposes" to Justify Standard of Performance	243
Other BSER Options	245
6.3.7 EIA Analysis	252
6.3.8 Effect of the Proposed NSPS Rule on CCS Development, Demonstration and Deployment	253
6.4	Proposed Emission Limit of 1,100 lb CO2/MWh	257
6.4.1 Achievability of Proposed Standard with CCS Technology	268
6.5	Other Subcategories	272
6.5.1 Coal-Fired Projects Under Development	274


General
Commenter (9646, 10092) supported the EPA's proposal to set separate performance standards for fossil fuel-fired utility boilers and integrated gasification combined cycle units and natural gas-fired stationary combustion turbines. Commenter (9646) stated that this approach better allows EPA more regulatory flexibility to craft standards of performance tailored to the unique characteristics of each fuel and generator type.  Commenter (10092) expressed concern about promulgating uniform nationwide limits.
The Agency appreciates the comments regarding its proposal to set separate performance standards for steam generating EGUs (i.e., utility boilers and IGCC units) and natural gas-fired stationary combustion turbines. The Agency also notes that Clean Air Act section 111(b) New Source Performance Standards (NSPS) are intended to be applicable nationwide.
Proposed NSPS for New Fossil Fuel-Fired Utility Boilers and IGCC Units is Not an NSPS
Commenter 9666 stated that EPA's proposed NSPS for new fossil fuel-fired utility boilers and IGCC units is not an NSPS as it is not a standard that requires an enforceable, on-site reduction in the total emissions generated by new sources. The commenter noted that the proposed standard merely reflects the amount of unseparated CO2 a source would release from the stack, yet the total CO2 generated by the source does not change as the remainder of the CO2 generated by the source is separated and sent somewhere with the expectation that it will be sequestered. Therefore, the commenter argued it would not violate the proposed NSPS if 100 percent of the CO2 separated by the capture technology subsequently was released to the atmosphere. According to the commenter, a standard defining "new source performance" must be based on a system of emission reduction incorporated into the new source itself and the underground "sequestration" of separated CO2 at an off-site location miles away from (and not under the control of) the new source does not meet this requirement,  nor does on-site sequestration, as sequestration facilities are not subject to the standard and are not a part of the "affected facility" to which the standard applies. According to the commenter, the proposed Subpart Da standard does not reduce emissions; the proposal, which is based on one element of CCS, produces no reduction in the CO2 generated by a source: instead, it merely requires that new sources separate some percentage of the CO2 from its flue gas stream, without imposing any requirements regarding the CO2's ultimate fate. The commenter stated that the proposal is a "carbon separation" system, not a "carbon capture and sequestration" system, and therefore it does not reduce emissions. The commenter concluded that the proposed standard for Subpart Da units must be withdrawn because it is unlawful and not a "performance" standard based on a "system of emission reduction" as it does not contain any limitation requiring on-site disposal of captured CO2 through sequestration or any limitation requiring off-site sequestration.  
First, as explained in more detail in response to this same commenter 9666 (UARG) in RTC Chapter 2, the commenter is mistaken that a standard of performance must include standards for a captured pollutant, be it particulate captured by a baghouse and disposed of as solid waste, a waste water captured in a wet scrubber and discharged to waters, or (as here) a gas captured in supercritical phase and sequestered.  Second, as part of its obligation under section 111 (a) (1) to consider non-air quality health and environmental impacts and other collateral consequences of this rulemaking, the EPA has carefully assessed the integrity and safety of the transport and sequestration of captured CO2.  It is EPA's considered and reasonable belief that the plenary regulatory standards for CO2 pipelines assure pipeline safety, and the comprehensive regulatory standards for Class VI and Class II injection wells (and the long history of safely-conducted use of CO2 for EOR), in combination with the reporting requirements of the subpart RR GHG reporting rule (including the comprehensive monitoring, reporting and verification plan required under those rules) assures that captured CO2 will be safely tracked to a sequestration repository, and that CO2 will be safely and securely sequestered for long-term storage.  See preamble section V.N.  In particular, the EPA notes that the Class VI standards for protection of underground sources of drinking water, such as a rigorous site characterization process and a rigorous sub-surface monitoring regime, would assure containment within a well's injection zone, and thereby also prevent any release of sequestered CO2 to the atmosphere.  The monitoring would also be sufficient  detect any potential escape from the injection zone before there could be any release of CO2 to atmosphere, with backup assurance provided by the monitoring required under the subpart RR GHG Reporting regulations (as part of the monitoring, reporting, and verification plan).   Id.  Indeed, some of the same commenters arguing that EPA had arbitrarily failed to address sequestration in the standard criticized features of the Class VI rules as overly stringent (e.g. the 50-year post-closure care requirement).
In short, section 111 (a)(1) standards of performance are not required to address disposition of a captured pollutant.  EPA is required to consider such disposition as part of the requirement to consider a standard's potential non-air quality health and environmental impacts, and has reasonably done so here.     
Commenter 9774 stated that EPA is applying the NSPS to a range of sizes and types of generation technology that were not evaluated in EPA's analysis of CCS. The commenter stated that EPA only evaluated the cost of CCS based on applying the technology to a 550 MW supercritical boiler and therefore the proposed NSPS should not apply to other types of coal generating units. According to the commenter, EPA must acknowledge that generating units employ varying technologies serving specific needs and a NSPS analysis and limit must be developed specifically for and allows for the continued use of these types and sizes of coal-fired generation units. Commenter 9774 also stated that the proposed NSPS will also apply to future boiler technologies, such as oxy-firing, which has the potential to significantly increase the efficiency of boilers and decrease CO2 emissions as compared to the super-critical coal-fired boiler assumed in the analysis. However, the commenter stated that oxy-firing cannot be considered as a stand-alone option if it cannot meet the CCS-based NSPS. Thus, the commenter concluded the proposed NSPS could effectively prohibit the use of this and other emerging boiler technologies, even if they provide a better overall outcome.
The final standard of performance is based on the performance of a highly efficient SCPC implementing partial CCS  -  at a reasonable cost. The final standard of 1,400 lb CO2/MWh-g can be achieved by a highly efficient SCPC burning bituminous coal by implementing about 16% CCS and by such a unit burning low rank coal by implementing about 23% CCS. The EPA did base its projections of cost and performance on a 500 MW-net new source (using information from DOE/NETL studies). However, the primary metric that the agency used to evaluate the reasonableness of costs  -  the levelized cost of electricity (LCOE)  -  is normalized on a per megawatt-hour basis (i.e., as $/MWh) and thus is indicative of costs over a range of sizes. In addition, as shown in Table 8 of the rule preamble, the EPA presented the anticipated costs as a range to account for uncertainties in capital costs from -15% to +30% (per guidance from DOE/NETL). While the cost for a new unit that is larger or smaller than the 500 MW example may deviate somewhat from the point estimate provided by DOE/NETL, the costs should fall within the range presented in Table 8.  The final BSER determination does not mandate in any way that utilities and project developers must build a new 500 MW SCPC that implements partial CCS. Project developers are still free to choose other generation options and the EPA has specifically discussed the alternative compliance option of natural gas co-firing  -  and option that can be implemented at a cost that is less costly than the BSER option (see Table 9 in the final preamble; though for reasons explained in the final preamble, the EPA does not find natural gas co-firing to be the BSER).  Regarding the use of oxyfuel combustion, there is no need for an oxyfuel combustion system to implement CCS. The system inherently produces a high concentration CO2 stream. In fact, such a system would be able to achieve a much more stringent emission rate than is required by the final standard. The EPA did not consider oxyfuel combustion as a BSER technology because of the relatively few demonstration projects (especially in the U.S.  -  no large-scale demonstration projects) and the lack of cost information. However, if a project developer chooses to construct a new oxyfuel combustion EGU in the future, the final NSPS will not hinder the feasibility to pursue the project in any way.
Commenter 9513 stated that the exemption for IGCC less than 50% syngas from the CCS requirement would result in the units not being subject to any regulation and allows unregulated combustion of large amounts of coal, which undermines partial CCS obligation.
Some IGCC units co-produce chemicals along with power. The final applicability requirements for IGCC units is that the unit is an affected source if it sells more than one-third of its potential electric output to the grid. Such a unit would be required to meet the final standard performance of 1,400 lb CO2/MWh-g. However, as we note in the preamble, many new IGCC units will be able to meet this standard by co-firing only a small amount of natural gas and would be unlikely to install a CCS system just to meet the final standard. However, some new IGCC units may choose to install CCS technology in order to take advantage of the flexibilities of the integrated gasification system  -  such as the co-production of chemicals.
Commenters 8022, 9725, 9734, 10023, 10031, 10039, 10050, 10520, 9190, 10552 stated that EPA has utterly failed to propose any system of emission reduction in its proposed NSPS for Subpart Da units, in direct contravention of section 111 of the CAA, and that as proposed, the standard requires only on-site separation of CO2, with no limits on its release to the atmosphere. According to the commenters, that is not a NSPS within the meaning of the CAA. 
Commenter 10664 noted that attributing of emissions beyond the capture is unusual.
The standard of performance does ensure that there is a reduction in the emission of CO2 from the affected facility.  The comment suggests that the EPAs proposed performance standards should have included some additional requirements to ensure that captured CO2 is not ultimately released into the atmosphere. This comment is addressed in this unit above at Response 6.2-1, and also in RTC Chapter 2.     
CCS
Commenter 0775 stated that they are pleased that the allowable CO2 emission thresholds would effectively prohibit any future coal-fired power plants unless those plants can capture and sequester at least 60% of their carbon dioxide emissions.
Commenter 10961 stated power utilities must either capture and sequester their carbon, or cease burning the most carbon-intensive source of boiler-generated electricity, namely coal. According to the commenter, nothing in the Clean Air Act requires EPA to permit any particular source of fuel. The commenter stated that natural gas-fired generators are an available and cost-effective technology for the generation of electricity, and is identifiable under this rulemaking as an alternative to coal-fired generators. 
The EPA notes that the rule does not require the use of CCS, nor does it specify any particular percentage that must be captured and sequestered.  Instead, the rule specifies the allowable emission (in pounds of CO2 per megawatt-hour-gross) from a new fossil fuel-fired steam generating EGU (utility boiler or IGCC unit). Although the EPA conservatively costed the rule based on the use of 16% partial CCS (for new SCPC plants burning bituminous coal), the EPA also noted that there are other compliance paths available for both of these types of sources.  
6.3.1 Literature on CCS
Commenter 10618 stated that EPA has only considered a narrow fraction of available information to inform its literature review. The commenter pointed to literature summarized in 2012 comments under EPA-HQ-OAR-2011-0660-10038, page 42.
While the EPA believes that it did conduct a thorough literature review for the proposal, we have specifically included a Technical Support Document  -  "Literature Survey of Carbon Capture Technology" in the rulemaking docket.
Commenter 2471 stated that EPA may not have conducted a proper peer review, including cross-media impacts to water and soil.  
  The EPA disagrees. In fact, the SAB Workgroup stated by letter endorsed by the full Committee that "while the scientific and technical basis for carbon storage provisions is new and emerging science, the agency is using the best available science ....".  Letter of Jan. 7, 2014 from SAB Workgroup Chair to Members of the Chartered SAB and SAB Liaisons, p. 3.  The same Workgroup likewise found that the NETL materials had been fully peer reviewed, and that the Department of Energy peer review procedures also satisfied the EPA Peer Review Guidelines.  Id.
Commenters 8966 and 9396 stated that EPA has violated the Data Quality Act because the supporting literature cited by the proposed rule constitutes a highly influential scientific assessment (HISA) that requires its own peer review under the OMB Peer Review Bulletin pursuant to the Data Quality Act. Commenter 8966 further stated that the controversial and precedent-setting nature of the proposal as well as the significant interagency interest constitutes an HISA.
These comments are addressed in Chapter 2 in the unit discussing issues related to the Data Quality Act.
Commenters 9426, 9666, 9780, 10095, 10098, 10239 and 10618 asserted that the government studies cited by EPA do not constitute an extensive record nor do they illustrate that the technical, economic and legal barriers to implementing commercial scale CCS have been surmounted. For example, Commenter 9666 stated that the literature does not address the issue of scale-up for PC and IGCC units, generalization to different fuels, or actual lessons learned. 
The EPA is not relying exclusively on government studies or on the scientific literature as the basis for its determination that partial CCS, along with highly efficient SCPC, is the best system of emission reduction adequately demonstrated.  As stated in section V.D of the preamble to the final rule, the principal justification are plants operating CCS at full commercial scale.  EPA likewise explains the basis for its conclusions that costs will decline for the next plants which deploy partial CCS in section V.H.8  of the preamble to the final rule The EPA has also addressed issues associated with scale-up (see generally in section V.G.3), and variable operating conditions, and use of different fuel types (see sections V.J.1 and V.J.2).
The commenters then discussed the EPA cited studies, noting that the Task Force report is not a final report of research and development results, the 2009 PNNL report cites CCS for coal-fired EGUs as a future technology requiring vigorous ongoing research, development and demonstration, and NETL's Cost and Performance Report models potential efficiency rates and costs of CCS units rather than assessing actual coal-fired power plants (because no power plant has operated with the 40 percent capture CCS system EPA proposes to define as BSER). Commenter 10239 also noted that the Task Force report was available when it issued the GHG Guidance in 2011, yet the EPA offers no rational basis for reversing its prior conclusion that CCS was unlikely to meet the higher BACT standard. 
The EPA has noted several times that the charge of the CCS Task Force was to propose "a plan to overcome the barriers to the widespread, cost-effective deployment of CCS within 10 years ..." Much of what is written in technology readiness assessments and other technology development "roadmaps" involves the readiness of CCS technology that can be widely implemented and often examines the readiness of "full capture" (i.e., 90+% capture).  Widespread implementation would only be applicable as a retrofit technology of existing facilities.  Existing sources are not covered in this rulemaking.  In the EPA's proposal for its CAA 111(d) emission guidelines, the Agency explained that it evaluated implementation of CCS as a potential component of the BSER for existing sources and ultimately rejected it due to cost and other considerations. 
     The EPA also examined application of CCS technology at existing EGUs. CCS offers the technical potential for CO2 emission reductions of over 90 percent, or smaller percentages in partial applications. In the recently proposed Carbon Pollution Standards for new fossil fuel-fired EGUs (79 FR 1430), we found that partial CCS was adequately demonstrated for new fossil fuel-fired steam EGUs and integrated gasification combined cycle (IGCC) units. We also found that for these new units the costs were not unreasonable, either for individual units or on a national basis, and we proposed to find that application of partial CCS is the BSER. 
     However, application of CCS at existing units would entail additional considerations beyond those at issue for new units. Specifically, the cost of integrating a retrofit CCS system into an existing facility would be expected to be substantial, and some existing EGUs might have space limitations and thus might not be able to accommodate the expansion needed to install CCS. 
     Further, the aggregated costs of applying CCS as a component of the BSER for the large number of existing fossil fuel-fired steam EGUs would be substantial and would be expected to affect the cost and potentially the supply of electricity on a national basis. For these reasons, although some individual facilities may find implementation of CCS to be a viable CO2 mitigation option in their particular circumstances, the EPA is not proposing and does not expect to finalize CCS as a component of the BSER for existing EGUs in this rulemaking. Nevertheless, CCS would be available to states and sources as a compliance option.
Additionally, Commenter 10618 noted that none of the reports consider the lessons learned and experiences of actual projects such as the AEP Mountaineer CCS validation-scale plant or the coal-based electric generation CCS projects under development. The commenters surmised that in light of these issues within the literature, EPA cannot claim that CCS is adequately demonstrated. Commenters 9426, 9666 and 10095 further asserted that rather than supporting EPA's conclusion that CCS is BSER, the studies provides support for the immaturity of CCS. Commenter 9666 then cited several reports stating that CCS is not demonstrated for large or commercial scale power plants.
The EPA stands by its determination that implementation of partial CCS is adequately demonstrated as described in the section V.D. and E. of the preamble to the final rule.  The EPA also understands that there is available literature and there are studies (some of which are dated) that offer more cautious or pessimistic views on the state of CCS development.  Many of the reports cited in the comments have evaluated the technology readiness or feasibility on whether "full capture" (90+% capture) can be economically deployed on a wide-scale.  EPA found that the costs of full capture, at this time, may not be reasonable as they are predicted to exceed the costs of other low CO2 emitting, base load generating options that are being considered as alternatives to new NGCC units. Most of the studies have focused on the availability and the economic and technical feasibility of retrofitting carbon capture technology to existing sources.  EPA is not predicating any standard for existing sources on utilization of full- or partial-CCS.
Commenter 9666 also stated that the NETL reports use cost data from a single engineering firm that reflects market conditions prior to and during the escalation in capital equipment cost from about 2006 through 2010 introducing significant uncertainty into cost estimates. The commenter further noted that the estimated CO2 separation equipment are based on an equipment list that was not peer reviewed and not based on actual operating experience under a range of relevant conditions. The commenter concluded that the report cannot therefore be relied upon to support a finding that the CO2 separation rates are actually "achievable" within the meaning of section 111.
First, the NETL cost estimates were adequately peer reviewed, and the SAB Workgroup so found.  The study report(s) the DOE/NETL explained that the Total Plant Costs (TPC) and Operation and Maintenance (O&M) costs for each of the cases in the study were estimated by WorleyParsons using an in-house database and conceptual estimating models. This database and the respective models are maintained by WorleyParsons as part of a commercial power plant design base of experience for similar equipment in the company's range of power and process projects. A reference bottoms-up estimate for each major component provides the basis for the estimating models. Costs were further calibrated using a combination of adjusted vendor-furnished and actual cost data from recent design projects. (See DOE/NETL report, pages 44-45).  The EPA understands that costs can change with time and location.  However, as the DOE/NETL noted (report p. 9): "The value of the study lies not in the absolute accuracy of the individual case results but in the fact that all cases were evaluated under the same set of technical and economic assumptions. This consistency of approach allows meaningful comparisons among the cases evaluated."  Increases in capital costs, labor costs, transportation costs, etc. affect the construction of all new technologies  -  with or without the inclusion of carbon capture equipment. While the relative comparisons presented in the NETL reports may vary somewhat as a result, the EPA's conclusion regarding the costs  -  that implementation of "partial capture" CCS is not exorbitantly expensive  -  should still be valid. The EPA also notes that the cost and performance projections that were used for the final rule were updated versions of the reports used for proposal. DOE/NETL noted in the updated (2015 report) that "[T]his revision reflects varying degrees of technology vendor input for updates to the pollution control equipment for PC plants, and the CO2 capture, CO2 compression, and steam turbine technology for PC and NGCC plants ..."
Commenter 10044 stated that the NETL data on which EPA relies are no longer valid according to the authors and comments by Commenter 0065 and 0066.
Commenter 9423 cited a May 2013 NETL report disputing the current technological and economic feasibility of CCS on coal fired plants. The commenter recommended that EPA withdraw the proposed rule until the issues are addressed
The commenter references comments (0065 and 0066) that came from OMB and Interagency review of DRAFT versions of the proposal preamble.  In particular, the DOE was concerned that EPA, in a DRAFT version of the preamble, had not clearly explained the cost numbers that relied on DOE/NETL studies and they recommended that EPA use first-of-a-kind costs instead.  The EPA explained the rationale for using the next-of-a-kind estimates  -  as it did in the proposal  - and provided the responses given in comment 0066.  The EPA worked with staff at the DOE/NETL to ensure that the language in the proposal preamble clearly explained the nature of the costs (i.e., that they represent next-of-a-kind or `next commercial offering' costs).  The proposal  -  as it was published in the Federal Register  -  was cleared through OMB and Interagency review.  The final rule likewise indicates clearly that the cost estimates represent the next commercial offering costs, consistent with their presentation in the NETL reports.  It should be noted that these interagency review comments are not part of the record for judicial review (see CAA section 307 (d)(7)(A) ), but the EPA is addressing these comments in the interests of transparency, and to correct the mistaken suggestion in the comments that the EPA proposal and final rule evaluated and made use of NETL materials in a manner inconsistent with the authors' intent.
 However, partly in response to this and similar comments, the EPA continued to evaluate cost information in order to consider the most up-to-date information.  The cost information for post-combustion CCS comes from NETL (2015) and reflects latest vendor cost quotes for the Shell Cansolv process  -  the process in use at the Boundary Dam Unit #3 facility.
Commenter 10618 stated that the data in the 2010 NETL report is unreliable because data is based on conceptual designs and limited to bituminous coals. The commenter further stated that no data validates the emission rates.  Commenter 10618 recommended that EPA analyze operating data from the CAMD database for emission rates in practice as well as talk with vendors, operators and manufacturers to determine sustainable, representative emission rates for coal based technologies.
The commenter is mistaken in suggesting that a standard of performance cannot reflect a conceptual design.  Indeed, the D.C. Circuit has explained that a standard of performance is ``achievable'' if a technology can reasonably be projected to be available to new sources at the time they are constructed that will allow them to meet the standard. 
Specifically, the D.C. Circuit explained: 
      Section 111 looks toward what may fairly be projected for the regulated future, rather than the state of the art at present, since it is addressed to standards for new plants. . . . -- It is the ``achievability'' of the proposed standard that is in issue . . . . The Senate Report made clear that it did not intend that the technology ``must be in actual routine use somewhere.'' The essential question was rather whether the technology would be available for installation in new plants. . . . The Administrator may make a projection based on existing technology, though that projection is subject to the restraints of reasonableness and cannot be based on ``crystal ball'' inquiry.
Portland Cement Ass'n v. EPA, 486 F. 2d at 391.   EPA has no way of pre-determining the specific design configuration that individual project developers will choose and so an evaluation of "conceptual designs" is appropriate.  In particular, regarding the conceptual designs in the NETL reports.  The `Objective' of the NETL studies was given (report in `NETL Viewpoint') as follows:
Objective:
To establish baseline performance and cost estimates for today's fossil energy plants, it is necessary to look at the current state of technology. Such a baseline can be used to benchmark the progress of the Fossil Energy RD&D portfolio. This study provides an accurate, independent assessment of the cost and performance for Pulverized Coal (PC) Combustion, Integrated Gasification Combined Cycles (IGCC), and Natural Gas Combined Cycles (NGCC), all with and without carbon dioxide (CO2) capture and sequestration assuming that the plants use technology available today. [Emphasis added] ("Cost and Performance Baseline for Fossil Energy Plants Volume 1: Bituminous Coal and Natural Gas to Electricity" Revision 2a, September 2013. DOE/NETL-2010/1397)
So, while the designs are necessarily conceptual, they represent fossil fuel fired plants that "use technology available today".  
We also note that, while we did rely on Volume 1 of the Cost and Performance reports, there are companion reports that evaluate very similar configurations that utilize low rank coals with very similar results.  Achievability of the final standard under a variety of operating conditions and using varying fuel types is discussed in the preamble section V.J.1 and V.J.2 and also in a Technical Support Document (TSD)  -  "Achievability of the Standard for Newly Constructed Steam Generating EGUs" available in the rulemaking docket.
Commenters 9505 and 10088 noted that although EPA's Science Advisory Board (SAB) dubiously reversed its position because the proposed rule only requires the capture of carbon emissions and does not directly address carbon storage, the SAB questioned the adequacy of the peer reviewed studies in a November 2013 memo.
This comment reflects a significant misstatement or misimpression.  See full response in RTC 2.4 concerning comments on the Data Quality Act.  In fact, the EPA addressed the SAB Work Group's recommendations from the November 2013 memorandum in subsequent meetings with the SAB Work Group. The EPA provided the Work Group with additional information on the peer review process of the DOE/NETL studies and noted that the peer review of the NETL studies, conducted by DOE, met the requirements of EPA's Peer Review Handbook. The Workgroup, in a letter endorsed by the full Committee, then found that "while the scientific and technical basis for carbon storage provisions is new and emerging science, the agency is using the best available science ...".  (See Letter of Jan. 7, 2014 from SAB Workgroup Chair to Members of the Chartered SAB and SAB Liaisons, p. 3.)  The EPA further noted that the proposed rule applied only to the capture of carbon emissions. Requirements for storage/sequestration of the captured CO2 rely on existing promulgated standards. In the same January 7, 2014 memorandum, the SAB Work Group recommended that the SAB not review the science supporting the proposed rule, noting that:
      This recommendation is based on the (1) information provided on the Clean Air Act statutory requirements for feasible technology, the (2) status of carbon sequestration under the Underground Injection Control Program, and (3) additional information on the EPA peer review process. The work group finds that a review by the SAB would not provide additional benefit to the proposed rule.
Commenter 10098 provided literature which estimates that CCS can increase water consumption by 30-100 percent.
The EPA is aware that the use of CCS can increase water usage/consumption at a new facility.  The EPA has carefully evaluated this issue in preamble section V.O.2 and finds the water use impacts of the final standard of performance to be reasonable.  
Commenter 8925 stated that CCS is likely to play a key role in any efforts to significantly reduce carbon emissions, as evidenced by the International Energy Agency (IEA) World Energy Outlook 2013, World Energy Council (WEC) World Energy Insight 2013, Energy Modeling Forum (EMF) 27 Study on Global Technology and Climate Policy Strategies and the Intergovernmental Panel on Climate Change (IPCC) Fifth Assessment Report, Working Group III Summary for Policy Makers.
The EPA agrees that numerous assessments have concluded that ultimate widespread use of CCS is likely necessary to significantly reduce global anthropogenic CO2 emissions.
Commenter 10108 provided a list of important and independent technical studies, such as the 2009 Pacific Northwest National Laboratory report and the SBC Energy Institute CCS Factbook, as a source of independent support for EPA's finding that CCS is technically feasible, adequately demonstrated, and ready for broader deployment.
The EPA appreciates that the commenter has provided the list of these studies.
Commenter 9514 states that the Electric Reliability Coordinating Council's public comments arguing that the Third National Climate Assessment contradicts EPA's BSER determination is wholly without merit.
The EPA generally agrees with the summary provided by Commenter 9514 on the scope of the National Climate Assessment and that the NCA does not purport to be an assessment of CCS.  
Commenters (9201, 9426, 9666, 10046, 10239, 10618) discussed reports and literature that support the commenter's statements that CCS is not adequately demonstrated.
Commenter 9426 submitted that EPA should rely on NETL, who recently concluded that "capture 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 power plant's steam and power to operate, and are very expensive", to determine the status of CCS development for fossil fuel-fired boilers and IGCC units. 
Commenters 9666 and 10239 asserted that CCS is not adequately demonstrated and cites the recent Climate Change Impacts in the United States study as stating that CCS demonstration at scale is uncertain and there are substantial increases energy penalties and construction and operating costs associated with CCS. 
Commenter 9201 cited Global CCS Institute, International Energy Agency, and DOE as support for the commenter's statement that there is a need for integrated commercial scale demonstration of whether CO2 control processes can respond with the rest of the plant to meet a variable, and at times unpredictable, operational load. The commenter further stated that CCS is not adequately demonstrated by the examples provided because they do not provide relevant, or authentic, experience for dedicated power generation, remain in construction or design phase, or only address post-combustion, pre-combustion and oxy-combustion as if the experience from one technology can be readily applied to another despite the fundamental differences in the process steps.  
Commenter 10046 stated that CCS technology is not technologically feasible, as demonstrated by the academic literature on which EPA relies which concludes that there are unresolved technical challenges to scaling and integrating CCS parts into new coal-fired power plants. 
Commenter 10618 argued that EPA ignored available information on CCS, providing references to and citations from numerous assessments by public and private organizations that recognize that CCS has not been proven to be technically feasible or adequately demonstrated for coal-based generation and that significant development barriers remain. 
The EPA stands by its determination that implementation of partial CCS is adequately demonstrated. See preamble sections V.D. and E.  The EPA also understands that there is available literature and there are studies (some of which are dated) that offer more cautious or pessimistic views on the state of CCS development.  Many of the reports cited in the comments address a different issue than the one presented in this rulemaking.  The reports evaluated the technology readiness or feasibility of "full capture" (90+% capture) can be economically deployed on a wide-scale and concluded such widespread implementation was not yet feasible.  EPA is not basing the promulgated standard of performance on full capture  -  regarding it as unreasonably costly.  See preamble section V.P.2. Most of the studies have focused on the availability and the economic and technical feasibility of retrofitting carbon capture technology to existing sources.  In none of the CAA 111 GHG proposals does the EPA suggest a requirement for widespread deployment of CCS across the existing fleet or for implementation of full-capture CCS.  . 
6.3.2 Similarity to Controls Required in Previous NSPS Rulemakings
Commenter 9666 stated that the current state of CCS development is not similar to that of controls required for SO2 and NOx in previous NSPS rulemakings. According to the commenter, showing that CCS is adequately demonstrated will require extensive demonstration experience on a greater scale than was required for SO2 and NOx control technologies and certainly requires more commercial experience than EPA identifies in this proposed rule. The commenter noted that SCR had been widely applied in utility industry in the United States and abroad by the time that it was incorporated into an NSPS for power plants in 1997. In comparison, the commenter notes that today there is no commercial scale coal-fired generating capacity equipped with CCS and only 45 MW of generating capacity has ever been equipped with a fully integrated CCS system. 
Commenters 8024, 9396, 9666, 10031, 10046, 10618 stated that adequate demonstration requires successful commercial scale demonstration, the ability to generalize single source test results nationally, and commercial assurance that components will integrate seamlessly. The commenters stated that CCS is not at the same development phase as FGD and SCR at the time of NSPS, is far more complex, and does not meet the requirements for adequate demonstration. 
First, post-combustion CCS is demonstrated at commercial scale at Boundary Dam Unit #3.  Second, there is no legal requirement that technology be in commercial use before it is identified as BSER.  See preamble section III.G.1.  Third, CCS is actually further developed than were FGD scrubbers when selected as BSER in the 1971 NSPS for this same industry.  This did not impede the successful development and deployment of the technology, and spurred innovation as well.  See preamble section V.L.  With regard to scrubbers, the agency notes that industry pronouncements in the 1970s about the non-availability of the technology were as strident, and misplaced, as those regarding partial CCS.  For example,
 In attack ads, the coal industry called scrubbers "monstrously expensive, unproven technology" and that "it is regrettable that workable technology doesn't exist";
 They said that "scrubbers are undeveloped, unreliable, and unacceptable for electric utility use" and these negative assertions "cannot be seriously challenged by anyone wishing to avoid ridicule";
 Over the next decade, the amount of coal capacity with scrubbers increased 15-fold, reducing emissions by millions of tons;
 The industry made similar claims about other technologies to remove NOx and Hg.  Each of these claims has been proven wrong.
Commenter 9666 discussed how the Great Plains Synfuels Plant is different because it does not generate power and does not need to satisfy a wholesale or regulated power market that can vary on an hour-by-hour basis. 
The commenter is correct that the Great Plains Synfuels Plant is not an EGU and does not need to satisfy a wholesale or regulated power market.  However, the facility is so functionally similar to an Integrated Gasification Combined Cycle (IGCC) EGU that it can be used to inform the EPA's understanding of the carbon capture process and the integrated transportation and ultimate storage of the captured CO2 and how that might be transferred to an IGCC that implements partial CCS to meet the final standards of performance.  See preamble section V.E.2. 
Commenter 9197 stated that unlike previous NSPS, this proposed rule is not supported by actual test data derived from full-scale, commercial facilities employing the claimed "best system of emission reduction."
This comment is addressed in preamble section V.G.2. Since the very inception of the CAA section 111 program, courts have noted that "[i]t would have been entirely appropriate if the Administrator had justified the standard, not on the basis of tests on existing sources or old test data in the literature, but on extrapolations from this data, on a reasoned basis responsive to comments, and on testimony from experts and vendors ...." Portland Cement v. Ruckelshaus, 486 F. 2d at 401-02. The EPA notes that the cost and performance data that the EPA relied on (NETL, June 2015 and NETL, July 2015) reflect information provided by Shell Cansolv, the vendor supplying the carbon capture technology for Saskpower Boundary Dam Unit #3, which is a commercial-scale EGU employing fully-integrated CCS at 90% capture.
Commenters 9666, 10618 stated that the development and demonstration history of controls for conventional pollutants like SO2 and NOx cannot accurately reflect the experience needed to demonstrate CCS, which is more complex and technically challenging than any system of emission control applied to date.
 There is no question that post-combustion CCS is adequately demonstrated,  POWER magazine just gave its power plant of the year award to Boundary Dam for its successful implementation and operation of full CCS.  The award mentioned the technology's reliability, that it came in at budget and on time, and quoted a company executive as stating "if coal has a future, this is it".  See also preamble section V.D. 
Commenter 9666 stated the quantity of pollutants that facility operators would need to remove in order to meet EPA's proposed standard is unprecedented: for a new 500 MW unit firing Powder River Basin coal, the amount of CO2 that the operator would need to capture and remove would be over 100 times greater than the amount of captured SO2, and over 1,000 times greater than the captured NOx.
The same hypothetical 500 MW facility would need to capture and remove about 50,000 times more SO2 than the amount of mercury that would need to be captured.  That does not make SO2 control infeasible.  The amount of CO2 that would need to be captured for a new 500 MW unit firing bituminous coal would be approximately 600,000 tons of CO2 per year, which is only about 6 times higher than the amount of SO2 that would be required to be captured from a high sulfur bituminous coal (or nearly 100 times the captured SO2 when burning low sulfur PRB coal).  However, in order to keep things in perspective  -  the hypothetical new 500 MW coal fired power plant would also require the mining, transport and burning of about 1.5 million tons of coal per year.  So, power plants are already accustomed to handling large quantities of coal and other combustion by-products and the relative quantities of pollutants that must be captured are not an issue.
Commenter 9666 noted that unlike with FGD and SCR, the byproduct of CCS - captured CO2 requires specialized processing because it is unstable under normal atmospheric conditions; captured CO2 must be compressed to a pressure of 100 atmospheres, transported long distances in that volatile state, and injected 4,000 to 8,000 feet below the Earth's surface into a geologically suitable repository, where chemical reactions secure the CO2 over time.
The particulate matter (PM, ash) that is captured from a coal-fired power plant must be carefully handled and properly stored as it contains toxic metals.  So must spent activated carbon used to capture mercury.  The CO2 that is captured must be compressed and transported (potentially long distances) before it is either utilized for enhanced oil recovery or injected for long-term storage.  All of these operations are well proven and have been adequately demonstrated. See 76 FR 48082-83 (Aug. 8, 2011) (plenary regulatory requirements for CO2 pipelines).  EOR operations using captured CO2 transported in subcritical state via pipeline have been conducted successfully for decades.  Class VI standards for Deepwell injection assure secure storage of captured CO2 for geologic timeframes.  See preamble section V.N.
Commenter 10098 cited the Sierra Club decision, noting that the D.C. Circuit held that dry scrubbing, an "emerging technology" at the time, could not have been an adequately demonstrated technology under Section 111. The commenter noted in the case of dry scrubbing, the court found that there was no record support for the Administrator to make a BSER determination due to (1) the absence of full scale dry scrubber use at utilities; (2) the Administrator's failure to explain how pilot scale testing "may be used to predict performance in full scale plants throughout the industry;" and (3) the absence of test data for different types of coals. Without data showing that dry scrubbing would actually allow coal-fired EGUs of various types to achieve the NSPS, it could not be considered to be adequately demonstrated. The commenter stated that dry scrubbing at the time of the Sierra Club decision was ahead of where CCS is today as no full scale CCS unit has yet been installed and it has not "adequately demonstrated." 
 EPA's final BSER determination is entirely consistent with the D.C. Circuit's analysis of availability of dry scrubbing in the extended footnote in Sierra Club.  The court did not hold that a technology must be in full-scale use before it could be considered "adequately demonstrated" for purposes of section 111.  Rather, the court indicated that EPA failed to explain how pilot scale testing predicted full-scale performance.  The court (in a passage not cited by the commenter) contrasted this situation with the standard based on baghouse performance, which also reflected pilot scale data.  There, the court found sufficient record evidence justifying that pilot scale baghouse performance could be scaled up (657 F. 2d at 382), and that inconsistent test data from a single larger facility reflected inefficient design and operation.  Id.  Thus, the case stands for the proposition that pilot scale data alone can be sufficient to justify that a technology is adequately demonstrated, provided there is a reasonable explanation of how the technology (and its level of performance) can be scaled up.
The record supporting technical feasibility and availability of partial CCS at full scale commercial operation is stronger than the record justifying demonstration of baghouses in Sierra Club.  Most obviously, the final standard reflects successful, full-scale operation of both pre- and post-combustion CCS.  Second, EPA has explained how CCS technology in full-scale use in other industry sectors may reasonably be transferred to EGUs.  See preamble section V.E.2.  The record further explains in detail how CCS can be implemented at full scale.   The NETL reports contain hundreds of pages of detailed, documented explanation of how every aspect of full- and partial-scale CCS can be implemented at full-scale for both PC and IGCC facilities.  Natural Resources Defense Council v. EPA, 655 F.2d 318, 333 (D.C. Cir. 1981) ("the agency need only identify the major steps necessary for development of the device, and give plausible reasons for its belief that the industry will be able to solve those problems in the time remaining."). For example, the NETL reports provide a detailed description of the following systems projected to be needed for a supercritical PC to capture CO2: coal and sorbent receiving and storage, steam generator and ancillaries, NOx control system, particulate control, flue gas desulfurization, flue gas system, CO2 recovery facility, steam turbine generator system, balance of plant, and accessory electric plant, and instrumentation and control systems.  Moreover, the AEP Front End Engineering and Design (FEED) Report,  prepared after conclusion of the development study, describes in detail precisely how the development scale CCS could be successfully scaled up to full scale operation for post-combustion carbon capture at a PC plant.  According to the FEED report, the challenge is "operating a complex system of chemical processing equipment [for post-combustion CO2 capture], typically designed with a chemical plant operations philosophy of high consistency and low variability, with a continuously variable feedstock of flue gas, to produce a highly consistent, high purity ... CO2 product."  FEED Report p. 11.  Chapter 6 of the Report then details how to do so, discussing the chilled ammonia process, process chemistry and process equipment (flue gas cleaning and cooling, CO2 absorption, water wash and CO2/NH3 stripping, refrigeration system, and high pressure regeneration and compression).  AEP concluded that it "has a high level of confidence in the robustness of the developed design .....".  Id. p. 64.  See also preamble section V.G.3.
6.3.3 The Range of Emission Limits EPA Is Considering Cannot Be Achieved by a Coal-Fired EGU without the Use of CCS
Commenters 3176, 3360, 6949, 7433, 7977, 8974, 9422, 9590, 10024, and 10393 stated that coal fired plants would have to install CCS to meet EPA's proposed standard. Commenter 7433 further added that this appears to be a mandated work practice and that EPA has not made the findings to justify imposition of a work practice required by CAA section 111 (b)(5). 
The commenters suggest that the proposed standards of performance would require the installation of CCS technology.  According to Commenter 7433 this would contradict CAA requirement in section 111 (b)(5) of the Act . 
      "...nothing in this section shall be construed to require, or to authorize the Administrator to require, any new or modified source to install and operate any particular technological system of continuous emission reduction to comply with any new source standard of performance."
These comments are mistaken.  The final standard is a performance standard which may be met by any means of a source's choosing.  EPA specifically notes that there are alternative compliance paths to achieve the promulgated standard of 1,400 lb CO2/MWh-gross for both PC units and IGCC units, including co-firing with natural gas without using CCS.   
Similarly, Commenters 1959, 8032, 8348, 8923, 9408, 9666 and 9471 stated that achieving the proposed emissions limit at a coal-fired unit can only be accomplished by at least partial CCS however the technology has never been commercially deployed. Additionally, Commenter 9471 noted that CCS has not been demonstrated as the best system when costs, environmental impacts and energy requirements are considered. Commenter 1959 further stated requiring CCS would remove coal from use as a hedge against natural gas swings and is costly.
As previous stated, the EPA has shown that partial CCS has been adequately demonstrated and is commercially available for deployment at new coal-fired utility boilers and IGCC EGUs.  As just described above, the standards do not require utilization of partial CCS technology.  Responses to comments related to cost of the technology are in unit below; see also preamble section V.I.
Likewise, Commenter 10239 stated that EPA has not identified a single commercial-scale EGU that can meet the proposed emission limit using CCS or any other technology nor is CCS adequately demonstrated, as determined by past BACT determinations and EPA's own guidance.
The EPA has identified a commercial-scale EGU that can meet  -  and currently is meeting  -  the emission limit using CCS technology.  The SaskPower Boundary Dam facility is capturing 90% of the unit's CO2 emissions using commercially available carbon capture technology (from Shell Cansolv; http://www.shell.com/global/products-services/solutions-for-businesses/globalsolutions/shell-cansolv/shell-cansolv-solutions/CO2-capture.html).  The facility's emissions are well below the 1,400 lb CO2/MWh-gross standard. Actually the  emissions at the Boundary Dam facility must be below 1,400 lb CO2/MWh as Canada's emission standard is 0.42 tonnes CO2/MWh, which is roughly equivalent to about 925 lb CO2/MWh.  The plant's operations with CCS are so successful that POWER magazine has awarded Boundary Dam its power plant of the year accolade (August 1, 2015).
Commenter 9666 stated that EPA normally invites discussion regarding achievable emission limits, however they have not allowed outside analysis because no full-scale EGUs have deployed CCS.
The EPA has engaged with a diverse set of stakeholders and specifically requested comment on the achievability and feasibility of the proposed emission limits.  As just described above, the Boundary Dam plant is an example of a full-scale, fully-integrated EGU that is successfully deploying full CCS.
Commenter 9666 asserted that any emission limit within the suggested range lead to an arbitrary and unachievable range of possibilities, including CCS. The commenter stated that EPA must withdraw its proposal with respect to coal-fired EGUs and reissue it with an emission limit that may be met with ultra-supercritical boiler designs.
The EPA stands by its determination that partial CCS is adequately demonstrated, that it is technically feasible, and that it can be implemented at a cost that is not exorbitant. See preamble section V.
Similarly, Commenter 10952 asserted that BSER is arbitrary and otherwise not supported by law, fact or adequate demonstration.
The EPA stands by its determination that partial CCS is adequately demonstrated, that it is technically feasible, and that it can be implemented at a cost that is not exorbitant. A detailed description of the BSER determination is found in the preamble section V. of the final rule. As shown in that preamble discussion, it is supported by law, fact and adequate demonstration.
Commenter 9664 asserted that the NSPS emission limits must reflect those achievable through application of the best emission reduction system which the Administrator determines has been adequately demonstrated, however the demonstration may be based on reasonable projection (Sierra Club, 657 F.2d at 298). The commenter further noted that the proposal does not mean that all existing sources are able to meet the new source standards or even that the available technology are in active use in the industry at the time of the rulemaking as long as appropriate lead time is provided (Portland Cement I, 486 F.2d at 391).
The EPA agrees with this interpretation.
6.3.4 CCS Technical Issues
Commenter 10239 noted that permit writers have uniformly rejected CCS after concluding that it is technologically infeasible, prohibitively expensive, or both and the EPA has uniformly supported these decisions. The commenter provided three examples where EPA did not question conclusions made by state agencies regarding BACT analyses that rejected CCS due to such considerations as parasitic energy load, the lack of a sequestration site, excessive transport costs, logistical challenges, and property right issues.
 The commenter cites to individual permit determinations reflecting performance of Best Available Control Technology (BACT) per CAA section 169 (3).  None of these permits involved determinations by EPA for coal-fired EGU.  Nor are individual BACT decisions determinative of whether a particular technology is adequately demonstrated for purposes of section 111 (b).  The definition of BACT differs from that of BSER as well.  Nor is EPA's silence with regard to individual state permits at all precedential (or probative at all) for EPA's actions in this rulemaking.  See generally preamble section XII.C.
Commenter 10239 discussed how carbon capture from natural gas streams cannot establish that CCS is adequately demonstrated for coal-fired EGUs. The commenter described differences in the processes needed to capture CO2 from power plant combustion stacks, including different amines and different characteristics of natural gas streams and flue gas combustion streams.
Commenters 9426 and 10098 stated that while it is true that natural gas sources have historically separated CO2 from natural gas streams, the processes are significantly different than the ones that are needed to capture CO2 from power plant combustion stacks. Commenter 100098 stated that the differences include: 
   * the need for primary amines like MEA rather than tertiary amines for the absorption process,  
   * the variability, number and types of contaminants in the gas stream characteristics, and
   * the tolerance needs of the catalyst (e.g., amines must be active at a very low CO2 partial pressure, must also be capable of tolerating nitrogen oxide and oxygen contamination) 
Commenter 10618 stated that EPA incorrectly uses the experience of other industries to support their evaluation of CCS for fossil fuel-fired electric generating sources. For example, EPA notes in the proposal that "the capture of CO2 from industrial gas streams has occurred since the 1930's using a variety of approaches." For EPA to suggest that capture technologies should be readily transferable to coal-based electric generating units because of a long history of use in other industries ignores the multitude of technical, process design, and operational differences between the "industrial gas streams" referenced and a coal-based power plant. It also ignores the significant difference in the quantities and end use of the captured CO2, which will be orders of magnitude greater from coal-based generation units than that for most "industrial gas streams." In addition, the likely end-use for coal-based CO2 will be geologic sequestration or enhanced oil recovery processes, which pose much different challenges than capture from industrial gas streams "to produce food and chemical-grade CO2."
Therefore, Commenters 9426, 10098, and 10618 asserted that EPA must adequately demonstrate the use CCS technologies in power plants rather than a different, irrelevant industry.
The EPA agrees that the separation and capture of CO2 from natural gas process is not the same as separation and capture of CO2 from the flue gas stream of a fossil fuel fired EGU.  However, the EPA does believe that the experience gained from those operations has informed  -  and continues to inform  -  the development of very similar (amine-based) CO2 capture systems. The EPA has not used those systems as the principal basis for its "adequately demonstrated" determination.  Rather, it has used the accumulated experience of CO2 capture in various industrial sectors  -  especially those experiences at fossil fuel fired EGUs such as the Boundary Dam facility in Saskatchewan, Canada. 
Similarly, Commenter 9780 stated that even in cases where the CO2 is captured from an EGU, such as the Searles Valley Mineral Soda Ash plant, the process is not analogous to CCS integrated with a full-scale EGU due to the difference in volume and the added responsibility of EGUs to reliably supply power to the grid. 
The EPA agrees that the separation and capture of CO2 from non-EGU industrial facilities can differ from separation and capture of CO2 from the flue gas stream of a fossil fuel fired EGU.  However, the EPA does believe that the experience gained from those operations has informed  -  and continues to inform  -  the development of very similar (amine-based) CO2 capture systems. The EPA has not used those systems as the principal basis for its "adequately demonstrated" determination.  Rather, it has used the accumulated experience of CO2 capture in various industrial sectors  -  especially those experiences at fossil fuel fired EGUs such as the Boundary Dam facility in Saskatchewan, Canada.
Commenter 9505 stated that the proposal fails to explore and explain the problems of using CCS technology on a commercial scale, and EPA must do this prior to finalizing any regulation that establishes CCS as the BSER. The commenter referenced numerous court decisions regarding the need for demonstration of commercial scale systems.
Commenter 9661 stated that CCS integrated with electricity generation is not commercially available or technically feasible.  In addition, the commenter stated that it is very unlikely that a new coal unit would be built, even if CCS was commercially available. Due to its high costs, state public utility regulators nor any utility would approve construction for a new coal plant. The commenter continues that this rule will not allow the development of this technology to progress, and that this rule should be based on the best demonstrated technology. EPA may then assess the status of CCS development and deployment during the CAA mandated review of the proposed NSPS in eight years. 
The EPA notes that while the commenters claims that "CCS integrated with electricity generation is not commercially available or technically feasible", the facts show that it clearly is both technically feasible and commercially available. The SaskPower Boundary Dam facility is currently using commercially available Shell Cansolv technology to capture CO2 at full-scale. The captured CO2 is being transported for use in EOR operations or for long term sequestration. Boundary Dam Unit 3 (BD3) was recently awarded POWER Magazine's "Plant of the Year" award. (www.powermag.com/saskpowers-boundary-dam-carbon-capture-project-wins-powers-highest-award/). In recognizing the Boundary Dam Unit 3 plant, with they described as "the most interesting and worthy project worldwide", POWER noted that "the SaskPower team has taken what actually constitutes a giant leap for the coal-fired power industry".
 Indeed, even before Boundary Dam started operating, Alstom Senior Vice President for Power and Environment Policies MacNaughton was extolling CCS technology after successfully installing it at the existing AEP Mountaineer coal-fired EGU:  "The technology works" and "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 sources, such as wind, solar, geothermal, hydro and nuclear."
Commenter 9505 stated that several government entities have concluded that CCS technologies are not commercially viable, citing the Report of the Interagency Task Force on Carbon Capture and Storage the DOE FY 2014 Budget Request, Vol. 3.
 These statements were in a different context: deployment of full scale CCS, and retrofitting CCS to existing facilities on a widespread scale.  The final standard of performance is not based on full CCS nor is there an expectation that it will require widespread deployment of CCS technology.  
Commenter 9505 stated that rather than follow the statutory text, EPA effectively rewrites Section 111 requirements to justify the proposal's BSER determination. According to the commenter, to justify its BSER determination, EPA crafts from whole cloth a 'technical' feasibility benchmark in place of the 'adequately demonstrated' standard, and rather than assessing whether CCS technology is reasonably reliable, reasonably efficient, and capable of controlling pollution without imposing exorbitant costs on the commercial scale, the proposal looks to whether the separate components of CCS are technically feasible. The commenter stated that any BSER discussion that does not address whether the elements of CCS can be integrated at a commercial scale with the generation of electricity is flawed.
Many of these issues are addressed in chapter 2 of this RTC.  In brief, EPA's analysis of whether partial CCS is adequately demonstrated tracks the language first enunciated in Essex Cement (486 F. 2d at 433) and explains why: the technology is reasonably reliable (i.e. technically feasible under the range of operating conditions under which it would operate), reasonably efficient, and capable of performance at commercial scale without exorbitant costs.  Boundary Dam and Dakota Gasification are both full scale operations where CCS is operating successfully. Although Dakota Gasification does not generate electricity, the process by which syngas is generated is equally usable by IGCC or chemical gasification (see section V.E.2 of the preamble to the final rule). 
Commenter 10036 stated that more research on CO2 compression and transportation is required before the technology is feasible for new power plants. Commenter referred to specific NETL research testing different projects that will improve the components of CCS for large-scale application. 
Standards for CO2 pipelines under 49 CFR Part 195 are well established and assure safety of transported CO2 of whatever origin.  
Commenter 9770 stated that EPA would need to demonstrate that existing infrastructure-pipelines and CO2 storage exists to safely sequester large amounts of CO2 across the country before the technology is considered achievable. 
EPA has already made (unchallenged) findings that the existing regulatory structure for CO2 pipelines assures safety of transported CO2.  See 76 FR at 48082-83 (Aug. 8, 2011); 79 FR 352, 354, 358-59 (Jan. 3, 2014).  The EPA likewise reasonably believes that the Class VI rules for geologic sequestration of CO2, in concert with the GHGRP subpart RR reporting provisions, provide assurance that CO2 will remain sequestered for long-term storage without endangering underground sources of drinking water and without release to the atmosphere. 
Commenter 10095 stated that carbon capture has not been "adequately demonstrated" in a pre or post-combustion application.  The commenter described pressure swing absorption and temperature swing absorption, both of which are being researched. The commenter provided a table showing limited pre and post-combustion carbon capture projects referenced in the proposal and noted that none of these projects is commercial-scale and none has been proven to deliver the reliable, continuous CO2 removal needed for compliance with this proposal.
Commenter 10618 stated that while pre-combustion, post-combustion and oxy-combustion capture systems are technically feasible, they have not been adequately demonstrated at a coal-based power plant on a commercial scale. The commenter continues that this has certainly not been demonstrated as an integrated process with CO2 utilization or storage.
Commenter 10039 stated that EPA did not consider the stack conditions differences when a CCS system is operated and when it is not operated. When carbon capture is being operated, the flue gas stream is colder, denser and lower in volume, which effects the concentrations of other pollutants in the flue gas stream. These pollutants are regulated by the EPA and may not be able to meet regulations without additional equipment with a CCS system. This could also subject a plant to contribute analysis under PSD. Commenter saw no indication that EPA made an analysis of this effect in the docket.
Commenter 2471 stated that EPA's support for CCS makes false assumptions, including the ability of CCS to separate, inject and hold or store CO2 deep into saline formations across the US for hundreds and perhaps thousands of years.
Commenter 9770 stated CCS is not an "adequately demonstrated" system of emission reduction and the acreage requirements for installation of carbon capture, about 6 acres of surface land, has not been demonstrated to be achievable in most areas of the country where power plants are located. According to the commenter, no such land exists around most municipal power plants in Minnesota as they were constructed inside city limits.
Commenter 10095 and 10618 indicates that neither pre- nor post combustion CCS is demonstrated.  In fact, both are demonstrated at full scale in commercial applications.  See preamble sections V.D.2 and V.E.2. Commenter 10095 also mentions pressure swing adsorption (PSA) and temperature swing adsorption (TSA) technologies. The EPA notes that PSA and TSA technologies are both potential post-combustion capture technologies involving solid sorbents.  The EPA is aware of research efforts in this area; however, the EPA is unaware of any larger scale demonstration projects or larger scale implementation of either technology. As such, these technologies were not considered as potentially being part of the best system for reduction of CO2 emissions from fossil fuel-fired EGUs. A more in-depth discussion of carbon capture technologies is provided in a Technical Support Document (TSD)  -  "Literature Survey of Carbon Capture Technology"  -  available in the rulemaking docket  -  EPA-HQ-OAR-2013-0495.
 Regarding Commenter 10039's assertions that the EPA did not consider impacts of CCS on stack conditions and the resulting effects on other pollutants. The EPA first notes that meeting the standard would only require a CCS system that treats a small portion of the bulk flue gas (~ 20%).  Further, the use of post-combustion chemisorption-based capture systems (primarily amine-based) will require added heat to desorb the captured CO2 and regenerate the solvent.  The EPA also notes in the final preamble that ... "[M]any post-combustion solvents will also selectively remove other acidic gases such as sulfur dioxide (SO2) and hydrochloric acid (HCl), which can result in degradation of the solvent. For that reason, the CO2 scrubber systems are normally installed downstream of other pollutant control devices (e.g., particulate matter and flue gas desulfurization controls) and in some cases, the acidic gases will need to be scrubbed to very low levels prior to the flue gas entering the CO2 capture system. See also RIA chapter 5 (quantifying SO2 reductions resulting from this scrubbing process). 
 Commenter 9770 indicates that siting CCS requires considerable land, but appears to equate that issue with retrofitting difficulties.  The standard of performance does not apply to existing sources, and new sources can site where there is available acreage (or pursue a compliance alternative not involving CCS or sequestration if it is imperative to site where there is insufficient space).

Geologic sequestration is demonstrated. See Preamble Section V.M and V.N. The EPA has issued six Underground Injection Control permits to two projects under the Class VI program. It would not have done so, and under the regulations could not have done so, without demonstrations that CO2 would be securely confined to prevent the movement of fluids into or between USDWs or into any unauthorized zones. One of these projects was for a steam generating EGU. Furthermore, international experience with large scale commercial GS projects has demonstrated through extensive monitoring programs that large volumes of CO2 can be safely injected and securely sequestered for long periods of time at volumes and rates consistent with those expected under this rule.
 Regarding the comment that installation of carbon capture systems would require acreage that may not be available "in most areas of the country where power plants are located"  -  the commenter seems to confuse requirements for new sources with those for existing sources. The EPA notes that space availability is one of the concerns expressed by the agency in considering the potential for retrofit CCS technology to be part of the BSER for emission guidelines for existing fossil fuel-fired EGUs. The EPA did not find retrofit CCS technology to be part of the BSER for existing sources and there is no requirement to add CCS technology to those sources. However, developers of new sources  -  those that have not yet been constructed  -  have the ability to select the site for the new facility in a location that ensures adequate space for the carbon capture system. 
Commenter 10952 referenced EPA's permitting guidance for greenhouse gases and noted that in this proposal EPA fails to disclose whether it followed its own longstanding policy that is to actually look at real data associated with actual BACT determinations where carbon capture was considered as required by EPA permitting guidance and to gauge whether carbon capture is 'available' is for widespread implementation. The commenter stated that best available information shows that EPA did not consider most relevant technical data in its determination that carbon capture is BSER, referencing the 2011 approval of a BACT determination for Wolverine Power Supply Cooperative, Inc. in which CCS was rejected as too expensive in addition to other rejection factors.
EPA first notes that the Guidance document does not create "requirements".   It provides non-binding guidance.  Moreover, the Guidance does not address CCS for coal-fired EGUs specifically, contain any specifics about CCS cost, operating mechanics, use within various industries, or otherwise.  Rather, in general terms, the Guidance advises that "although CCS is not in widespread use at this time, EPA generally considers CCS to be an `available' add-on pollution control technology for facilities emitting CO2 in large amounts and industrial facilities with high-purity streams."  Guidance p. 35.  EPA continued that CCS might be rejected in individual `top-down' BACT analyses, and concluded that "[w]hile CCS is a promising technology, EPA does not believe that at this time CCS will be a technically feasible BACT option in certain cases."  Id. p. 36.  The EPA thus does not believe that this general guidance, issued years before the present proceeding, addressed to multiple industries and not specific to coal-fired steam electric generating units, is binding in any way, or is especially probative of whether partial CCS is BSER for coal-fired EGUs.  See preamble section XII.C.
Commenter 9666 provided discussion about each of the three methods of CO2 capture, noting that none has been adequately demonstrated.
 See preamble sections V.D. and E.
Commenter 9202 encouraged EPA to tighten the rule with regard to CCS technology and supported the use of captured CO2 for enhanced oil and gas recovery
The EPA is not predicating its cost analysis on EOR revenue opportunities, but of course such opportunities exist.  See preamble section V.H.8.
Commenter 9666 provided a figure titled Schedule of Pilot and Demonstration Plants Employing Carbon Capture with Enhanced Oil Recovery or Sequestration, in which various CCS projects are identified. The commenter noted that a minimum of two years operation is required to synthesize data into CO2 capture design lessons, and additional issues separate from CO2 capture will require at least an additional 2-4 years of observation beyond first CO2 injection.
The EPA notes that there is already good information on the operation of CCS demonstration projects as described in the final rule preamble in section V. The EPA also notes that the Boundary Dam project  -  a full-scale, fully integrated utility boiler that is implementing full CCS is now operational. To facilitate the transfer of the technology and to accelerate development of carbon capture technology, SaskPower has created the CCS Global Consortium.  This consortium provides SaskPower the opportunity to share the knowledge and experience from the Boundary Dam Unit #3 facility with global energy leaders, technology developers, and project developers. SaskPower, in partnership with Mitsubishi and Hitachi, is also helping to advance CCS knowledge and technology development through the creation of the Shand Carbon Capture Test Facility (CCTF).  The test facility will provide technology developers with an opportunity to test new and emerging carbon capture systems for controlling carbon emissions from coal-fired power plants. The DOE also sponsors testing at the National Carbon Capture Center (NCCC). The NCCC  -  located at Southern Company's Plant Gaston in Wilsonville, AL  -  provides first-class facilities to test new capture technologies for extended periods under commercially representative conditions with coal-derived flue gas and syngas. The EPA has provided much discussion regarding the status of CO2 injection in preamble section V.M and elsewhere throughout this Chapter of the RTC.
Commenter 9666 discussed the difficulties of scaling pilot plant, demonstration, and early commercial tests to large generating capacities. The commenter noted concerns with the large scale of the necessary control equipment, stated that generalizing equipment design for each of post-combustion, pre-combustion, and oxy-combustion CO2 control methods will require experience with at least the three "ranks" or categories of coal broadly used in the U.S., as well as various sites; and the need for assuring the components work as an integrated system in a seamless manner. The commenter concluded that the need to scale, generalize, and integrate the operation of these processes requires additional demonstrations
Commenter 10095 stated that the full-scale integration of CCS at multiple commercial EGUS is extremely important before considering the technology BSER. Even non-natural gas EGUs face continuous load changes due to customer demand and dispatch.  Commenter agreed with EPA for not making CCS BSER for NGCC units due to frequent load changes, but challenged that this would occur for the non-NGCC fossil fuel units also. It is unknown whether CCS operations can withstand the ramping and shedding transitions to meet demand. 
Commenter 10618 identified a set of items to indicate the integration of CCS and coal-based generation technologies has many challenges. The commenter begins that chemical plants which have demonstrated CCS operation at steady-state operating conditions, as opposed to the EGU dynamic operation. In addition, some capture systems may have a capture system design specifications requiring other treatment and equipment. In addition, the capture systems may have high power or steam demands. The commenter continued stating that a commercial-scale CCS system would encompass a large amount of plant real estate for capturing just 20%, as demonstrated by AEP's Mountaineer Plant CCS Project. The commenter finished pointing out that the EGU's power production may become limited by the CCS and EOR systems' demands for CO2 instead of customer demand leading to availability risks.  
Commenter 10052 stated that to meet the proposed standard, a typical 500 MW plant would require injection capability of more than 2 million tons per year, which over a 20 year period would require storage in excess of 40 million tons. According to the commenter, to date, no geologic sequestrations have operated at this injection rate or demonstrated this level of capacity. The commenter also noted that the increased auxiliary load for CO2 capture equipment is likely to result in an overall decline in plant efficiency, thus increasing the real CO2 emission rate.
The EPA has discussed scaling issues and challenges in the preamble (see discussions in the section V of the preamble regarding the FEED studies performed by AEP and Tenaska). The AEP FEED study indicates how the development scale post-combustion CCS could be successfully scaled up to full-scale operation. See Section V.D.3.b.  Tenaska Trailblazer Partners, LLC also prepared a FEED study  for the carbon capture portion of the previously proposed Trailblazer Energy Center, a 760 MW SCPC EGU that was proposed to include 85 to 90 percent CO2 post-combustion capture. Tenaska selected the Fluor Econamine FG Plus[SM] technology and contracted Fluor to conduct the FEED study. One of the goals of the FEED study was to "[c]onfirm that scale up to a large commercial size is achievable." Tenaska ultimately concluded that the study had achieved its objectives resulting in "[c]onfirmation that the technology can be scaled up to constructable design at commercial size through (1) process and discipline engineering design and CFD (computational fluid dynamics) analysis, (2) 3D model development, and (3) receipt of firm price quotes for large equipment." The EPA also disagrees that the each of the carbon capture options (post-combustion, pre-combustion, and oxy-combustion) must be demonstrated with three ranks of coal at various sites to ensure that components work.  The EPA has provide considerable evidence that storage capacity is available broadly and carbon capture technologies have been  -  and are being  -  demonstrated by facilities utilizing a variety of fuels, including lignite, petroleum coke, and sub-bituminous and bituminous coals. Regarding the effect of load changes on CCS system operation, the EPA discusses this in preamble section V.J.1 and also in a Technical Support Document (TSD) on Achievability of the Standards available in the rulemaking docket. The EPA agrees that some capture systems may require additional control equipment to be installed upstream to remove flue gas components that may degrade the capture solvents (especially amine-based solvents). These considerations have been included the cost estimates developed by DOE/NETL and used by EPA in this final rulemaking. The EPA has specifically addressed energy demands (and increased water use) in the preamble in sections V.N and V.O.

As described in the preamble, Boundary Dam has been operated successfully since October 2014, showing that captured CO2 from a fossil-fired EGU can go to both EOR, and the excess to a deep saline formation, while still meeting customer demand.

Geologic sequestration is demonstrated. See Preamble Section V.M and V.N. The EPA has issued six Underground Injection Control permits to two projects under the Class VI program. 
The Archer Daniels Midland Class VI permit is for injection and sequestration of an estimated 5.5 million tons of CO2. The FutureGen Class VI permits are for 22.5 million tons of injected CO2. These projects are of a magnitude comparable to the (hypothetical) example in the comment. We repeat that the EPA's findings, and administrative record supporting those findings, is that each site was capable of safely sequestering the injected CO2 indefinitely consistent with the requirements of the Class VI regulations. As explained in section V.N.3 of the preamble to the final rule, these standards also assure that there will be no release of sequestered CO2 to the atmosphere. Additionally, there are several large scale CO2 sequestration projects including the Illinois Basin Decatur Project and the Cranfield (Tuscaloosa) Project that demonstrate that storage of large amounts of CO2 can be achieved. In April 2015, DOE announced that CCS projects supported by the department have safely and permanently stored 10 million metric tons of CO2, which is the same order of magnitude expected for an EGU. Furthermore, international experience with large scale commercial GS projects has demonstrated through extensive monitoring programs that large volumes of CO2 can be safely injected and securely sequestered for long periods of time at volumes and rates consistent with those expected under this rule.
Commenter 9666 stated that recognizing the limited experience with oxy-combustion capture technology, EPA noted in its Technical Support Document addressing EPAct that the proposed rule relies only on post- and pre-combustion capture as the basis for its BSER determination for Subpart Da units
Yes, that is correct.
Commenter 966 discussed that one additional aspect of CCS is the implication for increased water use, which escalates significantly for CO2-control power stations. The commenter discussed a DOE study on water use patterns for different types of coal plants. 
Commenter 9497 stated that while the Kemper facility has access to a plentitude of water for its operations, many other plants in the US would not be able to overcome the obstacle of an adequate water supply. Currently, Kemper has a 90 acre reservoir, which is a 50 day supply.
See preamble section V.O.2.
Commenter 10097 stated the proposed BSER of partial carbon capture is not available over reasonably wide geographic areas and is therefore not adequately demonstrated. According to the commenter, although the proposed BSER does not include necessary infrastructure availability such as CO2 pipelines, deep well sequestration or EOR fields and other apparatus necessary to meet the proposed NSPS, such infrastructure must nonetheless be available. The commenter noted that the proposal glosses over the availability of infrastructure needed to transport and sequester the CO2 captured by coal-fired EGUs with the proposed BSER, because there is little infrastructure available to support this requirement.
Commenter 10504 stated requiring new coal-fired EGUs in Alaska, especially in the interior, to implement partial CCS would require a significant amount of infrastructure that is currently not available or even considered. It is simply not feasible given the unique circumstances in Alaska.
Commenter 10052 stated EPA's assessment that CO2 has been safely transported via pipelines in the U.S. for nearly 40 years and that 95 percent of the 500 largest CO2 point sources are within 50 miles of a possible geologic sequestration site is broadly conclusory and does not account for the geographically diverse and distant nature of power plant locations in much of the United States.
Commenter 9683 stated the feasibility of CCS has not been shown for its constituent parts, capture and storage, and faces very wide variations in technical feasibility regionally.
Commenter 7977 stated that the D.C. Circuit Court has ruled that Section 111 of the CAA standards "must not give a competitive advantage to one State over another in attracting industry" citing Wisconsin Elec. Power Co. v. Reilly, 893 F.2d 901, 918 (D.C. Cir., 1990). The commenter continued that geological features necessary for EOR and sequestration are not evenly distributed throughout the country, and as a result, the proposed regulation will have significant disparate geographic impacts. According to the commenter, the implementation of the system for pollution control must not be dependent on geographical distinctions, such as EOR, geological formations for storage capability, and feasibility of installing pipelines for CO2 transportation. The commenter also stated EPA must identify and practically address the conflict between the inability of some fossil fuel-fired EGUs to locate in certain areas and the legislative intent behind the NSPS to encourage the use of local fuels. The commenter also stated EPA must also consider increased fuel transportation costs and increased electricity transmission costs incurred by locating an EGU facility proximate to geologic formations favorable to CO2 sequestration. 
The commenter's (commenter 7977) citation to the WEPCO decision is obscure. The case (decided, incidentally by the 7[th] Circuit, not the D.C. Circuit) deals primarily with the issue of what activities constitute a modification.  To the extent the case deals with the issue of fuel use, the case holds that section 111 standards are to be based on use of technological controls and that fuel switching is not a permissible means of meeting them.  893 F. 2d at 918-19.  As to the commenter's argument that BSER cannot be dependent on types of control which are geographically limited, EPA notes that this is not the case here.  As discussed in section V.M of the preamble and Figure 1 of the technical support document on geographic availability, there is ample sequestration capacity available in most areas of the country.  EOR opportunities also exist.  These areas also allow, for the most part, ready connection to the electricity grid.  See Figure 2 of the technical support document on geographic availability. There are also alternative compliance pathways for both PC and IGCC sources which would not involve CO2 capture and sequestration at all, and for which there would be no issues of geographic availability.  With respect to the commenter's assertion about Alaska, the EPA disagrees that geologic sequestration is not feasible in Alaska. NETL has noted GS potential in hydrocarbon reservoirs of the North Slope and Cook Inlet because of their proximity to large stationary CO2 sources and the potential for CO2-EOR. NETL has also found that Alaska has potential capacity of 24 billion metric tons in unmineable coal seams alone, or an estimated 610 to 1,420 years worth of emissions from all stationary sources. The development of pipeline infrastructure is proven and, as described in preamble section V.M.5, the operational experience of the oil and gas industry provides confidence that CO2 transportation and storage can be undertaken in a safe and effective way.

The EPA agrees that pipelines of longer or shorter distances than 50 miles may be constructed for compliance with the NSPS. 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 new sources, pipeline distance and costs can be factored into siting and, as discussed in section V.M, there is widespread availability of geologic formations for geologic sequestration. Moreover, data from the Pipeline and Hazardous Materials Safety Administration show that in 2013 there were 5,195 miles of CO2 pipelines operating in the United States. This represents a seven percent increase in CO2 pipeline miles over the previous year and a 38 percent increase in CO2 pipeline miles since 2004. The design, construction, operation, and safety requirements for CO2 pipelines have been proven, and the costs of CO2 pipelines have been taken into account in the development of the standard. 

The commenter mentioned AEP's experience in developing a GS project at Mountaineer. Each sequestration site involves highly site-specific circumstances. A monitoring program and its associated infrastructure (e.g., monitoring wells) and costs will be dependent on site-specific characteristics, such as CO2 injection rate and volume, geology, the presence of artificial penetrations, among other factors. It is thus not appropriate to generalize from AEP's experience, and thus not appropriate to assume that other sites will require the same number of wells for site characterization or injection. In this regard, we note that the ADM and FutureGen permits for Class VI wells involved far fewer injection and monitoring wells than AEP references.  We also note that the Mountaineer project involved a retrofit to an existing facility, which may have increased difficulties because the site was not selected with potential sequestration in mind.
Commenter 8957 provided the following: "In the EPA's discussion on the technical feasibility of carbon capture and storage (CCS), the storage segment relies on existing data from several small scale projects and from the Permian basin injection for enhanced oil recovery (EOR). Part of this information boasts the injection of 93 million metric tons of CO2 from 1972 to 2005 in the Permian basin, which equates to approximately 3.1 million short tons injected per year. It is also stated that 3 8 million metric tons of CO2 were re-emitted from the same project, meaning that only 1.8 million short tons per year of the injected CO2 was sequestered. This translates to 60% retention as compared to the 100% retention assumed by the EPA in establishing the 40% partial CCS requirement. An uncontrolled base plant with an efficiency of 40% and a parasitic load of 6.5% that must have a net electrical output of 500 MW would require an installed capacity of 535 MW and would emit 4.3 million short tons of CO2 while operating at a 100% capacity factor."
The EPA does not agree with the commenter's assertion. In the EOR process some of the CO2 is recovered with the oil and the recovered CO2 is separated from the oil and recycled so that it can be re-injected into the reservoir. Large amounts of CO2 can be stored via residual trapping, solubility trapping and stratigraphic trapping. In the example cited by the commenter, 55 million tons of CO2 were stored in the SACROC Unit in the Permian Basin over 25 years. No evidence of leakage was detected.
Post-combustion CO2 Capture
Commenter 9201 stated given the lack of full scale, commercialized, constantly operating post-combustion CCS capture facilities, broad commercial deployment of post-combustion carbon capture cannot be reasonably anticipated to be a demonstrated option until 2020 at the earliest. The commenter noted that EPA's examples of operating post-combustion carbon capture, AES/Warrior Run, AES/Shady Point and Searles Valley Minerals, are comprised principally of small coal-fired boilers with a very small slip-stream capture of CO2 with the CO2 used for commercial purposes such as food or chemicals. The commenter also referenced the two test pilot projects discussed by EPA, AEP/Mountaineer and Alabama Power/Barry, noting that both use different processes and capture technology and they only capture small fractions of CO2 as compared to the requirements of a commercial scale power plant. The commenter also discussed that the only electric power generation projects incorporating carbon capture and reuse for EOR, Sask Power/Boundary Dam and W.A. Parish, remain under construction or at the preliminary engineering study stage. 
 EPA noted at proposal that the Boundary Dam Unit #3 was scheduled to commence operations in the near future, which proved to be the case.  The facility is operating successfully and reliably (the project developer has stated publically that operation is even better than anticipated).  See also preamble section V.D. explaining why other facilities provide corroborative information regarding demonstration of post-combustion CCS.
Commenter 9201 stated that the large amount of energy required in regenerating CO2 in amine-based post-combustion technologies, and the extensive number of process steps required, challenges the commercial viability of such processes. According to the commenter, the parasitic energy burden of amine-based post-combustion CO2 control is significant; whereas a conventional pulverized coal-fired plant equipped with FGD for SO2 control and SCR for NOx control will devote 5-6% of the plant output to the environmental control system, post-combustion CO2 control for a comparable new unit will consume more than 19% of the gross plant output. According to the commenter, as a consequence, net thermal efficiency of power generation for a new unit decreases from 39.1% to 27.2% (for a supercritical boiler).
The EPA has specifically addressed energy requirements in preamble section V.O.3. The results in Table 14 in the preamble 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 choose to implement higher levels of CCS will expect higher amounts of parasitic power demand.
Commenter 9666 summarized demonstrated instances of post-combustion CO2 capture and concluded that the sole relevant experience with post-combustion CO2 control is with Plant Barry's 25 MW-equivalent pilot plant. The commenter noted the SaskPower 110 MW Boundary Dam unit may soon be operating and provide similar information. According to the commenter, the small commercial applications (Warrior Run, Shady Point, Searles Valley Minerals) do not transport or sequester CO2 and thus do not provide authentic utility experience or a complete scope of operation. The commenter characterized remaining units as either uncertain in status due to financing or other concerns.
The Boundary Dam facility is in fact now operating successfully  -  See preamble section V.D.2.a.  It is selling much of the captured CO2 and sequestering the remainder. Thus, the facility not only demonstrates feasibility of post-combustion CO2 capture, but successful sequestration of CO2 as well, along with successful transport and use of captured CO2 for EOR.  EPA notes that the commenter correctly anticipated that the facility would be operating and provide information relevant to this proceeding.  The remaining sources mentioned in this comment are discussed in section V.D. of the preamble where EPA explains how information from these sources further supports the BSER determination.  
Commenter 2741 suggested EPA include a provision in the final rule enabling fossil fuel-fired power plants to comply with the carbon dioxide emission standard by capturing carbon through effective, permanent, and commercially promising carbon utilization technologies such as Blue Planet's Liquid Condensed Phase (LCP) platform. According to the commenter, the LCP technology platform offers a unique means of permanently sequestering and utilizing CO2 into high value green building products and highway materials. The commenter explained that the process combines various natural and wastewaters with raw flue gas containing CO2 as inputs and, making use of established water process membrane technologies, produce solutions that are rich in bicarbonate (HCO3 -) ions. The commenter stated that in their second-generation technology, one equivalent of CO2 is being sequestered as solid calcium carbonate material (CaCO3), and the other equivalent of CO2 is evolved as a pure stream, which can be sold for use in EOR, or re-cycled in the LCP process. According to the commenter, Blue Planet's LCP process can capture in excess of 50 percent of the carbon dioxide emissions from a stationary source, enabling a coal-fired power plant to comply with EPA's proposed emission limits for new electricity generating facilities, and because this process uses little energy and creates a number of marketable products, it provides a promising and potentially profitable option to traditional gas separation that turns the conventional assumptions of the economies of carbon capture on their heads.
The final standard is a performance standard, and so does not compel a source to adopt any particular control type.  
Commenter 8952 stated the proposed rule does not suggest that carbon capture is a viable adaptation for a combined cycle, however, it does not explicitly state--but should so state--that carbon capture is not viable for a simple cycle gas turbine. According to the commenter, the operating environment at the exhaust for a simple cycle is much more severe than for the combined cycle, making the application of that technology a near impossibility.
The EPA discusses the technical uncertainties associated with implementation of CCS technology with natural gas-fired stationary combustion turbines in the final preamble.
Oxy-combustion
Commenter 9201 states technical concerns with oxy-combustion technology, including the increased potential for corrosion due to increased SO2 concentrations in CO2 gas streams and long-term research and development needs that are unlikely to be completed in the near future. Commenter 9201 notes that operating experience with oxy-combustion is mainly limited to test facilities. The commenter believes the most significant challenges for oxy-combustion based on conventional cryogenic processes are scale-up and reliability, and the auxiliary power penalty. The commenter states that the auxiliary power penalty negates any cost advantage of oxy-combustion over post-combustion CO2 removal. As a result, the commenter believes that this CCS technology is an unavailable commercial application at this time. 
The EPA did not consider oxy-combustion a potential component of the BSER for new fossil fuel-fired steam generating EGUs. The EPA believes that the technology has not been demonstrated to the extent that both post-combustion capture and pre-combustion capture systems have. Further, importantly, oxy-combustion is not applicable as a partial capture option as it inherently results in a highly enriched flue gas stream. Thus the opportunity to reduce compliance costs by adjusting the capture rate is not available to oxy-combustion systems.
Commenters 9201 and 9666 provide summary information on oxy-combustion projects that are completed, operating or in the process of being designed, constructed or planned in the U.S. and abroad.  
See response to previous comments on oxy-combustion.
Pre-Combustion CO2 Removal
Commenters 9201 and 9666 stated that IGCC equipped with CO2 removal has yet to operate in an integrated system for power production and although several chemical plants in the U.S. use gasification with CO2 recovery, none are primarily designed for or representative of power generation as base load operations. The commenters discussed the demonstrated instances of pre-combustion CO2 capture and noted where DOE provided funds for the partial costs associated with the projects. Commenter 9201 stated that several IGCC units equipped with pre-combustion CO2 removal and designed for power generation have been proposed but only one is under construction, and given the uncertainties in present state-of-art IGCC, broad commercial deployment with carbon capture cannot be reasonably anticipated to be a demonstrated option until 2020 at the earliest. 
The EPA notes in the final preamble that a new IGCC unit will be able to meet the final standard of performance by co-firing with a small amount (< 10%) of natural gas. However, the EPA still finds that pre-combustion carbon capture is a technically feasible and demonstrated technology.
CO2 Transport
Commenter 10095 noted that fossil fuel-fired EGUs cannot control actions of a downstream, third party CO2 off-taker. The commenter further asserted that a robust network of CO2 pipelines, offering power plants multiple CO2 off-taker options is needed to minimize these third-party compliance risks but will require significant investment. Commenter 9197 noted that the EPA's CCS cost estimates do not appear to consider the likelihood that EGUs will be required to rely on third-party CO2 pipeline and sequestration service providers. The need to overbuild will clearly raise costs even further than the EPA estimates.
The EPA's cost estimates do in fact include costs associated with transportation and storage of CO2. See preamble section V.I.5. The United States has a robust pipeline network and the EPA disagrees that the rule will necessitate "overbuilding" of CO2 pipeline systems. The CO2 pipeline network in the United States has almost doubled in the past ten years in order to meet growing demands for CO2 for EOR. CO2 transport companies have recently proposed initiatives to expand the CO2 pipeline network. Several hundred miles of dedicated CO2 pipeline are under construction, planned, or proposed, including projects in Colorado, Louisiana, Montana, New Mexico, Texas, and Wyoming. 
Commenters 10039 and 10095 stated that the EPA cannot rationally conclude that the U.S. CO2 pipeline network is adequate when it is 76 times smaller than the U.S. natural gas pipeline network, which will limit new coal-fired power plants to within proximity to a sequestration site. Commenter 8966 cited CRS' statement that a national carbon pipeline network is several years away. Commenter 10087 also noted that for many locations for coal-fired power plants, such as in the Midwest, there are no existing CO2 pipelines and none proposed. Commenter 8966 noted that the vast majority of the country lacks any sort of dedicated CO2 pipeline network altogether, including virtually the entire U.S. Midwest, Appalachian, and Eastern Seaboard regions. Commenter 10010 noted that CO2 pipelines and storage capacity are not available in Florida. Commenter 9657 notes that the EPA's own analysis notes that northern Georgia has no EOR operations, oil and gas reserves, saline formations, unmineable coal areas, existing or planned CO2 pipelines, or natural CO2 sources, and notes that there are dozens of coal electric generating units in the region that are hundreds of miles from the closest saline formations. 
Commenter 10662 concludes that the EPA has dismissed issues related to the long term storage of CO2 by simply stating that 95 percent of the 500 largest CO2 sources are within 50 miles of a "possible geologic sequestration site," which ignores the significant hurdles that must be overcome. Commenter 10662 noted that even if a state has the requisite geologic formations, facilities would be required either to build in proximity to the formations regardless of other considerations, or to build miles of CO2 pipeline simply to reach the formation. 
Commenters 10023 and 9472 also identified pipeline siting and construction issues as a legal and regulatory impediment to implementation of CCS. Commenter 8949 noted that many regions throughout the United States lack access to suitable storage sites and/or infrastructure to provide access to storage sites, and that there are no companies operating commercially in the United States that offer CCS. Commenter 8949 stated that for those regional locations where Enhanced Oil Recovery (EOR) is a potential option, there remain technical, legal, and cost challenges to siting and constructing pipelines from EGUs to EOR fields.
The EPA does not agree that the transport of CO2 through pipelines is an impediment to compliance with the NSPS. There is a robust regulatory framework in place already that addresses CO2 pipelines. CO2 pipeline specifications  of the U.S. Department of Transportation Pipeline Hazardous Materials Safety Administration found at 49 CFR part 195 (Transportation of Hazardous Liquids by Pipeline) apply regardless of the source of the CO2 and take into account CO2 composition, impurities, and phase behavior. These rules contain (among other provisions) detailed requirements related to reporting, pipeline design (temperature, pressure variation both internal and external, loads, types of pipes, valves and fittings, connections, closure, and leak detection), construction, pressure testing, and corrosion control. CO2-specific provisions require special design for CO2 at low temperatures. 49 CFR section 195.102 (b). These requirements have applied for years, successfully, to compressed, supercritical CO2 captured, transported via regulated pipeline, and used for EOR. Additionally, issues of pipeline availability and use did not pose obstacles to the EPA granting Class VI permits to ADM and FutureGen. Denbury recently completed the final section of the 325-mile Green Pipeline for transporting CO2 from Donaldsonville, Louisiana, to EOR oil fields in Texas, and completed construction and commenced operation of the 232-mile Greencore Pipeline in Wyoming. Chaparral completed an 8-inch, 68-mile CO2 pipeline from fertilizer plant in Coffeyville, Kansas, to an oil field in Oklahoma. These large CO2 pipeline projects demonstrate that long CO2 pipelines can be sited effectively under the current regulatory system. 
The commenters do not address whether new sources could site a source advantageously to account for pipeline availability. Such siting opportunities are, of course, available, as illustrated by the Boundary Dam and Kemper facilities (two of the most recent projects, both of which sited proximate to EOR sources). The EPA thus regards these comments as overstated. In any case, compliance alternatives exist under the final standard which would not necessitate sequestration. 

Additional information about pipeline requirements and availability is discussed in Section V.M.5 of the preamble.
Commenter 8501 stated that the presumptions the EPA makes regarding EOR as an ancillary form of partial CCS are not supportable. There is little discussion of the actual demand of CO2 for EOR operations or pipeline delivery capability of the CO2 to the oil fields. Commenter 9236 noted that many oil fields are not able to utilize CO2 flooding as an enhanced production method and in most cases the oil fields that are amenable to CO2 use are located in remote areas far from electricity load centers, where large power plants would need to be sited in order to meet electric demands. This results in either long pipelines to deliver CO2 to the oil fields or long electric transmission lines to deliver electricity to load centers. Commenter 9666 stated that broad use of both EOR and deep saline reservoirs will require investment in infrastructure for pipeline delivery.
Commenter 9734 stated that any suggestion that CCS for EOR could be accomplished through pipelines from states without EOR opportunities ignores the lack of infrastructure to accomplish this. 
The EPA does not agree that the rule would preclude the development of new EGUs in states that do not have current CO2-EOR operations. New coal-fired EGUs in states or areas in which EOR operations are not available could locate in the proximity of non-EOR sequestration formations such as deep saline formations and transport the captured CO2 by pipeline, or could locate near a sequestration site and transport the electricity generated to customers by electric transmission lines. Additionally, there are alternative compliance paths available to meet the promulgated standard of performance which do not involve sequestration.  
Commenter 9774 noted that the major portion of coal-fired generating capacity in Wisconsin is located in urban areas, and that the EPA should address the difficulties, logistics and significant additional expense related to placing CO2 pipelines in urban areas. Commenter 9201 also noted that existing CO2 pipelines are rare near most population centers, and states with little or no storage capacity would have to construct costly, lengthy and expensive CO2 pipeline systems.
The rule would not affect the ability of existing power plants to operate and would not require or necessitate construction of CO2 pipelines to existing power plants. 
Commenter 10786 noted that no federal agency has given a favorable assessment to associated storage via CO2-EOR as an alternative in an Environmental Impact Analysis ("EIA") conducted under NEPA. Commenter 10786 noted that in FERC's recent final EIA for the Cameron LNG export terminal project, FERC concluded that a CCS-based solution was technically and economically infeasible because the nearest CO2 pipeline (which, in turn, supplied EOR projects) was a mere twenty miles away. FERC also concluded that while closer CO2 pipelines appeared to be available, that CO2 pipeline network "appears to be fully subscribed with CO2" thereby frustrating the ability of the Cameron LNG export terminal to engage in associated storage via CO2-EOR. FERC's analysis of the potential for associated storage via CO2-EOR accurately reflects some of the complexities of the typical EOR situation  -  to wit, even siting one's project within a short twenty miles of an EOR-supplying CO2 pipeline failed to enable the use of CO2-EOR as a control technology.
The rule applies only to new EGUs and the EPA rulemaking process is not related to FERC's review process for proposed LNG export terminals. The EPA has determined that CCS, including construction and operation of CO2 pipelines, has been adequately demonstrated for transporting large volumes of CO2 safely. See Preamble section V.N. 
Commenter 8966 stated that if the proposed rule is enacted, it is highly unlikely that any new coal power plant operator would be able to transport captured CO2 from its facility to a storage site for at least several years. Without the certainty of pipeline network development, few, if any, coal power plants would be built. But without the existence of new plants that use such pipelines, it is equally unlikely that any national pipeline network could develop. Therefore, Commenter 8966 concludes that the EPA must abstain from issuing any CCS-based emissions standards until development of a nationwide CO2 pipeline network is substantially in progress.
Commenters 9600, 10097, and 10952 stated that the proposed rule offers no rational discussion regarding the availability of needed offsite CO2 pipeline facilities required to augment the proposal's identified BSER, without which the rule would allow new sources to capture CO2 emissions and subsequently emit these emissions at the boundary of the source, an irrational result. Commenter 9734 stated that states including Kentucky are not located close to states with EOR sites where captured CO2 could be used, and that any suggestion that CCS for EOR could be accomplished through pipelines from states without EOR opportunities ignores the lack of infrastructure to accomplish this. 

Commenter 950 stated municipal utilities such as CU are very limited in their authority to secure sufficient storage capacity in distant locations or to construct the necessary transportation infrastructure to support long-term CCS. The commenter referenced their own case, for example, the Missouri Supreme Court has held that CU is prohibited from constructing a pipeline by lack of condemnation rights beyond their native counties. See City of Springfield ex rel. Bd. of Public Utilities of Springfield, MO v. Brechbuhler, 895 S.W.2d 583 (Mo. 1995). Thus, under controlling case law, CU can only transport captured CO2 a distance of twenty miles from the source. In addition, the commenter has learned, through a recently concluded DOE-funded research project, that local basal geography and hydrology preclude the long-term sequestration of CO2 in the immediate area. Accordingly, the commenter stated that logistical hurdles are very much in play in Springfield, Missouri, as they would be for any number of municipal utilities in the Midwest. The commenter noted that EPA's current proposal does not address how these hurdles can be overcome by generators in our situation. Therefore, according to the commenter, the compliance technology is inapplicable and sources such as our own would be unable to construct either a conventional coal-fired steam unit or an integrated gasification combined cycle (IGCC) unit in the future. The commenter noted that this is immediately problematic in that the existing natural gas supply to Springfield is incapable of supporting a future natural gas combined cycle (NGCC) unit and although the supply problem might be rectifiable in the future, CU would be totally dependent on outside interests to do so.

Commenters 9407 and 10097 asserted that the lack of availability of CO2 pipelines will prevent affected facilities from meeting the NSPS and applying the BSER. Commenter 9407 states that although the proposed BSER does not include necessary infrastructure availability such as CO2 pipelines, deep well sequestration or EOR fields and other apparatus necessary to meet the proposed NSPS, such infrastructure must nonetheless be available. The commenter asserted that the EPA proposal glosses over the availability of infrastructure needed to transport and sequester the CO2 captured by coal-fired EGUs with the proposed BSER, because there is little CO2 pipeline infrastructure available to support this requirement. A BSER must be available immediately as opposed to even one or two years hence. Commenters 9409, 9600, and 10097 state the CO2 pipeline infrastructure needed to transport the captured CO2 must be available immediately in order for a facility to capable of achieving the proposed NSPS. Commenters 9407, 10097, and 10952 assert that the CO2 pipeline transportation infrastructure needed to comply with the NSPS does not exist and will not exist within the foreseeable future.
The EPA does not agree that a nationwide CO2 pipeline network must be developed in order for the EPA to issue this rule or that there needs to be changes in how CO2 pipelines are operated. At least one study estimated that of the 500 largest point sources of CO2 in the United States, 95 percent are within 50 miles of a potential storage reservoir. See preamble section V.I.5. For new sources, pipeline distance and costs can be factored into siting, and there is widespread availability of geologic formations for GS. The design, construction, operation, and safety requirements for CO2 pipelines have been proven, and the U.S. CO2 pipeline network has been safely used and expanded. Moreover, PHMSA data show that in 2013 there were 5,195 miles of CO2 pipelines operating in the United States. This represents a seven percent increase in CO2 pipeline miles over the previous year and a 38 percent increase in CO2 pipeline miles since 2004. GS capacity is available domestically in the form of geologic formations (e.g., deep saline formations) and EOR sites in most areas of the country. Where such GS capacity is unavailable, electricity demand in those areas can be served by coal-fired power plants built in neighboring areas with GS. See Figure 1 of TSD on geographic availability showing that virtually all areas of the continental United States are within 100 kilometers of a geologic formation or EOR site (the length of pipeline assumed in the EPA's cost estimates), and may be served by coal-fired electricity generation built in nearby areas with geological sequestration, and this electricity can be delivered through transmission lines. For other of those areas, coal-fired power plants are either not being built due to state law restrictions, or other available compliance alternatives exist allowing a new coal-fired power plant meeting the promulgated NSPS to be sited. See also previous responses and Section V.M.5 of the preamble.
Commenter 10660 stated that siting of CO2 pipelines raises technical considerations that have yet to be resolved at scale and in all geographies. Commenter 10662 stated that the EPA simply dismisses CO2 transportation and storage concerns and assumes that effective sequestration will occur. The transportation component of CCS is well-established as technically feasible and is not a significant component of the cost of CCS. However, the EPA dismisses concerns over CO2 pipelines and does not take into account the scale of transportation infrastructure and investment required to enable large-scale deployment of CCS. 
The EPA's cost estimates include reasonable cost estimates for CO2 pipelines. See section V.I.5 of the final rule preamble for the NSPS. Moreover, there are alternative compliance pathways for new sources that do not involve geologic sequestration or other CO2 storage. Finally, the EPA is not "assuming that effective sequestration will occur". The EPA is reasonably relying on the robust and rigorous Class VI regulatory program to assure long-term storage.
Commenter 9201 stated that the EPA should not apply the rule to "modified" facilities in part because of space limitations. Commenter 9201 noted that transportation pipelines for the captured CO2 would require significant space and are extremely site-specific determinations, and as such must be incorporated at the very beginning of EGU planning. Such design issues were not factored in to the construction of the vast majority of EGUs constructed in the U.S. to date. 
Commenter 9472 stated that existing power plants face a number of site- and plant-specific limitations to participating in a CCS demonstration project, including proximity to existing pipeline infrastructure to sell CO2 into an EOR facility.
The final emission limits for modified and existing sources do not require implementation of CCS, nor are they based on that technology. Additionally, the rule does not require that EGUs participate in CCS demonstration projects.
Commenter 9683 noted that the CO2 generated by facilities in several large western states, e.g., Arizona, Idaho, and Nevada, would need to be piped somewhere through CO2 pipelines due to limitations on storage capacity. The EPA has not factored into its rulemaking the unavailability of a CO2 pipeline network throughout the vast majority of the country, nor the fact that a substantial portion of existing CO2 pipelines are not "common carrier" lines open to anyone's use, but rather, are dedicated pipelines.
The EPA has considered the existing CO2 pipeline network in the U.S, as well as the ability to expand that network if needed beyond existing dedicated or common carrier pipelines. The CO2 pipeline network in the United States has almost doubled in the past ten years in order to meet growing demands for CO2 for EOR. CO2 transport companies have recently proposed initiatives to expand the CO2 pipeline network. Several hundred miles of dedicated CO2 pipeline are under construction, planned, or proposed, including projects in Colorado, Louisiana, Montana, New Mexico, Texas, and Wyoming. As discussed earlier, the EPA does not foresee additional needs for CO2 pipelines that transport captured CO2 as an impediment to the NSPS. Moreover, there are alternative compliance pathways for meeting the promulgated standard of performance that do not involve geologic sequestration.
Commenter 10098 asserts that the proposed rule provided virtually no explanation or supporting rationale for its finding that coal-fired EGUs will be able to transport compressed CO2 streams for geologic sequestration at either EOR operations or commercial storage facilities. The commenter further stated that the proposed rule provides no support for the EPA's assumption that a future coal-fired EGU will be reasonably close to an EOR site.
In the final rule the EPA has provided multiple compliance pathways for this NSPS, including geologic sequestration in various storage formations and through EOR, as well as storage alternatives that entities may submit to the EPA for case-by-case consideration. Therefore, the EPA does not agree that implementation of the rule depends upon the proximity of EGUs to EOR sites for CO2 injection. Potential sequestration sites are located throughout the U.S., including deep saline formations and other non-EOR formations. Additionally, for the few states that do not have geologic conditions suitable for GS, or may not be located in proximity to these areas, in some cases, demand in those states can be served by coal-fired power plants located in areas suitable for GS and the electricity they generate can be delivered through transmission lines, and in other cases, coal-fired power plants are unlikely to be built in those areas for other reasons, such as the lack of available coal or state law restrictions against coal-fired power plants.
Commenter 10108 suggested it would be reasonable for the EPA to conclude that future coal-fired EGUs and EOR operators would develop new long-distance pipelines to transport CO2 to EOR sites. Commenter 10108 cited a study that concluded that concluded that there are "no significant technical barriers" to building an extensive network of CO2 pipelines to link large power plants with sequestration sites and that connecting large coal-fired power plants in the Eastern, Midwestern, and Southern United States to storage sites would require only about 50 miles of pipeline per plant. Commenter 10108 also noted that there are existing CO2 pipelines that are 200 to 500 miles long, illustrating that such pipelines are feasible to construct. 
The EPA agrees that transport of CO2 is feasible and that CO2 pipelines of various lengths and capacities have already been sited and constructed and are feasible to construct.
Commenter 10662 stated that the EPA references the existence of 3,600 miles of CO2 pipeline in the U.S., the location of which are identified in Appendix H of the Global CCS Institute 2012 report cited by Commenter 10662. Commenter 10662 noted that only 11 states have operating CO2 pipelines, and 54 percent of the total CO2 pipeline mileage is in Texas. Commenter 10095 notes that these 3,600 miles of existing pipelines only transport less than 50 million metric tons of CO2 annually, and Commenter 10662 provided a map of the existing CO2 pipeline network and asserted that the limited CO2 pipeline network will effectively eliminate the ability to site new coal-fired power plants as an option in numerous states. 
Commenter 10662 further noted that the capacities of those 3,600 miles of CO2 pipelines are not addressed by the EPA; the EPA dismisses the volume of gas that would need to be transported by simply stating that 50 million metric tons of CO2 are currently transported annually by pipeline. The Commenter provided an estimate indicating that the entire existing CO2 pipeline transport capacity is 188.3 million tons CO2 per year, as compared to the 70 million tons per year of CO2 emitted by West Virginia alone. 
CO2 pipelines are the most economical and efficient method of transporting large quantities of CO2. CO2 has been transported via pipelines in the United States for nearly 40 years. Over this time, the design, construction, operation, and safety requirements for CO2 pipelines have been proven, and the U.S. CO2 pipeline network has been safely used and expanded. The Pipeline and Hazardous Materials Safety Administration (PHMSA) reported that in 2013 there were 5,195 miles of CO2 pipelines operating in the United States. This represents a seven percent increase in CO2 pipeline miles over the previous year and a 38 percent increase in CO2 pipeline miles since 2004. The expansion of the CO2 pipeline network in recent years provides assurance that if needed, CO2 pipelines can be permitted and constructed, and overall U.S. capacity for transporting CO2 via pipelines can be increased as needed to meet growing demands (e.g., for EOR). Moreover, given the reasonable projection that there will be little new coal-fired capacity being built (for reasons independent of this rulemaking), see RIA chapter 4, commenters' predictions of inadequate pipeline capacity appear to lack foundation.
Commenter 10095 asserted that CO2 compression and transportation is extremely energy intensive and expensive, and has not been adequately demonstrated at the commercial-scale. The commenter stated that more experience is needed to understand how pipeline transportation specifications to maintain CO2 quality (e.g., dehydration, CO2 polishing) may impact the overall reliability of the CCS system, and therefore the operation of the EGU. Commenter 9597 stated that CCS is challenged by safety issues associated with long distance transport of CO2, a super-critical fluid. 
Commuter 9666 stated that the byproduct of CCS -- captured CO2 --  requires specialized processing because it is unstable under normal atmospheric conditions. Captured CO2 must be compressed to a pressure of 100 atmospheres, transported long distances in that volatile state, and injected 4,000 to 8,000 feet below the Earth's surface into a geologically suitable repository, where chemical reactions secure the CO2 over time. 
Commenter 10095 also stated that CO2 transportation operations could also be affected by the unsteady flow of CO2 generated by EGUs during load changes and planned and forced outages, and it is unknown how these fluctuations and suspensions will impact transportation and injection operations. 
Commenter 10036 noted that after CO2 is captured, it must be compressed "from near
atmospheric pressure to a pressure between 1,500 and 2,200 psia (pounds per square inch absolute) in order to be transported via pipeline and then injected into an underground storage site" and noted that compressing CO2 is energy intensive and expensive. 

Commenter 10036 also noted that the CO2 transported for use in EOR operations has historically been from the steady state production of natural geologic deposits and not from CO2 captured at power plants. Compression and transportation operations, similar to storage operations, could be affected by the unsteady flow of CO2 sourced by power plants. 
The EPA does not agree with the commenters' assertions. CO2 has been safely compressed and transported via dedicated pipelines in the U.S. for nearly 40 years. Pipelines can indeed convey captured CO2 to sequestration sites with certainty and provide full protection of human health and the environment. Existing and new CO2 pipelines are comprehensively regulated by the Department of Transportation's Pipeline Hazardous Material Safety Administration. The regulations govern pipeline design, construction, operation and maintenance, and emergency response planning. See generally 49 CFR 195.2. Additional regulations address pipeline integrity management by requiring heightened scrutiny to assure the quality of pipeline integrity in areas with a higher potential for adverse consequences. See 49 CFR 195.450 and 195.452. On-site pipelines are not subject to the Department of Transportation standards, but rather adhere to the Pressure Piping standards of the American Society of Mechanical Engineers (ASME B31) which the EPA has found would ensure that piping and associated equipment meet certain quality and safety criteria sufficient to prevent releases of CO2 such that certain additional requirements were not necessary. See 79 FR 358-59 (Jan. 3, 2014). These existing controls over CO2 pipelines assure protective management, guard against releases, and assure that captured CO2 will be securely conveyed to a sequestration site. 
CO2 used for EOR may come from anthropogenic or natural sources. The source of the CO2 does not impact the effectiveness of the EOR operation. CO2 capture, treatment and processing steps (including compression, as commenter 9666 states) provide a concentrated stream of CO2 in order to meet the needs of the intended end use. CO2 pipeline specifications of the U.S. Department of Transportation Pipeline Hazardous Materials Safety Administration found at 49 CFR part 195 (Transportation of Hazardous Liquids by Pipeline) apply regardless of the source of the CO2 and take into account CO2 composition, impurities, and phase behavior. Additionally, EOR operators and transport companies have specifications to ensure related to the composition of CO2. These requirements and specifications ensure EOR operators receive a known and consistent CO2 stream.
Lastly, the EPA acknowledges that generation of captured CO2 from natural gas treatment plants and industrial sources may be more steady-state than the generation of captured CO2 from EGUs. However, the EPA does not agree that the technical and economic feasibility of operation of CO2 pipelines depends upon steady-state generation of CO2 from capture sources. There are technically and economically feasible technologies (e.g., looping, pressure maintenance, and diversion to/from other pipelines) that EGUs and CO2 pipeline can apply to manage pipeline pressure and flow fluctuations associated with EGU load fluctuations and EGU planned or unplanned outages to avoid detrimental effects on CO2 pipeline operations.   
Commenter 9472 and commenter 9033 stated that the EPA has ignored the technical challenges of CO2 storage. Commenter 9472 notes that full scale application of CCS on a power plant requires that CO2 transportation and long-term subsurface storage is available at all times, and that CO2 removed from an emissions stream by CO2 capture equipment are in a gaseous form and cannot be stored onsite; the captured CO2 must be transported for long-term storage. Commenter 9033 inquired about the risk associated with shutting down electricity generation when the capture or subsequent processes fail. Commenter 9033 also questioned what would happen to EGU CO2 compression systems when load on the CO2 capture plant is reduced, and would that situation subsequently impact CO2 transportation or injection given the instantaneous load drop and increase.  
The EPA does not anticipate that the CO2 transportation network will need to be available "at all times" in order for EGUs to achieve compliance with the proposed rule. Moreover, a new fossil fuel-fired steam generating EGU  -  if constructed  -  would, mostly likely, be built to serve base load power demand and would not be expected to routinely start-up or shutdown or ramp its capacity factor in order to follow load demand. Thus, planned start-up and shutdown events would only be expected to occur a few times during the course of a 12-operating-month compliance period. Post-combustion partial and full CCS have also proven highly reliable in actual operation (e.g. at Boundary Dam, and AEP Mountaineer). 
Commenter 10786 noted that the Class VI regulatory approach is inconsistent with the legal and regulatory framework governing CO2-EOR operations. For example, EOR industry's standards and requirements for CO2 pressure, allowed co-constituents and the like are by and large focused on what is needed and acceptable for the pipeline infrastructure, surface handling facilities, and target oil & gas reservoir(s). The EOR industry is not in the generic CO2 offtake business.
The EOR industry instead acquires CO2 that is suitable for meeting both its pipeline and its mineral extractive needs. Commenter 10786 also stated that EOR operators and CO2 pipeline companies are unlikely to allow CO2 intended for use in EOR to be commingled with CO2 from other sources. 
CO2 used for EOR may come from anthropogenic or natural sources. The source of the CO2 does not impact the effectiveness of the EOR operation. CO2 capture, treatment and processing steps provide a concentrated stream of CO2 in order to meet the needs of the intended end use. CO2 pipeline specifications of the U.S. Department of Transportation Pipeline Hazardous Materials Safety Administration found at 49 CFR part 195 (Transportation of Hazardous Liquids by Pipeline) apply regardless of the source of the CO2 and take into account CO2 composition, impurities, and phase behavior. There is thus no a priori restriction on commingling CO2 from different sources. Additionally, EOR operators and transport companies have specifications to ensure related to the composition of CO2. These requirements and specifications ensure EOR operators receive a known and consistent CO2 stream.
Commenter 7977 noted that the proposed regulation relies on the expected typical pipeline CO2 distance to be 50 miles to possible geologic sequestration sites, but that this distance underestimates the actual distances that may be necessary for the transmission of CO2. Commenter 9648 noted that even if 95 percent of the sources are located within 50 miles, it is unclear if the pipelines that would be needed in their state to transport CO2 could receive the necessary permits to allow construction. Commenter 9426 cited a study of CO2 pipeline options that concluded that sequestration is not economically or technically feasible in North Carolina, and asserted that based on these studies it would not even be possible to develop a new coal-fired EGU if CCS were required.
Commenter 9774 noted that coal-fired power plants in Wisconsin are between 200 and 500 miles from the nearest sequestration formation and that there are no CO2 pipelines in Wisconsin, and that the cost of building such a pipeline would exceed the cost of installing CO2 capture technology on the coal-fired plants. Comment 10106 however, noted that although there are no identified sequestration sites in Wisconsin, as there are existing locations where sequestration geology has been demonstrated, and since the transport of CO2 through pipelines is a well-established practice throughout the nation, the presence of sequestration geology within state lines does not dictate the availability or feasibility of CCS.

Commenter 9666 cited the studies conducted of CO2 pipeline feasibility for North Carolina and Wisconsin that concluded that CCS would only be viable if multi-state CO2 pipelines were constructed, and that suggested that the 50-mile CO2 pipeline transport distance presumed in cost studies is inadequate in many cases. 
The EPA does not agree that technical or permitting feasibility would limit the development of CO2 pipelines (see also previous responses). In estimating impacts of the rule, the EPA relied on NETL studies referenced in Section V.I.2 of the preamble and based transport costs on a generic 100 km (62 mi) pipeline and a generic 80 kilometer pipeline. At least one study estimated that of the 500 largest point sources of CO2 in the United States, 95 percent are within 50 miles of a potential storage reservoir. For new sources, pipeline distance and costs can be factored into siting and, as discussed in section V.M, there is widespread availability of geologic formations for geologic sequestration (GS). Moreover, data from the Pipeline and Hazardous Materials Safety Administration show that in 2013 there were 5,195 miles of CO2 pipelines operating in the United States. This represents a seven percent increase in CO2 pipeline miles over the previous year and a 38 percent increase in CO2 pipeline miles since 2004. Therefore, the EPA's assumptions, while they may apply to all cases, are representative for cost estimation purposes. In reality, the EPA understands that pipelines of longer or shorter distances may be constructed for compliance with the NSPS. With respect to pipeline construction in the southeast (such as North Carolina), offshore saline geologic capacity exists within 100 kilometers of the state, and state demand could also be served by coal-fired electricity generation capacity built in nearby areas and this electricity then delivered through transmission lines. See Figure 1 of TSD on geographic availability. In any case, there are alternative compliance pathways available for achieving the final standard of performance which do not involve sequestration.   
Commenter 10618 provided cost estimates of CO2 pipeline development: Duke Energy estimated a CO2 pipeline along existing right of way from North Carolina to sites in the Gulf States and Appalachia would approach $5 billion, and the International Energy Agency estimated nearly $300 billion to construct necessary pipelines to transport the CO2 from capture to end use facilities for a 50% reduction. Commenter 9666 cited a study that as of 2010 industry had spent $2.2 billion for construction of over 2,200 miles of CO2 pipelines within the Permian Basin alone. Commenter 9596 noted that the costs for CO2 pipeline construction predicted by a study conducted for the Carolinas vary from $3.8 billion to $4.3 billion. Commenter 8925 noted that CO2 pipeline cost estimates published in the open literature for the U.S. range from $50,000 to $110,000 per inch-mile of pipeline, including labor, materials and right-of-way costs, which vary by location. Commenter 9195 noted that at a cost factor of $100,000 per inch-mile, a 24-inch pipeline would cost roughly $2.4 million per mile, and a two thousand mile pipeline of modest size would cost roughly $5 billion to construct.
 Commenter 7977 noted that the EPA is required to comprehensively evaluate the impact of all associated transportation costs via CO2 pipelines, including availability and acquisitions of right-of-way for new pipelines, capital and operating costs, and actual length of transmission pipelines. Commenter 10043 noted that it is unclear whether the EPA's estimate of CO2 pipeline construction costs includes the costs of right-of-way, pipeline construction, permitting delays, and length of transportation, among other costs. Commenter 9600 also stated that it does not appear that the EPA has taken into account the costs of CO2 pipelines, Commenter 9734 stated that the cost that would be required to construct CO2 pipelines to transport captured CO2 to oil fields would be insurmountable, and that the EPA has recognized this. Commenters 9657 and 9734 also noted that there are significant costs for building the CO2 pipeline framework and believe that the EPA has not incorporated these burdens into its analysis.
Commenter 8925 noted that published sources indicate that CO2 pipeline construction costs range from $50,000 to $110,000 per inch-mile of pipeline, including labor, materials and right-of-way acquisition costs. Commenter 8925 noted that once permits and rights-of-way were secured, construction of a 12.2 mile intrastate CO2 pipeline to support a CO2 capture and EOR project was completed within 3 months. Commenter 8925 noted that the applicant needed to consult with eight separate Federal and State agencies as part of the pipeline permitting process.

Commenter 10039 asserted that the lack of a regulatory framework and the NETL cost and performance assumptions that the EPA has relied on renders the proposal arbitrary and unreasonable, with no nexus with any EGU siting requirements. Commenter 10039 notes that all CCS analysis cases assume generation will be located within 62 miles of a local available sequestration site for purposes of estimating CO2 transportation costs. The commenter asserted that sequestration sites are not possible in large parts of the country and therefore transportation cost assumptions are arbitrarily low. The cost assumption has no basis in any real siting requirement or electric generation needs analysis and is therefore arbitrary and inappropriate for consideration of the costs of the technology when developing the NSPS. Commenter 10039 notes that under no EPA, DOE, or EIA models of the electric generating sector, does the EPA show that 200 individual generating units will be installed within 62 miles of any area of the country which is assumed to be suitable for CO2 storage.
The EPA estimated costs for CO2 based on the NETL studies referenced in Section V.I. of the preamble and based transport costs on a generic 100 km (62 mi) pipeline and a generic 80 kilometer pipeline. At least one study estimated that of the 500 largest point sources of CO2 in the United States, 95 percent are within 50 miles of a potential storage reservoir. For new sources, pipeline distance and costs can be factored into siting and, as discussed in section V.K, there is widespread availability of geologic formations for geologic sequestration (GS). Moreover, data from the Pipeline the and Hazardous Materials Safety Administration show that in 2013 there were 5,195 miles of CO2 pipelines operating in the United States. This represents a seven percent increase in CO2 pipeline miles over the previous year and a 38 percent increase in CO2 pipeline miles since 2004. Therefore, the EPA's assumptions are representative for cost estimation purposes.  See responses to previous comments on the regulatory framework for CO2 pipelines and Section V.I.5 and N.4 of the preamble. See also Figure 1 of TSD on geographic availability. In any case, there are alternative compliance pathways available for achieving the final standard of performance which do not involve sequestration.   
The EPA recognizes that siting and construction of CO2 pipelines will generally involve securing permits from multiple jurisdictions. Costs of acquisition of both land and subsurface property rights (`pore acquisition rights') are included in the EPA's cost estimates. 
Commenters 9600 and 10097 noted that the EPA relied exclusively on DOE studies to predict the levelized cost of electricity (LCOE) for EGUs, and noted that the LCOE data do not factor in CO2 transport and sequestration costs where EOR is not available. Commenters 9201, 9600, and 10097 noted that the proposal completely ignores any costs associated with the transportation and storage components of CCS, and concludes that based on these facts within the proposal, the EPA cannot reasonably conclude that partial carbon capture is of reasonable cost based on this information derived from these DOE studies. Commenter 7977 also noted that the DOE/NETL costs the EPA relied for the rule on exclude transportation costs of CO2, which could significantly increase the cost estimate for new sources implementing CCS technology. Commenter 7977 also noted that Section 111 (a)(1) of the CAA requires that the EPA account for the "costs of achieving such reductions." Since EPA is proposing that CCS is the BSER for coal-fired EGUs, the EPA must account for the cost of transporting CO2.
Commenter 9396 stated that the proposed rule's analysis of partial sequestration as BSER effectively ends with CO2 capture at the plants, failing to provide analysis of the other component parts of CCS  -  pipeline CO2 transportation, CO2 monitoring, and permanent CO2 sequestration. In determining the BSER, the EPA has not examined the entire process and fails to include in the standard full evaluation of all the critical components to assure the emissions reductions are accomplished permanently.
The EPA in fact included cost estimates for CO2 transport when EOR opportunities are not available  -  consistent with its overall conservative cost methodology of assuming no revenues from sale of captured CO2. The EPA also carefully reviewed the assumptions on which the transport cost estimates are based and continues to find them reasonable. 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 the preamble for additional information in Section V.I.5. 
Commenter 9648 stated that not all the energy and emissions related effects impacted for the CCS systems by the proposed rule have been identified and incorporated in the rulemaking. For example, electric power consumption for operation of CCS CO2 separation and injection technologies are estimated to be 30 percent of the plant's total electricity generation rate, and this estimate does not include additional energy requirements for transport and compression for EGU sites that do not have nearby geologic reserves for storage, such as those in North Carolina.
The cost studies used by the EPA in the cost analysis for the rulemaking include both construction cost and operating and maintenance (O&M) costs for CO2 transport. Pipeline O&M costs included in the studies include the cost of electricity and other consumables that would be needed to operate the CO2 pipeline. Typically the electricity needed to operate a CO2 pipeline would not come directly from the EGU from which the captured CO2 is being transported, but rather would be provided directly to the pipeline by the pipeline operator, which could be a separate entity from the EGU operator. Therefore the electric power consumption for operation of the pipeline would not generally directly affect the EGU's net electricity generation rate.
Commenter 7977 noted that the economics of EOR change drastically with distance and CO2 transportation needs. The cost of building infrastructure for CO2 transport or transporting CO2 hundreds of miles far exceeds that of a facility located on an existing EOR site. The EPA should provide cost calculations for new facilities that do not have EOR within a certain geographic distance, as CCS won't be economically feasible for facilities without easy access to EOR. Based on the EPA's own analysis, there are 37 states where CO2-EOR is not utilized and eleven states that have virtually no CO2 storage capacity or CO2-EOR operations. Commenters 7977 concludes that the cost of building infrastructure for CO2 transport or transporting CO2 hundreds of miles far exceeds that of a facility located on an existing EOR site. 
The EPA does not agree that the absence of EOR sites in the vicinity of new EGUs would render the EGU sites infeasible. The EPA recognizes that the cost of CCS may vary depending upon the proposed location of the EGU based on geographic and other factors including locations of potential sequestration sites; however, the EPA does not agree that CCS is economically infeasible for new EGUs located in areas in which there are no EOR operations. Potential sequestration sites including both EOR sites and deep saline formation sites as well as other non-EOR sites are located throughout the U.S. and construction of CO2 pipelines is adequately demonstrated.  
Commenter 9195 noted that the EPA's proposal will have significant disparate geographic impacts, and that geologic features appropriate for EOR or geologic sequestration are not evenly distributed throughout the country. Commenter 9195 noted that the DC Circuit Court has said that sec. 111 standards "must not give a competitive advantage to one State over another in attracting industry" and questioned whether construction of CO2 pipelines can solve this issue. Commenter 9780 in testimony stated that it is not clear how EOR could defray the costs of an overall CCS project if long pipelines or transmission lines would have to be built (and paid for), and stated that the EPA has made no effort to quantify whether the price of captured CO2 would overcome the increased costs associated with pipeline or transmission construction. Commenter 9780 also noted that the EPA has failed to account for the lengthy, costly, and uncertain permitting processes for major infrastructure like pipelines and transmission lines, and has not addressed the fact that the owners of new EGUs installing CCS are not likely to be the entities responsible for permitting, building and paying for this critical infrastructure. Commenter 9780 concluded that in an effort to dismiss the geographic constraints of EOR, the EPA has made unsubstantiated and unverifiable claims about the ease and cost of building pipelines and transmission lines.
The EPA does not agree that the rule provides a "competitive advantage" to one state over another in attracting industry. There are various compliance paths which may be used, some of which do not involve sequestration, so that compliance is not limited by geographic location.
Geologic Sequestration
Commenter 10098 stated that the EPA's claim that geologic sequestration is currently available is contradicted by the extensive ongoing research and development seeking to make geologic sequestration commercially available. Commenter 10098 further stated that although the proposed rule provides a theoretical overview of how geologic sequestration could work a discussion of commercial geologic storage facilities is conspicuously absent. Commenter 10098 noted that it is arbitrary and capricious to declare that an experimental technology is technically feasible and available without any explanation as to why the technology is considered ready for commercial use or acknowledgment of the evidence of operational setbacks.
Commenter 9472 stated that the EPA has not adequately examined the feasibility and challenges of CO2 storage in the proposed NSPS. Commenter 9472 further noted that the EPA failed to consider several aspects of CO2 storage that limit the feasibility of utilizing CCS at a coal-fueled power plant.
Geologic sequestration is demonstrated. See Preamble Section V.M and V.N. The EPA has issued six Underground Injection Control permits to two projects under the Class VI program. It would not have done so, and under the regulations could not have done so, without demonstrations that CO2 would be securely confined to prevent the movement of fluids into or between USDWs or into any unauthorized zones. One of these projects was for a steam generating EGU. Furthermore, international experience with large scale commercial GS projects has demonstrated through extensive monitoring programs that large volumes of CO2 can be safely injected and securely sequestered for long periods of time at volumes and rates consistent with those expected under this rule.
Commenter 10095 stated that the EPA's development of its proposal does not account for the costs and burdens associated with the level of effort necessary to confirm the feasibility of sequestration sites and that the EPA instead relies on theory and generalizations.
Commenter 10392 stated that the cost-effectiveness of partial CCS  -  particularly if involving permanent geologic sequestration  -  is entirely unproven and not commercially available.
The EPA's cost estimates account for the costs of GS, among them site screening and evaluation costs, costs for injection wells and equipment, O&M costs, and monitoring costs. The EPA's cost estimates for sequestration thus cover all aspects commenters claimed the EPA disregarded. The EPA believes that the use of costs and scenarios presented in the studies referenced are representative for purposes of the cost analysis. The NETL cost estimates upon which the EPA's costs are based draw directly from the UIC Class VI economic impact analysis. That analysis is based on estimated characteristics for a representative group of projects over a 50-year period of analysis, as well as industry averages for several cost components and sub-components. See also RIA chapter 4.
Commenters 1959, 2471, 8349, 9194, 9426, 9780, 10086, and 10239 stated that there is no power plant with full-scale geologic sequestration functioning anywhere in the US today. Commenters 1959, 8349, 9194, 9780, and 10239 noted that there is no evidence of successful commercial implementation. Commenters 2471, 8349, 9780 and 10239 noted that the EPA made reference to a number of plants, but none of them are actually operating, but are only planned. Commenter 10239 additionally noted that the EPA provides no analysis regarding these facilities and fails to acknowledge that at least one has been suspended due to concerns over vertical leakage. Commenter 9780 noted that there is insufficient monitoring experience with post-injection storage of CO2 to support findings of adequate demonstration. 
Commenter 9780 specifically noted that 3 of the 4 large-scale storage projects listed by the EPA as evidence of the technical feasibility of storage are capturing their CO2 from natural gas extraction or processing facilities while the fourth receives captured CO2 from a gasification plant for use in EOR, none receive captured CO2 from an EGU.
Commenters 9426 and 9683 stated that there is not relevant experience to support a finding that permanent geological sequestration of CO2 on the scale required for use with commercial power generation has been adequately demonstrated, or that any level of CO2 emission from sequestration repositories is achievable under the range of relevant conditions for the industry as a whole.
Commenters 9725 and 10050 stated that the EPA cannot show that the proposed coal unit standard can be met on a continuous basis given the lack of any demonstration of continuous sequestration of the large amounts of CO2 from a commercial scale base load generation plant.
The EPA notes that SaskPower's Boundary Dam CCS Project in Estevan, Saskatchewan, Canada, less than 10 miles from the US border, is the world's first commercial-scale fully integrated post-combustion CCS project at a coal-fired power plant. The project fully integrates the rebuilt 110 MW coal-fired Unit #3 with a CO2 capture system The CO2 from the capture system is more than 99.999 percent pure with only trace levels of N2 in the product stream. The captured CO2 is transported by pipeline to nearby oil fields in southern Saskatchewan where it is used for enhanced oil recovery (EOR) operations. 

In the United States, the EPA has issued Class VI UIC permits for six wells for two projects. EPA considered, among other information, information on the regional geology and local geologic features at each site as part of its permitting process to determine that the wells were appropriately sited and met the Class VI requirements. Additionally, there are several large scale CO2 sequestration projects including the Illinois Basin Decatur Project and the Cranfield (Tuscaloosa) Project that demonstrate that storage of large amounts of CO2 can be achieved. In April 2015, DOE announced that CCS projects supported by the department have safely and permanently stored 10 million metric tons of CO2, which is the same order of magnitude expected for an EGU.
Existing commercial CCS facilities in other countries demonstrate the commercial storage of CO2, and the ability to inject large quantities over long period of time. The CO2 streams from these facilities have physical and chemical characteristics similar to pipeline grade CO2 that would be expected from an EGU so the source of the CO2 is not a factor in assessing the feasibility of long term secure storage. Commenter 10239 refers to the In Salah project where CO2 injection has been suspended due to concerns over vertical leakage. Monitoring data and analyses indicated that CO2 had migrated from the injection zone into the lower caprock, but had not reached the main caprock seal. No CO2 was released. While the In Salah project is no longer injecting CO2, the events demonstrate that the monitoring program served its intended purpose in detecting adverse conditions prior to the release of any CO2. (Indeed, the Electric Power Research Institute (EPRI), a nonprofit research organization funded by the electric utility industry, likewise stated in its public comments that In Salah served as an example of the efficacy of sub-surface monitoring in preventing environmental release of sequestered CO2.)
Post injection site care, including monitoring of the stored CO2, is required under UIC Class VI permits, and all Class VI permits issued to date have included required post injection site care plans. The risk of release is highest during the injection phase and decreases during the post injection period and monitoring requirements reflect the relative risk during each phase. 
The EPA has reviewed and considered the results from several long-term monitoring programs, including more than 10 years of monitoring from the sequestration site at the Weyburn oil field, and the Sleipner project, which began injecting CO2 into the deep subsurface in 1996. The EPA also recognizes that several EOR projects have been monitoring reservoir conditions for more than 30 years. The EPA believes that the proposed standard can be met on a continuous basis because several of the sequestration projects described in the proposal including Sleipner in the North Sea, Snohvit in the Barents Sea and Weyburn in Canada have demonstrated continuous operation for many years. 
Commenter 9426 noted that geologic storage of CO2 is not technologically viable in some regions of the United States since the necessary geologic conditions to support CO2 storage simply do not exist in those regions. 

Commenter 10778 stated that the theoretical feasibility of sequestration geology in the Coastal Plains and Gulf Coast does not mean sequestration is actually available and capable of being implemented in the Region. The commenter stated that the Coastal Plains region of the United States, especially the Gulf Coast, contains the largest storage sequestration resource of any region; however, the commenter clarified as a threshold matter, the potential feasibility of geologic sequestration does not equate to a finding that this technology is either "available" or that it has been "adequately demonstrated" within the meaning of CAA Section 111. Further, the commenter stated that while the Coastal Plains region could have a greater percentage of the basic geologic systems that might support sequestration, this does not equate with sequestration capability.

Commenter 9426 stated that because the geology necessary for carbon sequestration is highly site-specific and suitable sites are concentrated in a few areas of the country, it may be impossible for the EPA to determine that an NSPS based on CCS is achievable for sources across the nation. The commenter stated that before the EPA may impose a standard across the entire electric generating industry it must show that the standard is achievable across the entire industry, which includes a wide variety of geologic characteristics. According to the commenter, geologic limitations require long-distance transportation of removed CO2 prior to sequestration, then the EPA must factor in the transportation and associated costs as part of its BSER demonstration.

Commenter 9596 stated storage sites for CO2 are simply not available in many areas of the country. According to the commenter, CCS is only an option in certain areas of the United States that has the correct geological formations to sequester CO2 (or have access to long-distance CO2 pipelines that can convey CO2 to a proper sequestration site). The commenter concluded that EPA cannot require the use of a compliance option that is only available in some regions of the United States.

Commenter 10033 stated it is likely that many areas are simply unsuitable for CCS based on geology or other factors.
Commenter 10039 stated that the EPA's basis for the technical feasibility of CO2 sequestration is based on the potential technologies for monitoring and verifying sequestration and that the data presented is insufficient to show that CO2 sequestration is a feasible, permanent storage solution for CO2 from EGUs. Commenter 10039 notes that the USGS analysis cited by the EPA as to the availability of CO2 storage resources shows that large sections of the US are unsuitable for sequestration for various reasons. Commenter 10098 stated that USGS does not know how much of these regional areas may actually be used for CO2 storage.
Commenter 9326 stated that much is yet to be proven regarding the permanent storage of CO2 in deep geologic formations. Commenter 9326 further stated that not every power plant is located on or near favorable geology for CO2 storage and that hundreds of miles of pipelines would have to be built to service these facilities, which continues to add on to this high cost of CO2 capture.
Commenter 10095 stated that injection and storage of commercial volumes of CO2 produced by an EGU is not available in all regions, has not progressed beyond the research, development and early demonstration phase, and requires additional study and development before it can be considered adequately demonstrated.
Commenter 9197 stated their doubts that CCS will be feasible to implement in many parts of the country because storage sites for CO2 are simply not available in many areas of the country. Commenter 9197 further stated that the EPA should not require new facilities to use a compliance option that is only available in some regions of the United States.
Commenters 8949, 9201, 9381, 9407, 9666, 10023, 10052, 10100 and 10660 asserted that CCS is not available in all areas of the U.S. due to geologic restrictions, lack of transportation infrastructure, or lack of EOR. Commenter 9407 further stated that NSPS is nationally applicable and must be implementable over broad geographic regions.
Commenters 9201, 9381, 9666, 10052, 10100 and 10660 stated that the requirement would result in advantages for states such as those in the Coastal Plains and Southwest that have storage capacity or EOR, and disadvantages for states that lack sufficient resources for sequestration, such as the Pacific Northwest and Atlantic Coast. 
Commenters 9201, 9381, 10048, and 10052 stated that areas with little or no storage capacity would have to construct costly, lengthy and expensive pipeline systems to meet the regulatory requirements, if property rights and easements were obtainable. Furthermore, Commenters 9201 and 9666 reiterated that the National Carbon Storage Atlas assessment of potential geological storage opportunities was an initial assessment and more precise assessments that identify all relevant properties (e.g., permeability, penetrations, understanding of underground fluid displacement, fractures and potential for fractures) will take additional time to complete. Additionally, Commenter 9666 stated that the EPA did not consider economic viability or lack of accessibility to storage resources due to land-management or regulatory restrictions, such as areas containing freshwater in the West.
Commenter 9407 stated that pipelines, deep well sequestration, EOR and other infrastructure must be available for the proposed BSER. 
Commenter 9780 stated that there is no evidence in the proposal that the EPA considered regional differences in EOR opportunities and sequestration site availability in assessing the feasibility of deploying partial CCS for coal-based units.
Commenter 9426 further stated that in regions of the country where storage is not available, the EPA would be required to establish alternative standards.
See Section V.M. of the preamble and the technical support document on geographic availability. Potential GS formations are widely available in the United States. The EPA recognizes that geologic conditions to support CO2 storage may not exist in all regions of the country. Where such capacity is unavailable, electricity demand in those areas can be served by coal-fired power plants built in neighboring areas with geologic availability with generated electricity being supplied via transmission line, see Figure 1 of TSD on geographic availability, or the CO2 can be transported to available GS sites via pipeline. For other of those areas, coal-fired power plants are either not being built due to state law prohibition s against building such units, or other available compliance alternatives exist allowing a new coal-fired power plant meeting the promulgated NSPS to be sited. There are alternative means of complying with the final standards of performance which do not necessitate use of partial CCS, so any siting difficulties based on lack of a CO2 repository would be obviated. 
Commenter 9683 stated that industry-wide carbon storage has even less evidence of feasibility than does carbon capture, but is the only feasible large-scale fate for the amount of CO2 to be captured from a full-scale electric generating unit. Commenter 9683 further stated that depleted oil and gas formations provide the only evidence that large amounts of CO2 can be stored safely over the long term, but noted also that these formations do not exist in sufficient geographic dispersion throughout the US.
The commenter is correct that depleted oil and gas formations provide potential capacity for CO2 captured from a full-scale electric generating unit and that the CO2 can be stored safely over the long term. However, the EPA does not agree that oil and gas formations provide the only evidence of large scale storage. The three international sites (Sleipner, Snohvit and In Salah) and DOE pilot and demonstration projects provide evidence of the feasibility of saline storage sites also. The issue of geographic availability is addressed elsewhere in this section and in Preamble section V.M. 
Commenter 10106 stated that the presence of sequestration geology within state lines does not dictate the availability or feasibility of CCS. Commenter 10106 noted that different states are positioned differently in terms of the ease of compliance for many reasons, including cost, and that this is true under most Clean Air Act regulations.
Commenter 10095 stated that some states may not have the capability of implementing CCS without exporting CO2 to other states or offshore. Commenter 10095 noted that the EPA proposal does not broach how a state would address these barriers and externalities.
Commenters 9423 and 10500 stated that carbon sequestration may not be available in various regions of the United States and that the CCS requirement will result in a competitive advantage for states that have EOR or sequestration opportunities and disadvantages for those that do not.
Commenter 9774 stated that fourteen states do not have any geologic formations suitable for carbon sequestration. Commenter 10031 stated that at least 30% of the states have little to no known storage capacity in the form of saline reservoirs.
Commenter 9770 stated Minnesota does not have the geology to sequester CO2 either for saline aquifer storage, which has not been commercially demonstrated, or for enhanced oil recovery (EOR).
Commenter 9194 specifically addressed their concerns with geologic sequestration viability in Florida.

Commenter 2470 stated Florida has insufficient ability to utilize enhanced oil recovery for the captured carbon from the CCS process due to the minimal oil and gas production currently within the State. According to the commenter, moving the captured CO2 to other areas within the Southeast with greater oil and gas resources will require the construction of a pipeline and additional associated costs.
The EPA largely agrees with the commenter that each state has unique geologic circumstances. Transporting CO2 to areas of geologic availability is an option for complying with the NSPS and there are many examples of transportation of CO2. 
The EPA noted in the January 2014 Proposed Rule that certain sources may be precluded from locating in certain areas for economic or technical reasons which is not inconsistent with congressional intent for CAA section 111. The presence of suitable geology for sequestration is an initial factor to consider in determining the feasibility of a specific site for a new EGU. Site specific studies must then be conducted to ensure the location is capable of safe, long-term storage of CO2 and not all locations will meet the siting criteria. 
The EPA notes that DOE and USGS resource assessments have identified 39 states that have saline storage opportunities. Many of the states that do not have storage access are unlikely to see new coal fired power plants because there is no need for the additional power, coal-fired power has never been utilized in the area (e.g. Hawaii), or there are other preferred power options that can meet the performance standard. The EPA believes that the rule offers a wide range of options that allow states considerable flexibility to comply with the rule without creating an economic disadvantage. States with little or no saline storage capacity may choose to transport CO2 to locations with available storage, or site facilities near storage areas and using transmission lines to provide power to other areas. In addition, there are various compliance alternatives to achieve the promulgated standard of performance, not all of which involve sequestration.

With respect to the commenter's assertions about the lack of availability of EOR in Florida, the BSER determination and regulatory impact analysis for this rule relies on GS in deep saline formations. The EPA notes that Figure 1 of the technical support document on geographic availability shows the areas of Florida that are within 100 kilometers of a potential GS formation; electricity demand may be served by coal-fired electricity generation built in areas that are proximate with geologic sequestration, and this electricity can be delivered through transmission lines. See preamble section V.M.7.
Commenter 9426 stated that the EPA must show that storage of large volumes of CO2 has been adequately demonstrated on a consistent basis and must also identify locations where suitable geological conditions would allow for such storage. Commenter 9426 specifically stated that while there may be potential CO2 storage areas offshore of the Carolinas, the ability to inject CO2 in these areas has not been demonstrated.
Commenter 10095 noted that geologic data may simply show large areas are not suitable for underground injection and storage of CO2 and that consistent geology is imperative for ensuring the adequacy of a formation for CO2 injection and storage. 
The EPA has identified and described several large storage projects that demonstrate the ability to safely store large volumes of CO2. Analyses by DOE and USGS identify many areas where conditions are favorable for storage, but recognize that site specific studies will be required to ensure the location is capable of safe, long-term storage of CO2. DOE studies have identified several offshore areas, including the Carolinas, with the potential for saline storage. In addition, should none of these storage opportunities be readily available, there are alternative compliance pathways to meet the promulgated standard.
Commenter 10030 cited the WCEV project in Michigan, and stated that as the design of the project was only in relation to a slip-stream, it cannot form a basis for concluding that the facility as a whole or the available geology feasibly could accommodate a full-scale CCS system capable of sequestering the CO2 necessary for the WCEV to meet the proposal's emission limitations.
Commenter 9426 noted that neither the Kemper County nor the SaskPower Boundary Dam projects shed light on the challenges associated with storing CO2 in saline geological formations, and these first generation of CCS systems will likely reveal performance and reliability issues that may require costly additional measures to address.
The EPA has not used the Wolverine Clean Energy Venture (WCEV) project in Michigan as a basis for concluding that the facility, as a whole could accommodate a full-scale CCS system. Today's rule specifically notes the proposed Wolverine EGU project in Rogers City, Michigan has been cancelled and is therefore not addressed in the final rule. See preamble section III.J. With regards to the issue of slip stream, see section V.D.2.a. of the final rule preamble of the NSPS for the EPA's response to this comment. We also note that the Boundary Dam project developer has publically extolled the reliability of the CCS system in operation, and that the system in fact has been on-line without incident since it commenced operations.
Commenter 9426 is correct that neither the Kemper County nor the SaskPower Boundary Dam projects plan to store CO2 in a deep saline formation as a primary location. However, Boundary Dam is in fact sequestering the excess CO2 which it is not selling for EOR in a deep saline formation. 
The EPA has issued six UIC Class VI permits to two applicants under the Class VI program, each permit involving deep saline injection of large volumes of captured, anthropogenic CO2.  The EPA would not have issued these permits without finding (and demonstrating in  the administrative record) that the permittees would meet all requirements of the rigorous Class VI regulation, whose requirements assure that sequestered carbon dioxide will remain confined  without endangering underground sources of drinking water.
Commenter 10239 stated that it is unlawful for the EPA to prohibit coal-fired EGUs in areas that lack geologic storage options. According to the commenter, applying a national standard based on CCS would have the effect of creating the exact type of localized competitive advantages that Congress sought to avoid when it enacted the NSPS program, as only regions with geologic storage could construct coal-fired EGUs. The commenter also stated that using Section 110 attainment provisions to prohibit facilities from being constructed in certain areas is irrelevant since GHGs do not produce localized air impacts and there are no national ambient air quality standards for GHGs that could be used to invoke Section 110.
The final standard of performance for fossil-fired EGUs does not create these effects. Most areas of the country have potential GS opportunities. Some states prohibit new coal-burning capacity. In the unlikely event that a new source locates in another state (and there is no record evidence of any such possibility), there are alternative compliance pathways available under the final standard which do not involve capture and sequestration and which have associated geographical constraints. The EPA has determined that more than 95 percent of the 500 largest CO2 point sources in the U.S. are within 50 miles of a possible geologic sequestration site so localized competitive advantages would be minimized. In drafting the CAA Section 111, Congress recognized that certain emission sources may be precluded from locating in certain areas for economic or technical reasons and there is no requirement that BSER apply to all locations equally. 
Commenters 10098 and 10239 stated that the EPA lacks record support for its assertion that geologic storage capacity is widespread and available throughout the U.S. and Canada, and typically available within 50 miles of existing power plant locations. Commenter 10098 noted that the USGS review cited in the proposed rule is an initial assessment of storage capacity and provides no information on areas that may actually be used for CO2 storage. According to Commenter 10239, it is arbitrary and capricious for the EPA to simply rely on the potential availability of suitable formations, further stating that such reviews of potentially suitable formations cannot establish actual availability because each potential geologic sequestration site must undergo appropriate site characterization to ensure that the site can safely and securely store CO2. 
Commenter 9780 stated that the distance to geology suitable for geologic storage, and the distance to oil production development activities that might purchase CO2 for EOR, vary widely from location to location and from region to region and can have a substantial impact on the feasibility of deploying CCS at a particular EGU.
Commenters 8974, 10024, 10393, and 10665 stated that most utilities are not located near enhanced oil and gas or geologic formations that may be able to permanently sequester CO2. The commenters additionally note that until those issues are resolved, no utility could realistically build a new coal-fired power plant under the proposed rule.
Commenter 8349 noted approval in Illinois for a 30 mile pipeline intended to carry CO2 from the plant site to the injection site, but stated that this fact only emphasizes the complications of locating the correct geology for sequestration in relation to a plant site.
Commenter 9648 noted, that sequestration of CO2 in large-scale geologic storage areas is not an option for North Carolina, particularly in areas where coal-fired EGUs are located.
The EPA recognizes that the USGS review cited in the proposed rule is an initial assessment of storage capacity and additional site specific work would be needed to demonstrate that a specific site meets the requirements for safe and secure storage under the UIC Class VI rules. Given the large areal extent of potential storage areas, the EPA believes that based on the USGS assessment suitable storage areas can be identified in proximity to new power plants.   
The distance to geology suitable for geologic storage is a factor that will be necessary to consider in siting new coal fired EGUs. The EPA believes that while there may be regional differences in the proximity to storage, there is widespread availability of storage capacity near likely new coal fired plants. While additional planning and permitting may be required, building pipelines to transport CO2 to storage areas may allow for additional flexibility in siting EGUs. 
The USGS has identified storage capacity in North Carolina, primarily in offshore areas. Siting new coal fired EGUs in North Carolina may require transporting CO2 to storage areas by pipeline to offshore sub-seabed geologic formations. 
Commenter 10239 disagreed with the EPA's reliance on case law for the geologic sequestration requirement for coal-fired EGUs. With respect to EPA reliance on the "basic demand" theory, under which it claims it can ban new coal-fired EGUs under Section 111 as long as basic demand for electricity can be met through other sources, the commenter cited Int'l Harvester Co. v. EPA, 478 F.2d 615 (D.C. Cir. 1973), noting that the court affirmed the EPA's decision not to extend the deadline for Title II emissions standards after concluding that petitioners failed to demonstrate that the necessary control technology was not available. In contrast, the commenter stated, the EPA proposes a rule that requires a technology "geologic storage" that is not, and never will be, available in some parts of the country. Further, the commenter noted in Int'l Harvester, the requirement to apply the "basic demand" theory was mandated by the statute, id. at 640; no such statutory mandate applies under Section 111. The commenter also stated the EPA's reliance on NRDC v. EPA, 489 F.3d 1364 (D.C. Cir. 2007) is equally unavailing. According to the commenter, NRDC involved a claim under Section 112 that certain control technology, while technically available, was too expensive. Id. at 1375-76. The commenter stated that in addition to the fact that the Section 112, maximum achievable control technology (MACT) is much more stringent that the Section 111 BSER standard, geologic storage faces significant technological, geological, and legal challenges, not merely economic challenges associated with implementing a control technology.
First, the EPA believes that a new steam generating affected source could meet the promulgated standard and be located anywhere in the country. There is available sequestration capacity in most areas of the country, and there are alternative ways a new EGU could meet the standard, not involving sequestration, should a new source decide to locate in an area where these sequestration opportunities are unavailable. See Portland Cement Ass'n v. EPA, 665 F. 3d 177, 191 (D.C. Cir. 2011), holding that the EPA could adopt section 111 standards of performance based on the performance of a kiln type that kilns of older design would have great difficulty satisfying, since among other things, there were alternative methods of compliance available should a new kiln of this older design be built. The court also noted that it was highly unlikely that such a new kiln would ever be constructed and that the EPA could consider this in adopting a standard of performance reflecting a different type of kiln design. Similarly here, there is significant doubt that a new steam generating unit would be sited in one of the few areas without ready access to sequestration or EOR opportunities (and commenters have supplied no information indicating that such a possibility actually exists). Finally, the promulgated standard of performance can be met without capturing CO2 or sequestering it, using alternative means of control which have no associated geographical constraints.
Moreover, as explained at 79 FR 1466-67, the legislative history to section 111 makes clear Congress did not intend that every new source would be able to meet a standard. The EPA is required, in adopting section 111 standards of performance, to consider impacts on energy (CAA section 111 (a)(1)), and has done so here, finding with ample record support that the final standards of performance for coal-burning EGUs will not impair electricity availability or reliability. See RIA chapter 4 and preamble section V.O.3.  This determination tracks well with the holding of International Harvester that under the technology-forcing CAA provision there at issue, the EPA could legitimately adopt a standard that would not be feasible for every vehicle type so long as basic demand is satisfied. Likewise, under Plywood MACT (NRDC v. EPA), the court held that the EPA was not required to create a separate subcategory to accommodate a particular type of plant for which control technology was more expensive, again indicating that technology-based standards do not have to be tailored to accommodate the circumstances of each type of source. The commenter's statement that MACT requirements are more stringent than those for BSER is not germane, since  this part of the opinion involved the EPA's authority to subcategorize under section 112 (d)(1), a provision which is identical in all material respects to the subcategorization authority for new source standards in section 111 (b)(2). See 479 F. 3d at 1376. 
Commenter 9514 stated that though the EPA's proposal intends to ensure captured CO2 emissions are permanently stored over the long-term, the rule does not contain sufficient enforceable requirements for permanent sequestration. The commenter provided the example that if the geologic storage facility reports high leakage rates, the rule does not require any action on the part of the EGU that was the source of the carbon in question. As a result, the commenter recommended the EPA work with the appropriate state and federal authorities to establish a comprehensive regulatory structure governing sequestration of captured CO2.
Commenters 1959 and 9396 stated that legal and regulatory uncertainties remain regarding widespread deployment of long term storage for both EOR and non-EOR operations.
Commenter 10039 remarked that the EPA has no regulatory structures or operating data to adequately demonstrate that permanent sequestration can be achieved and verified at a commercial scale, under commercial scale timeframes. 
Commenter 10039 stated that the EPA ignores that sequestration is not proposed or required in this or any other rule and has no regulations which require permanent sequestration, accounts for CO2 disposition from any entity, or monitors for or prevents the re-emission of captured CO2 and therefore cannot conclude that control of CO2 is required by this rule.
Commenter 9514 notes that GHGRP subpart RR does not provide mechanisms to assure containment of sequestered CO2. The EPA believes that the monitoring, verification and reporting plan required by subpart RR provides some measure of assurance when implemented in conjunction with Class VI (or II) requirements under the UIC program. The Class VI rules contain rigorous requirements for site selection, well construction and operation, testing and monitoring, corrective action, financial responsibility and post-injection site care and site care.  These requirements assure that there will be no endangerment of underground sources of drinking water from sequestered CO2 and should, by extension, reduce releases to the atmosphere. The Class VI Director may also require surface air monitoring and/or soil gas monitoring to detect movement of CO2 that could endanger a USDW.  UIC Class II regulations provide minimum federal requirements for site characterization, area of review, well construction (e.g., casing and cementing), well operation (e.g., injection pressure), injectate sampling, mechanical integrity testing, plugging and abandonment, financial responsibility, and reporting. UIC wells must undergo periodic mechanical integrity testing which will detect well construction and operational conditions that could lead to loss of injectate and migration into USDWs.  In conjunction with the subpart RR monitoring requirements, these standards likewise assure that injected CO2 does not endangering underground sources of drinking water and is not released to the atmosphere.
To comply with the CCS requirement in the rule an EGU must send its captured CO2 to an EOR or geologic sequestration site reporting under subpart RR. Facilities reporting under subpart RR are required to have a monitoring and leak detection program in accordance with the EPA-approved Monitoring Reporting and Verification (MRV) plan. Additionally, Class VI well owners or operators must develop and update a site-specific, comprehensive emergency and remedial response plan that describes actions to be taken (e.g., cease injection) to address potential events that may cause endangerment to a USDW during the construction, operation, and post-injection site care periods of the project (40 CFR §146.94). Geologic sequestration sites operating under a Class VI permit must continuously monitor the operation, and, injection must cease if there is evidence that the injected CO2 and/or associated pressure front may cause endangerment to a USDW (40 CFR § 146.94(b)). Once the anomalous operating conditions are verified, the cessation of injection, as required by UIC permits, will minimize any risk of release to air. The EPA believes that the protections provided by the existing regulatory framework demonstrate sufficient enforceable requirements to minimize leakage. 
The EPA cites several studies that have demonstrated the effective and safe storage of CO2 in EOR operations including the SACROC Unit in the Permian basin which has been injecting CO2 since 1972, the Weyburn oil field in Saskatchewan, the Sleipner gas storage project in the North Sea, Snöhvit in the Barents Sea, and In Salah in Algeria, which have all been operating for many years. Under the DOE Phase III Regional Carbon Sequestration Partnership six projects are currently conducting large volume injections, and one, the Cranfield Early Test has injected over 8 million metric tons of CO2 since 2009. The U.S. experience with large-scale CO2 injection, combined with ongoing research, development, and demonstration programs in the U.S. and throughout the world, provide confidence that the storage can be achieved and verified at a commercial scale, under commercial scale timeframes.
Commenter 9666 provided a discussion about characteristics of CO2 storage. Specifically, the commenter stated that USGS concludes the Gulf Coast area contains almost 60% of the national CO2 storage capacity in deep saline reservoirs.
The USGS assessment estimates a mean of 3,000 billion metric tons of subsurface CO2 storage potential across the United States which is 500 times the 2011 annual U.S. energy related CO2 emissions. If 60% of this capacity is in deep saline reservoirs in the Gulf coast, there will still be 1200 billion tons of storage in the remainder of the U.S.  -  more than 200 times the 2011 annual energy related CO2 emissions.
Commenters 9666 and 10036 stated that although DOE-NETL studies show that large areas of the US are potentially feasible for CO2 storage, CO2 storage at any one site will not be known until the site is assessed for specific criteria, such as a regionally extensive confining zone and injectivity. According to Commenter 9666, these criteria cannot be evaluated until the subsurface physical characteristics of a site are mapped or documented, an analysis that requires an extensive effort. Commenters 9666 and 10036 concluded that it can take at least five years to evaluate a site for CO2 storage potential. Commenter 10036 further stated that no geologic storage site has been characterized sufficiently to guarantee that it will provide secure permanent storage for a commercial-scale power plant.
Commenter 10098 stated that simply identifying a geologic formation as a potential candidate site is not enough to assume that it will actually be viable for carbon storage. Commenter 10098 further stated that nothing in the proposed rule evinces that the EPA has performed any analysis regarding the actual availability of geologic formations that could comply with the requirements of the Agency's Class VI injection well regulations.
Commenter 10048 stated that a significant investment is required to better characterize and quantify the country's sequestration capability. Commenter 10048 further stated that although a site many initially appear to be ideal for CO2 sequestration, it may be determined to be unworkable after further detailed investigation.
Commenter 9426 stated that to be feasible for CO2 storage, a site indicated to be favorable for CO2 storage must be fully characterized and shown to demonstrate particular geologic features, including CO2 containment in the target geologic formations. 
The EPA agrees with the commenters that each sequestration determination involves site-specific determinations, which require time and care to perform sufficiently. The site characterization requirements and permit review process for Class VI wells provide a comprehensive framework to ensure sites are suitable for long-term storage of CO2. The site characterization requires analysis of many factors including those mentioned by the commenters to ensure CO2 can be securely contained in the target geologic formations. If the site characterization process identifies unsuitable geologic conditions the developer may be required to remediate the site or to select an alternate storage location. This is one of the strengths of the Class VI and Class II regulatory programs, and why reliance on these standards is a reasonable way for the EPA to meet the requirement in CAA section 111 to consider non-air health and environmental impacts of a standard of performance.
The EPA issued Class VI permits to the FutureGen Alliance, a commercial scale power plant, to inject and sequester captured CO2 into deep saline formations pursuant to the Class VI regulatory standards. In doing so, the EPA found, and demonstrated in the administrative record for these permits, that the captured CO2 can be securely sequestered for long-term storage. The commenters are thus incorrect that no geologic site has been sufficiently characterized to guarantee that it will provide long-term storage for a commercial scale power plant.
Because of the lead times for planning, permitting and constructing a new power plant, the EPA believes the current state of characterization of potential geologic sequestration sites would not be a barrier to CCS. In the time since the commenter submitted comments, several Class VI permits have been issued by the EPA. These projects demonstrate that a GS site permit applicant could potentially prepare and obtain a UIC permit concurrent with permits required for an EGU.
As just noted, the EPA's analyses and findings supporting issuance of permits under the Class VI regulations to Archer Daniels Midland and FutureGen indicate the availability of "geologic formations that can comply with the Class VI injection well regulations". (Of course, the formation does not itself comply; even if the area of containment is otherwise suitable, the rules require comprehensive construction, monitoring, testing, financial responsibility and other requirements to assure complete and safe containment). The EPA's estimated compliance costs include the costs for sequestration site characterization and are based on the NETL CO2 Saline Storage Cost Model and documented in Carbon Dioxide Transport and Storage Costs in NETL Studies (DOE/NETL-2013/1614). The model includes costs for four sites simultaneously undergoing characterization, each having a 2-D seismic survey and one test well drilled to collect relevant reservoir data. One of these four sites is selected as the eventual storage site and has an additional test well drilled plus a 3-D seismic survey covering the Area of Review; pore-space rights and property access are also costed. 
Commenter 9426 stated CCS cannot serve as a system of emission reduction without a suitable site for carbon storage or reuse that eliminates any emissions or limits on a continuous basis CO2 emissions to the ambient air. 
Commenter 9003 stated that it is inappropriate to require CCS as BSER when the infrastructure to accommodate new units only exists in some areas of the country.
Commenter 9600 stated that the proposal glosses over the availability of infrastructure needed to transport and sequester the CO2 captured by coal-fired EGUs with the proposed BSER.
The EPA has determined that partial CCS is the BSER that will meet the standard set in the rule, and suitable sites are available for geologic sequestration. A new SCPC with partial CCS can meet the limits on a continuous basis, thus reducing CO2 emissions to the atmosphere. The rule requires monitoring of emissions from the source to verify compliance with the standard. 
As discussed in previous responses, studies by the USGS and DOE have identified the capacity to store large volume of CO2 across broad areas of the country. Many of the areas without saline storage potential are not expected to have new coal-fired EGUs built without CCS for legal or practical reasons. The EPA believes that the rule will advance CCS technology and spur development of the necessary infrastructure to support broad development of CCS. 
Commenter 10618 noted the experiences of the Mountaineer CCS programs that indicated the complexity at every level of developing injection wells in regards to technical, financial, and schedule risks. Commenter 10618 further noted that the agency failed to properly account for various design and development barriers in their evaluation of CCS as BSER.
Each sequestration site involves highly site-specific circumstances. A monitoring program and its associated infrastructure (e.g., monitoring wells) and costs will be dependent on site-specific characteristics, such as CO2 injection rate and volume, geology, the presence of artificial penetrations, among other factors. It is thus not appropriate to generalize from AEP's experience, and thus not appropriate to assume that other sites will require the same number of wells for site characterization or injection. In this regard, we note that the ADM and FutureGen permits for Class VI wells involved far fewer injection and monitoring wells than AEP references.
The commenter's reference to the experiences with the Mountaineer project is not reflective of the rule for new fossil fired EGUs. The Mountaineer CCS project was an early pilot scale development project to demonstrate the commercial viability for retrofitting an existing coal-fired power plant. The plant was not initially sited and constructed to consider the needs and technical requirement of CCS, but initial assessment indicated that the plant may be suitable for retrofit and associated CCS storage. The project was cancelled in July 2011 due to several factors including economic and policy conditions; however, the project increased the understanding of technical and project risks associated with CCS development. In the time since the Mountaineer project was initiated, there have been numerous technical advancements, and much has been learned to facilitate the development of CCS projects. The EPA has evaluated potential design and development barriers for CCS as part of the BSER analysis, and has concluded that there are no insurmountable technological, legal, institutional, regulatory or other barriers that would prevent broad deployment of CCS.
Commenter 9194 stated that there is no factual basis on which the EPA may assert that sequestration technology meets the required three part test for Section 111 technologies-that it is widely usable and technically and economically feasible. Commenter 9194 further stated that the EPA has not examined the entire system and fails to include in the standard the critical components--sequestration, transportation and monitoring--to assure emission reductions are accomplished.
Commenter 9648 agreed with the EPA's conclusion that there is not sufficient information and knowledge about geologic sequestration and the commenter believes that the EPA's statements about CO2 storage confirm that this technology is not BSER.
The commenter's legal argument is addressed in section 2 of this document. Briefly, there is no requirement in section 111 that a standard of performance address the fate of captured pollutants which are not emitted to the atmosphere. Rather, there is a requirement that non-air health and environmental impacts of a standard be considered, and the EPA has done so here, documenting that captured CO2 will be safely transported, accounted for, and sequestered over the long-term (in Class VI or Class II sites).
The comments are also factually mistaken. CO2 transport is demonstrated many times over. A substantial network of CO2 pipelines exist, and are comprehensively regulated  under standards adopted by the U.S. Department of Transportation Pipeline Hazardous Materials Safety Administration found at 49 CFR part 195 (Transportation of Hazardous Liquids by Pipeline). Sequestration of captured CO2 is likewise comprehensively regulated under the regulations for underground injection. The UIC Class VI requirements facilitate injection of CO2 for GS, while protecting human health and the environment by ensuring the protection of underground sources of drinking water. Moreover, the EPA has issued class VI permits under the Class VI program, and obviously would not have done so without the administrative record for each permit demonstrating that geologic sequestration of captured CO2 in the injection sites was both technically feasible, and fully protective.
Finally, injection of anthropogenic CO2 for EOR has a many decades long operating experience, is well understood, and has been successfully applied.
The EPA's recognition that additional work is needed to advance the understanding of certain aspects of sequestration should not be construed to suggest that there is currently insufficient information or knowledge to evaluate the technical feasibility and availability of CCS. The EPA has documented many successful projects that demonstrate that the technology meets the requirements for BSER. 
Commenter 9666 stated that because any NSPS must actually reduce emissions, the EPA must show that its proposed standard based on CCS contains achievable limits on the CO2 emitted from sequestration sites receiving separated CO2 from regulated new sources. According to the commenter, the EPA has not made, and cannot make, this showing. Furthermore, the commenter stated that the EPA provides no evidence that the separated CO2 will remain in geological storage, and does not require such storage in the proposed rule. Commenter 9666 stated the EPA's proposed rule does not even evaluate permanent geological storage of large volumes of CO2, much less find that such storage has been demonstrated.
See Section V.N.5 of the final rule preamble of the NSPS for the EPA's response to this comment. 
As described in previous responses within this section, the EPA has evaluated GS of large volumes of CO2 through a review of several large scale commercial CO2 injection and storage cases as well as the latest research and development conducted by DOE and has concluded, based on these examples, that such storage has been demonstrated. Additionally, the effectiveness of long-term trapping of CO2 has been demonstrated by natural analogs in a range of geologic settings where CO2 has remained trapped for millions of years. 
Commenter 1902 stated that knowledge about potential formations that might be suitable for permanent storage of commercial volumes of CO2 produced by a power plant is incomplete. Commenters 1902 and 9602 stated that it is not feasible or demonstrated to hold the CO2 volume for hundreds and perhaps thousands of years. Commenter 10036 further stated that there is little experience injecting CO2 into coal seams for permanent storage because of various setbacks. Commenter 7977 noted that the proposed regulation provides no scientific evidence of long-term storage of CO2.
Commenter 10095 stated that limitations and uncertainties regarding the adequacy of coal seams for CO2 storage remain and that access to coal seams may not be available due to the value of coal as a commodity. Commenter 10095 further stated that there is little experience injecting CO2 into hydraulically fractured coal seams for permanent storage due to their structure posing risks to their structural integrity and drinking water sources.
Commenter 9194 noted that deep saline aquifers have not been geologically assessed by either the private sector or the government on the level needed to adequately demonstrate that there are consistent caprock type formations to hold CO2 under pressure for hundreds and perhaps thousands of years.
As discussed elsewhere in this section, the EPA not only has found that large scale geologic sequestration of anthropogenic CO2 is possible and promulgated a regulatory framework for how to do so safely without endangering underground sources of drinking water, but has issued permits under the Class VI UIC program to conduct such geologic sequestration. Four of these permits were for injection of CO2 from a fossil-fuel (coal-fired steam generating EGU (FutureGen). As described in section V.N of the preamble to the final rule, the Class VI rules, complemented by the subpart RR reporting and monitoring requirements, assure as well that injected CO2 will remain sequestered without release to the atmosphere.
The EPA believes that existing data from DOE research programs show that CO2 can be sequestered safely and effectively. The monitoring programs required as part for the UIC Class VI permit and GHGRP subpart RR reporting will identify any such releases. The rule requires captured CO2 to be sent to a facility that will ensure the safe and secure long term storage, and document the volume received. 
The site characterization, modeling and monitoring requirements under UIC Class VI Program ensure that knowledge about potential formations for long-term storage is developed and reviewed prior to authorizing injection. Site characterization requires a significant level of geologic data collection, testing and modeling to demonstrate that the caprock (i.e., confining zone) can provide the containment necessary to ensure long term storage. 
The BSER analysis and RIA rely on GS in deep saline formations. Current estimates of storage capacity indicate that coal seams provide only a small percentage of total US storage capacity. 
Commenter 10664 stated that there is a strong implication that technologies that recycle captured CO2 to produce a sustainable fuel, which will subsequently release CO2 into the atmosphere when later combusted by a mobile source, do not permanently store or isolate that CO2 molecule from the atmosphere and therefore may not be used by EGUs to meet the CO2 emission limit.
The rule generally requires that captured CO2 be either injected on-site for geologic sequestration or transferred offsite to a facility reporting under 40 CFR subpart RR. The EPA recognizes there are emerging technologies alternative to geologic sequestration that are designed to safely sequester or otherwise utilize captured CO2 such that it is not released to the atmosphere. These technologies are not sufficiently advanced that the EPA is prepared to unqualifiedly structure this final rule to allow for their use, nor are there plenary systems of regulatory control and GHG reporting for these approaches, as there are for geologic sequestration. Nonetheless, as stated above, these technologies not only show promise, but could potentially be demonstrated to show permanent storage of CO2. The final rule provides for a case-by-case adjudication by the EPA of applications seeking to demonstrate to the EPA that a non-geologic sequestration technology would result in permanent confinement of captured CO2 from an affected EGU.
Commenter 9513 agreed with the EPA that CO2 injection into geologic formations is technically feasible and that the EPA's decision to move forward with a CCS requirement is justified, but also noted that more work needs to be done to ensure that the injected CO2 will remain sequestered for geologic time frames and will not cause or contribute to unintended adverse consequences. Commenter 9513 stated that the EPA must work with the appropriate authorities to develop a better technical understanding of the risks and develop definitive site characterization, monitoring and remediation protocols and a comprehensive regulatory scheme for geologic sequestration.
Facilities that inject CO2 for long-term storage must obtain a UIC Class VI permit. The UIC Class VI program requires extensive subsurface analysis, computational modeling to delineate the project area (the "area of review") and monitoring, as well as post-injection site care and site closure to ensure the CO2 will remain sequestered for long periods. The EPA has developed detailed guidance documents for UIC Class VI permit applicants regarding project plans, well construction, site characterization, monitoring and remediation protocols. Research is being conducted by DOE through the National Risk Assessment Partnership to develop risk assessment tools to support geologic sequestration project risks and ensure safe, long-term storage. 
The EPA believes that there is a comprehensive regulatory framework for geologic sequestration that includes the SDWA UIC Class VI rule, CAA GHGRP Reporting Program rule, the RCRA CO2 Hazardous Waste Exemption and DOT pipeline safety standards. These federal rules provide the basic framework for the safe and secure storage of CO2. 
The Class VI permits issued to Archer Daniels Midland and FutureGen reflect the EPA's findings, documented in the administrative record for each permit, that the sequestration sites at issue were suitable for long-term, secure and safe storage of large volumes of CO2. 
Commenters 9666 and 9774 stated carbon sequestration has not been proven on a long-term basis and CCS has not been implemented within the utility sector to the extent necessary for setting an NSPS. Commenter 9666 stated there is no relevant operating experience to support a finding that permanent geological sequestration of CO2 on the scale required for use with commercial power generation has been adequately demonstrated, or that any level of CO2 emission from sequestration repositories is achievable under the range of relevant conditions for the industry as a whole.
Commenters 9197 and 9596 noted that experts and stakeholders have raised significant questions about the long-term feasibility of sequestering large amounts of CO2 underground.
EPA cites several examples of CO2 injection sites that have been in operation for many years, including the SACROC site in Texas that has been safely injecting CO2 for more than 40 years. The EPA believes that the examples provided demonstrate that the three components of CCS, capture, transport and storage, have been adequately demonstrated and support the development of this NSPS. Monitoring data from injection sites in a wide range of geologic settings indicate that CO2 can be sequestered safely and effectively.
Commenters 10036 stated that the US could potentially store billions, maybe trillions, of tons of CO2 in deep saline formations (based on the Carbon Atlas), but sustained operations and monitoring of CO2 in saline formations in the US have not progressed beyond the demonstration phase. Commenter 10095 stated that the US could potentially store more than 12 billion tons of CO2 in deep saline formations, according to a DOE report. Commenter 10095 further stated that saline formations must demonstrate particular geologic features, including CO2 containment in the target geologic formations and non-interference with underground sources of drinking water. Commenter 10095 noted that CO2 storage in saline formations is occurring but not with CO2 captured from an EGU.
Commenters 9774 stated that carbon sequestration capacity is not proven and available at all potential sites of a new coal-fired generating unit. Commenters 0587 and 10036 stated that carbon sequestration has not been proven on a commercial scale. Commenter 9774 noted that the EPA identifies the carbon storage capacity in North America while also acknowledging that virtually all of this capacity is unproven. According to Commenter 9774, the EPA must rely only upon proven sequestration sites in the analysis of CCS. 
Commenter 8925 cited a real-life example studied by the SECARB partnership to illustrate that the area in the subsurface occupied by injected CO2 emissions from a single EGU will likely extend over many square miles and stresses the importance of characterizing and utilizing large regional reservoirs for storage due to the large quantities of CO2 from multiple EGUs.
Commenter 10031 stated that significant uncertainties exist with regard to candidate sites for sequestration. 
Commenter 9396 referred to a statement from API stating that there are significant challenges to scaling up CCS for EGUs.
The monitoring and operational experience gained from EOR projects over the past 40 years is directly applicable to storage in saline formations, and provides a strong basis for demonstrating the feasibility of CO2 storage in saline formations. Large scale demonstration projects such as Cranfield and Illinois Basin Decatur Project further support the feasibility of saline storage. Prior to receiving a UIC Class VI permit the applicant must demonstrate that geologic features at the proposed injection site ensure CO2 containment in the target geologic formations and that the GS project would not impact underground sources of drinking water. 
The response to Commenters' 0587, 10036 and 9774 assertion that sequestration has not been proven on a commercial scale is addressed elsewhere in this section. 
The review process for UIC Class VI permit applications will address the commenters' concerns that regional reservoirs are used for storage due to the large quantities of CO2 from multiple EGUs. The rigorous review and ongoing monitoring required under UIC Class VI will reduce the uncertainties that exist with regard to candidate sites for sequestration. 
Commenter 9666 stated the adequate demonstration of CO2 storage will depend on the resolution of numerous technical issues and that sequestration of CO2 generated by a new source may not prevent the emission of that CO2 to the ambient air. According to the commenter, CO2 must be injected at extremely high supercritical pressures to enter either a saline reservoir or a depleted oil and gas reservoir. Once injected below the surface, supercritical CO2 is buoyant and will both rise to the top of the storage formation and radiate outward from the injection point in a horizontal manner below the caprock layer. The commenter stated it is essential that the geology of a carbon storage site ensures a secure fate and that CO2 does not migrate through fractures to penetrate groundwater reservoirs and is not released to the ambient air through abandoned wells.
Commenter 8966 stated that carbon storage raises many safety, environmental, and liability issues that have not been adequately demonstrated by the EPA. Commenter 8966 noted that the reservoirs required under the CCS model must contain a capacity not yet achieved or tested in practice. Commenter 8966 raised concerns that sequestration on such a large scale poses severe risks in the event of reservoir leaks that can rise to the ground surface.  Commenter 8966 further stated that a fundamental lack of understanding in the physics of CO2 leakage and the processes that control leakages dictates that development of large CO2 reservoirs is not ready for commercial implementation.
Commenter 1747 stated that any standard that relies on sequestration must ensure that CO2 injected stays out of the atmosphere, and that the parties required to meet the standard are responsible for the leakage. 
Commenter 7433 stated that there is a concern with leakage of stored CO2 and whether that will compromise CCS as a GHG emission mitigation option.
Commenter 9202 stated that the storage of captured CO2 must be secure for an exceptionally long time frame and that leakage of stored CO2 negates all benefits of capturing emissions.
The site characterization and monitoring requirements in the UIC Class VI permit program and the monitoring required by Subpart RR provide a framework to ensure that the geology of a carbon storage site provides a secure storage and that CO2 does not migrate through fractures to endanger underground sources of drinking water and does not migrate through abandoned wells or other leakage pathways (UIC Program) and is not released to the atmosphere (Subpart RR). Site characterization requires extensive data collection and computational modeling to predict the behavior of CO2 in the subsurface, and ongoing monitoring to demonstrate that the CO2 is behaving as predicted. These computational models apply fundamental and advanced understanding of the chemical and physical interactions of CO2 in the subsurface. UIC Class VI regulations require computational modeling to determine the fate of the CO2 as part of the Area of Review. Specifically, 40 CFR 146.84(c)(1) states that owners or operators of Class VI wells must predict, using existing site characterization, monitoring and operational data, and computational modeling, the projected lateral and vertical migration of the CO2 plume and formation fluids in the subsurface from the commencement of injection activities until the plume movement ceases, until pressure differentials sufficient to cause the movement of injected fluids or formation fluids into a USDW are no longer present, or until the end of a fixed time period. The requirement goes on further to specify the model must take into account any geologic heterogeneities or other discontinuities. The MRV Plan that is prepared under subpart RR requires an assessment and risk evaluation of potential leakage pathways. 
Several large CO2 injection and storage examples have demonstrated that CO2 can be sequestered at a capacity necessary for commercial implementation. The SACROC Unit in the Permian basin has injected CO2 since 1972 for enhanced oil recovery purposes. One study evaluated a portion of this project, and estimated that the injection operations resulted in final sequestration of about 55 million tons of CO2. This study used modeling and simulations, along with collection and analysis of seismic surveys, and well logging data, to evaluate the ongoing and potential CO2 trapping occurring through various mechanisms. The monitoring at this site demonstrated that CO2 is trapped in geologic formations. In a separate study in the SACROC Unit, the Texas Bureau of Economic Geology conducted an extensive groundwater sampling program to look for evidence of CO2 leakage in the shallow freshwater aquifers. No evidence of leakage was detected. An extensive CO2 leakage monitoring program was conducted by a third party (International Energy Agency Greenhouse Gas Programme) for 10 years at the Weyburn oil field in Saskatchewan, during which time over 16 million tonnes of CO2 have been stored. The Cranfield test in Mississippi has stored over 4.7 million metric tons of CO2 in a saline reservoir since 2009, with no evidence of leakage. At the Sleipner site in Norway more than 15 million tons of CO2 have been stored in the saline aquifer with no evidence of leakage. The EPA believes that these large scale injection and demonstration projects show the capacity to store CO2 from EGUs on a commercial scale.   
Commenter 9666 provided the following technical information related to sequestration: to comply with the proposed standard, a 500 MW boiler firing bituminous coal at a gross heat rate of 8,500 Btu/kWh and an 80 percent capacity factor would need to separate almost 1.2 million tons of CO2, which would produce approximately 1.5 million cubic meters of CO2 at supercritical pressure annually for sequestration. 
The Archer Daniels Midland Class VI permit is for injection and sequestration of an estimated 5.5 million tons of CO2. The FutureGen Class VI permits are for 22.5 million tons of injected CO2. These projects are of a magnitude comparable to the (hypothetical) example in the comment. We repeat that the EPA's findings, and administrative record supporting those findings, is that each site was capable of safely sequestering the injected CO2 indefinitely consistent with the requirements of the Class VI regulations. As explained in section V.N.3 of the preamble to the final rule, these standards also assure that there will be no release of sequestered CO2 to the atmosphere.
The commenter's estimate of the mass and volume of CO2 produced from a standard 500 MW boiler is consistent with the estimates DOE has used as guidelines for the Regional Carbon Sequestration Partnership Phase III Demonstration projects for large scale injection and storage. Under the DOE Phase III Regional Carbon Sequestration Partnership six projects are currently conducting large volume injections, and one, the Cranfield site has injected over 8 million metric tons of CO2 since 2009. Globally, there are commercial integrated CCS facilities safely and effectively sequestering captured CO2 into deep geologic formations at rates of one million tonnes per year.
Commenter 9194 noted that CO2 currently used in the oil and gas sector in the US and worldwide is recycled, not permanently stored, and that CO2 in this industry has a residence time of only days. The commenter additionally noted that this is in sharp contrast to the idea of CO2 storage for the power sector that the EPA is proposing.
The EPA does not agree with commenter's assertion that CO2 currently used in the oil and gas sector is recycled, not permanently stored. In the EOR process some of the CO2 is recycled but large amounts are stored via residual trapping, solubility trapping and stratigraphic trapping. Direct observation of trapping in the deep subsurface is not possible but numerous monitoring and modeling studies have demonstrated the permanent storage of CO2 in EOR operations. The SACROC Unit in the Permian basin is one example of long term CO2 storage. A 2010 study evaluated the trapping mechanisms using numerical models, and identified residual trapping and solubility trapping as the dominant trapping mechanisms over a 200 year modeling period. The volumes of CO2 injected and stored at SACROC are consistent with the volumes expected from plants covered under this rule. 
Commenter 10035 stated that excessive emphasis on underground injection and geologic sequestration as approaches to achieve the standards would be shortsighted, as it would limit the amount of CO2 that could be sequestered, reused, or recycled by other means. Commenter 10035 further stated that excluding CO2 utilization would directly impact investments in the US manufacturing base and development of innovations to reduce greenhouse gas emissions.
Commenter 9317 stated that a blanket prohibition on alternatives to geologic sequestration actually discourages the development of alternatives and that the EPA should instead propose a streamlined approach for approving alternatives to CCS that states could consider.
. The final rule provides for a case-by-case approval mechanism for alternative CO2 storage methods.
Commenter 10098 stated that EPA has not grappled with findings that many potential geological storage areas could be impacted by shale gas development. Commenter 10098 noted that a recent study found that as much as 80% of deep saline aquifers overlap with potential shale-gas production regions (commenter provided journal article citation). Commenter 10098 further notes that this could lead to the EPA imposing restrictions on the very gas production activities that make a severe curtailment of new coal-fired electricity generation possible.
The presence of shale gas development areas that are spatially coincident with areas potentially suitable for geologic storage or EOR does not necessarily preclude the use of the saline or oil bearing zone for sequestration. Under the Class VI permit, each sequestration site must undergo a rigorous risk analysis to determine if safe long-term storage is possible. The depth and thickness of potentially productive shale formations would be evaluated along with the depth of the saline storage formation, and the type and thickness of the intervening geologic layers. Only areas where storage locations are incompatible with oil and gas extraction would potentially affect production.
Following Class VI geologic storage site closure, the owner or operator of a Class VI injection well must record a notation on the deed to the facility property (40 CFR 146.93(g)). The notation must state that the land has been used for GS, the name of the state agency, local authority, and/or tribe with which the survey plat was filed, as well as the address of the EPA Regional Office to which it was submitted; and the volume of fluid injected, the injection zone(s), and the period over which the injection occurred. This notification will enable regulatory authorities to impose appropriate conditions on subsequent drilling activities that may penetrate the injection and confining zone(s). 
Commenter 9683 noted that scale-up presents perhaps even thornier complexities for storage than for capture. For large-scale storage, an area potentially dozens of square miles across must be studied. A confining zone free of transmissive faults and fractures must be present and must be of sufficient thickness, and the formation must exhibit porosity and permeability to accommodate high-volume injections over decades. Furthermore, storage of tens of millions of tons of CO2 in a saline or other non-EOR formation requires aggregation of property rights across a broad area potentially encompassing not only areas to which the CO2 may migrate, but areas into which brines and other materials displaced by CO2 injections may reach.
The commenter is correct that large areas may need to be studied for certain storage sites. Site characterization is critical to operating safe and effective geologic sequestration projects and identifies potential risks and eliminates unacceptable sites. Large scale subsurface studies are commonly required in other industries including mining, oil and gas exploration, water resources and waste management. 
See the Section 6.3 topic titled Geologic Sequestration Property Rights for responses to property rights comments.
Commenter 9600 noted that while the proposal recognizes that CO2 sequestration, or storage or utilization in EOR activities at an EGU site would require pipeline transportation and subsurface injection facilities offsite, the proposal offers no rational discussion regarding the availability of these facilities. Additionally, Commenter 9600 noted that the proposal does not address physical or economic considerations associated with CO2 storage. 
Commenter 10618 stated that the equipment to capture CO2 is large and an entire system capable of treating the effluent of a power plant requires extensive tracts of land. The commenter cites an AEP/Alstom study and further states that size alone would preclude the use of the technology at many existing power plants and must be carefully considered in the design of any new power plant. 
The commenter is mistaken. The physical and cost issues associated with CO2 sequestration (i.e. storage) were discussed in detail at the proposal. See  e.g. 79 FR at 1482-1484 (preamble); Draft RIA (EPA-452/R-13-003) at pp. 5-29 to 30 and NETL Cost and Performance of PC and IGCC Plants for a Range of Carbon Dioxide Capture (DOE/NETL-2011/1498) at pp. 46-50. The EPA has addressed the availability of CO2 pipelines in the Section 6.3 topic titled CO2 Transport, and the availability of offsite subsurface injection facilities in the Section 6.3 topics titled Geologic Sequestration and Enhanced Oil Recovery and CO2 Utilization. 
The EPA discusses the physical considerations associated with CO2 storage in terms of the capacity estimates of saline storage areas and notes that 95% of the current coal fired plants are within 50 miles of potential storage sites. The proposal also discusses the availability and location of EOR, where injection facilities, pipelines and other supporting infrastructure are in operation. An extensive discussion of economic and cost considerations is presented in the Regulatory Impact Analysis for the NSPS, and summarized in the preamble to the rule. 
The EPA agrees with the commenter that additional equipment is required for CO2 capture at EGUs and the footprint of some existing plants may not allow for the equipment to be installed. Today's rule applies to new plants exclusively which can be sized to accommodate the equipment. 
With regard to AEP and Alstom statements, contemporaneous statements of both companies extolled CCS, praised the success of the Mountaineer project, indicated that a regulatory mandate for CCS would further investment in and further deployment of CCS, and that the project was not implemented full scale due at least in part to the absence of such regulatory certainty.  See preamble section V.I.4.  See also statement of Alstom senior Vice President for Power and Environment Policies Joan Macnaughton (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.  But without clear policies in place outlining options for cost recovery, power generators are hard-pressed to invest in its continued refinement."  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 sources, such as wind, solar, geothermal, hydro and nuclear."  See http://www.alstom.com/Global/US/Resources/Documents/Press%20Releases/PR_JMacN_CCSbriefing_FINAL.pdf
Commenter 10098 stated that it would not be unreasonable to assume that, in certain geographic locations with limited CO2 transportation and storage options and under certain market conditions, a power plant with CCS capability could find itself having to give away CO2 or even pay for the disposal of its captured CO2 stream, which reverses the EPA's prior position on the issue of selling CO2 for EOR without any explanation.
The BSER and regulatory impact analysis assume GS in deep saline formations. The EPA recognizes that some EGUs may not be located near EOR areas, which provide an opportunity to defray some of the cost associated with partial CCS, and may incur costs for the transportation and storage of CO2. 
Commenter 9195 noted a DOE document "Mitigation Action Plan for the W.A. Parish Post-Combustion CO2 Capture and Sequestration Project" and proposed the following questions to the EPA regarding DOE's view on carbon storage activities:
1. Does EPA fully agree with this assessment? (Explain EPA rationale/legal justifications)
2. If EPA does not fully agree, has or will EPA object? Why or why not?
3. (Commenter also asks to) Provide any documentation that EPA considered this or other determinations made by DOE or other agencies that CCS is a connected system that includes storage.
A response is not provided here as this comment is outside the scope of the NSPS. The referenced document relates to a National Environmental Policy Act (NEPA) mitigation plan for DOE's action of providing partial funding to construct an industrial CO2 capture system and pipeline, and conduct monitoring. The CO2 will be used for EOR and the EOR aspect of the project, although not funded by DOE, was included in the project description because the system components are integrated into the project concept and considered connected actions. 
Commenter 10786 also discussed the storage of CO2, stating that the EPA has not provided support for the position that CO2 losses downstream are expected to be modest. 
The EPA believes that CO2 losses downstream will be modest based on the review of monitoring data from numerous CO2 storage sites. The characterization, construction and operational requirements in the UIC Class VI permit and the monitoring requirements in subpart RR provide additional support to ensure safe operation and early detection of leakage. 
Commenter 8925 discussed the relative scale and relevant lessons learned from the three large scale projects in the world currently injecting CO2 at approximately one million metric tons per year. The commenter notes the following project comparisons and lessons learned:
   * Each project is only approximately one-third of the CO2 that would be stored by a single 1,000 MW coal-fired EGU, illustrating the need to rapidly expand our experience base to scales commensurate with full scale commercial power projects to improve technical certainty, operational reliability and a better understanding of project costs upon which sound financial investment decisions can be made. Commenter 9666 also echoed the need for an expansion of experience and commercial demonstration.
   * Adequate monitoring and analyses at the sites are critical to inform the operator of a potential problem and shut down of CO2 injection before the caprock is breached. 
   * There are significant risks associated with geologic uncertainty at storage site. The large volumes involved with full-scale CO2 storage and scarcity of information on saline formations may require that several attempts be made to identify specific injection sites with suitable storage capacity and formation injectivity. For example, project developers for the onshore ZeroGen project in Australia spent AU$90 million on site characterization activities before the project was abandoned because the formation was found to be uneconomical for large scale CO2 storage. Commenter 9666 also discussed the economic and temporal implications of assessing the viability of a site for storage, determining that the site is unsuitable, and then starting the evaluation process again at a different site.
Commenter 10097 stated that the proposal does not address physical and economic considerations associated with transport and storage. 
The EPA believes that the current experience with large scale capture and storage projects is applicable to larger systems, such as the 1000 MW plants the commenter describes. The selection of partial CCS as BSER will further technological development and improve operational reliability and provide a better understanding of project costs for larger projects. 
The current regulatory framework provides extensive requirements for operators to monitor and analyze site operations to ensure the safe storage of CO2. In particular the UIC permit requires monitoring to detect anomalous conditions that could indicate leakage. Failure of mechanical integrity would necessitate the cessation of injection in accordance with the UIC permits.
Site characterization is an essential element in reducing risks associated with geologic uncertainty at storage sites, and not all proposed sites will meet the requirements for demonstrating safe and secure storage of CO2. DOE has developed guidance for selecting sites, and through the Regional Carbon Sequestration Partnerships has conducted detailed geologic evaluations of regional areas to help focus the assessments and reduce the time and cost of site selection.
The response to the transportation considerations in this comment are addressed in the prior section. The EPA discusses the physical considerations associated with CO2 storage in terms of the capacity estimates of saline storage areas and also discusses the availability and location of EOR, where injection facilities, pipelines and other supporting infrastructure are in operation. An extensive discussion of economic and cost considerations is presented in the Regulatory Impact Analysis for the NSPS, and summarized in the preamble to the rule.
Commenter 9425 stated water use could also be an issue in many locations as it is estimated that the addition of an amine-based CCS system would double the consumptive water use of a power plant, which may be unacceptable in some locations. 
The commenter appears to exaggerate the extent of water use needed for post-combustion partial CCS. See preamble section V.O.2.
Enhanced Oil Recovery and CO2 Utilization
Commenter 9664 stated that EOR is an essential part of a widely available near term system for transportation and sequestration of CO2.
EOR provides an opportunity for EGUs to defray some of the cost of CCS using infrastructure that is already in place. Twelve states currently have active EOR operations, and 18 states are within 100 kilometers of active EOR areas. 
Commenters 10098 and 10239 stated that, without justification, the EPA arbitrarily and capriciously asserts that CO2 captured from coal-fired EGUs can be transported and sold for enhanced recovery of oil and other hydrocarbons and fails to account for the regulatory and economic conditions that may prevent or dissuade EOR operators from using anthropogenic CO2 in their operations. Commenter 10618 states that regulatory challenges for EOR operators may be significant as well, citing the October 2013 comments from U.S. EPA on the draft environmental impact statement for the proposed Hydrogen Energy California IGCC/CCS project. The EPA's comments note that for the Elk Hills Oil Field, the thousands of well bores on the site create a potential for leaking of the injected CO2, and the EPA recommended that the old wells with the potential for leaking should be located and permanently sealed. Commenter 10618 stated that the prospect of being required to locate and permanently seal "hundreds of wells" and "thousands of well bores" is simply not practical, far outside the typical scope of EOR operations, and alone would likely doom any CCS project from being developed, as the process is time-consuming and the outcome of requirements is wrought with uncertainties. 
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 with the commenters' example that locating and plugging wells is not practical and far outside the typical scope of EOR operations. The current UIC Class II permit process for EOR projects includes conducting studies that ensure USDWs are protected from endangerment during injection. This process requires identifying active and inactive wells within the Area of Review, and demonstrating that all wells are properly constructed or have been plugged in a manner that will not permit the movement of fluids into strata other than the permitted injection zone. Where new Class II wells are constructed, wells within their Areas of Review must undergo correction actions, including plugging or remediation, prior to injection to ensure protection of USDWs. Additionally, planning for EOR includes identifying and mitigating barriers that prevent full contact of CO2 with the oil, such as preferential flow paths or movement of CO2 into non oil-bearing areas, caused by manmade conditions such as improperly plugged boreholes and wells.
Commenters 9201, 9472, 9426, 9683, 9666, 9678, 10048, 10098 and 10239 stated that the EPA provides no support that a future coal-fired EGU will be reasonably close to one of the approximately 100 EOR sites in the country. Commenter 8024 disagrees with the EPA's view that potential EOR applications represent a viable path for capturing and sequestering CO2 emissions from utility-scale power plants. Commenter noted that EOR opportunities are inherently limited to petroleum-producing regions, or areas with available pipeline access, and do not extend to the full range of states to which the NSPS apply. Commenters 10036 and 10095 noted the limited availability of EOR as an option for new EGUs in certain regions. Commenters 9657 and 10017 stated that enhanced oil recovery (EOR) is not widely available across the U.S. Commenter 9657 noted that the vast majority of CO2 -EOR is conducted in oil reservoirs in southwest Texas and southeast New Mexico, along with eleven other states. Commenter 7977 noted that although the proposed rule has nationwide applicability, the fact that EOR seldom occurs in Kentucky prevents EGUs located in the state from relying on EOR to defray the costs of implementing CCS, making CCS not economically feasible. Commenters 1959 and 9657 noted that for large portions of the U.S., EOR cannot be viable, geologically. Commenter 10105 stated that Nevada's ability to employ CCS for enhanced oil recovery is limited, as Nevada has small oil fields, and the conditions of Nevada's oil fields are geologically unsuitable and are susceptible to leakage. Commenters 9678 and 10043 assert that EOR is not a widely available method and Commenter 10043 asserted that most utilities are not near EOR sites or geologic formations suitable for long term storage. Commenter 2471 stated that the projects used by EPA to justify CCS as BSER are EOR projects and none are planned to inject CO2 into geology that has no recovery opportunities for oil and gas. According to the commenter, by contrast, many coal and natural gas fired plants in the US are located in states with little or no oil and gas recovery opportunities.
Analysis of recent DOE and USGS storage resource assessments indicate that twelve states currently have active CO2 EOR operations and 18 states are within 100 kilometers of active CO2 EOR locations. To access the existing EOR areas, as well as other potential EOR locations not currently utilizing CO2 EOR, construction of CO2 pipelines is feasible. 
Any new EGUs proposed would need to be planned prior to siting and construction and new EGUs have several compliance options including constructing coal fired plants near EOR and transporting the electricity via transmission lines, or transporting captured CO2 to deep saline formations or other non-EOR sequestration sites. The costs for CCS either with or without EOR are consistent with the D.C. Circuit's criteria for determining that costs are reasonable. 
Commenters 9201, 9472, 9426, 9683, 9666, 9678, 10098 and 10239 asserted that the rulemaking places additional regulatory burdens on an EOR operator that it would not face if it accepted any other CO2 stream. Commenter 9666 asserted that EOR operators have stated that they will refuse to accept CO2 from EGUs under this rule because of the additional regulatory constraints on EOR operators that the EPA plans to impose.
The NSPS establishes a standard of performance based on a highly efficient SCPC using partial carbon capture and storage (CCS) as the BSER. Sequestration sites receiving and injecting the captured CO2 are required to obtain UIC permits and report under subpart RR of the GHGRP. Although the NSPS does not impose regulatory requirements on the transportation pipeline or the sequestration site, such requirements already exist under other regulatory programs of the Department of Transportation and the EPA. In order to ensure the EGU is compliant with the standard the EPA is reasonably relying on UIC requirements in combination with the subpart RR requirements to provide secure sequestration of captured CO2. 
Commenter 9772 expressed concern that federal rules will deter not encourage the use of CO2 captured by emissions sources in EOR operation. Commenter 9772 specifically noted that Subpart RR of the Greenhouse Gas Reporting Rules will allow an emitter to use EOR- - based storage only where the offsite injector reports the CO2 storage to the EPA, which would result in an emitter trying to mandate an EPA rule for an EOR operator now only subject to Subpart UU of the Greenhouse Gas Reporting Rule. This is a situation that would certainly lead to EOR avoiding the purchase of CO2 subject to those rules. Concern about Subpart RR compliance, commingling of purchased and other CO2, and rules governing storage would also lead to litigation. 
The Commenter is concerned that the use of subpart RR will discourage use of anthropogenic CO2. The EPA disagrees with this comment in several respects. First, the BSER determination and regulatory impact analysis for this rule relies on GS in deep saline formations, not on EOR. However, the EPA also recognizes the potential for sequestering CO2 via EOR, but disagrees that subpart RR is prohibitive to the use of EOR. The rule provides requirements for EGUs to verify that CO2 captured at an affected unit is geologically sequestered CO2 through an arrangement with EOR operators complying with the requirements of Subpart RR of the Greenhouse Gas Reporting Program (40 CFR 98.440 et seq.). This specification limits qualifying geologic sequestration operations only to those operations adhering to Subpart RR of the Greenhouse Gas Reporting Program and does not apply to EOR operations that do not report under subpart RR. Subpart RR requires that facilities that conduct geologic sequestration of CO2 for long-term containment in subsurface geologic formations, regardless of the class of Underground Injection Control permit that they hold, report basic information on the amount of CO2 received for injection; develop and implement an EPA-approved monitoring, reporting, and verification (MRV) plan; and report the amount of CO2 sequestered using a mass balance approach and annual monitoring activities. Reporting under subpart RR will not change the status of a Class II well. See preamble section V.N.5.a.
Commenter 8024 also stated that the agency's assumed $20/ton to $40/ton revenue stream from EOR CO2 sales is inadequate to offset the full costs of CO2 capture, compression and transport, which is recognized by proposed federal legislation such as S. 3581 (112th Cong., 2d Sess.)
The BSER determination and regulatory impact analysis for this rule relies on GS in deep saline formations, not on EOR. The EPA recognizes that the revenue stream from CO2 sales to EOR operators does not currently cover all costs associated with CO2 capture, compression and transport, but does provide a revenue stream to offset some of the costs associated with the implementation of partial CCS. 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).
Commenters 9201, 9505, 10786, 10087 and 10088 stated that many locations for coal-fired power plants have no CO2 pipelines and none proposed, therefore EOR technology cannot be representative. Commenter 10088 therefore suggested that the cost estimates are inadequate and incomplete, as requiring CCS in locations with no access to EOR will be far more costly than in locations within 50 miles of geology suitable for EOR.

Commenter 9487 stated EPA identifies only 13 states with in which carbon dioxide has been used in such formations for EOR and recognizes that EOR will not be "practically available" in all geographic locations. Thus, the commenter contends, meeting the NSPS will not be feasible and sustainable in up to 37 states. According to the commenter, the inability to build new coal-fueled generation in those states will be a function of the facility's inability to meet the NSPS itself, and not result from otherwise existing state or local factors (such as air quality or zoning limitations) disallowing an NSPS compliant facility.
First, the final standard assumes (conservatively) that captured CO2 will be sequestered for long-term containment. The preamble to the final rule explains our basis for finding that there is ample geologic sequestration capacity available in most parts of the country. The proposal also notes the possibility (borne out by experience) that captured CO2 can also be used for EOR in many areas. Thus, geologic sequestration is available in most, of the continental United States. EOR is available in certain areas, including the areas for which demand can be served by coal-fired power plants located in neighboring areas with EOR. Although there are some areas in which GS is not available, that is not an impediment to our defining BSER to be partial CCS because -- 
         a.       For at least some of those areas, demand in those areas can be served by coal-fired power plants built in neighboring areas with GS; 
         b.       For other of those areas, coal-fired power plants are not being built due to state law restrictions.
      In addition, new fossil-fired EGUs could utilize other compliance alternatives which do not involve sequestration. 

In the final rule the EPA identified partial CCS as the BSER and determined that estimated costs are reasonable compared to other options, even without EOR. Many EOR operators have found that pipelines longer than 50 miles are economically feasible in EOR projects. For example, Chaparral Oil recently constructed a 68 mile pipeline in eastern Oklahoma for its EOR operations in Osage County, Oklahoma. Denbury Resources completed the final section of the 325-mile Green Pipeline for transporting CO2 from Donaldsonville, Louisiana, to EOR oil fields in Texas, and also completed construction and commenced operation of the 232-mile Greencore Pipeline in 2013. NRG (Petra Nova) has begun construction on a project to capture CO2 from a power plant in Fort Bend County, Texas for transport to EOR sites in Jackson County, Texas through an 82-mile CO2 pipeline. These examples demonstrate that the cost of pipeline construction is not expected to be a constraint on using CO2 from new power plants affected by this rule. 
Commenter 8949 states that EPA should not use the Kemper County facility as a viable example that CCS is BSER. Commenter continues that this facility is only commercially-viable because of a suite of financial incentives and public subsidies, including revenue from CO2 sales for EOR. The commenter believes that it is unreasonable for the EPA to expect every new facility subject to this rule to be able to acquire federal financial assistance and revenue from EOR. Commenter 10048 also states that CCS will only be possible at locations where developers can take advantage of financial incentives
Southern Company Mississippi Power Kemper County Energy Facility has reached an advanced stage of construction and is expected to be fully operational in 2016. The advanced stage of the project and agreements for offtake of the CO2 for EOR demonstrate the availability of the technology to perform partial pre-combustion CCS at solid fuel power plants should plants choose to pursue this alternative means of achieving the standard of performance. While some funding for this project was provided by federal assistance the majority was funded privately by the utility. Sales of CO2 and other products will offset some of the costs of the plant. Subsidies to support emerging energy generation and pollution control technology are not unusual. Government subsidies in the form of tax benefits, loan guarantees, low-cost leases, or direct expenditures have supported development of fossil fuel as well as nuclear, geothermal, wind, and solar energy development.
Commenters 10036 and 10095 stated that delivery of CO2 is likely to be sporadic in quantity and timing due to constantly changing electricity demand. Commenter 10036 also noted that any issue at the injection site, or along the pipeline, impact would directly affect the power plant's ability to operate and to serve its customers while remaining in compliance with the NSPS emission limit. Commenter 8024 expressed concern that the EPA has not addressed the possibility that EOR or carbon sequestration facility operators (who may be third parties) may be unable to accept CO2 from power plants due to operational constraints, even when those plants would be required to continue producing power.
See section V.N.3.c of the final rule preamble of the NSPS for the EPA's response to this comment. The EPA disagrees with the premise of the comment that CO2 from an affected EGU must go to either EOR or saline storage, where operational constraints may cause the facility to be unable to accept CO2. As described in the preamble, the design of optional saline storage at Boundary Dam shows that captured CO2 from a fossil-fired EGU can go to both EOR, and the excess to a deep saline formation. 
Commenters 9513 and 10119 stated that the Proposed Rule considered the economic benefits of CO2 injection for EOR but did not consider the greenhouse gas emissions associated with production, refining, and combustion of additional oil reserves made available through EOR operations that otherwise might not be produced at all. The commenters asserted that the omission not only skews the costs and benefits assessment but may undercut or even eliminate any emissions reductions achieved by requiring CCS in the first place and undermine the purpose of the CAA.

Commenter 0588 stated that EPA, in assessing emission reductions from the proposed rule, failed to take into account the CO2 attributable to the oil that is recovered using gas captured at the coal plant and sold to oil companies to enhance EOR activities. According to the commenter, these emissions -a direct consequence of the NSPS- would significantly undermine the effectiveness of the proposed standard, and could even exceed the mass of the CO2 "saved" by partial CCS.  The commenter therefore stated that such a standard would be arbitrary and capricious, for "control technologies cannot be "best" if they create greater problems than they solve."  The commenter stated that EPA completely fails to take into account the expanded carbon footprint of the oil industry caused by its power plant rule, which is an impermissible omission by the administrator, because the emissions attributable to EOR are inherent to the NSPS as envisioned by the administrator, as opposed to being indirect in nature. According to the commenter, in the final rule, she must reasonably account for all CO2 emissions attributable to the NSPS as envisioned by the EPA.
Commenters 5532 and 1612 object strongly to the use of CCS as a mechanism to extract more fossil fuels from the earth that will, for the most part, be burned for energy and themselves contribute GHG's to the atmosphere. Commenters 5532 and 1612 are also concerned that this policy might indirectly encourage inadequately regulated oil-fracking operations and that it will lengthen, not shorten the time before the United States has done its fair share to protect the climate and that employing EOR is a form of fuel switching from coal to oil that works against EPA's efforts to reduce carbon pollution, fight climate change and protect the environment.
Commenter 9202 affirms the proposed Carbon Pollution Standards for New Power Plants as a good and essential component of policies to reduce U.S. climate impacts. However, the commenter has concerns about allowing the use of captured CO2 for enhanced oil and gas recovery and disagrees with the provisions in Section VII. E. 2. (c) that would allow the use of captured CO2 for EOR. Commenter notes that the purpose of carbon capture and storage is defeated when the "storage" leads directly to the production and combustion of other fossil fuels. The climate impact of that new oil or gas production should be added to the measured CO2 output from the power plant, and considered part of the 1,100 pounds of CO2 per megawatt-hour.
Commenter 10046 noted that substantially more carbon dioxide is emitted from burning this oil than is stored. Commenter 10046 explained that this means that the EPA's regulations will actually lead to more carbon dioxide emissions than no regulation at all.
Commenter 9513 references the study by the Texas Bureau of Economic Geology that assessed CO2 leakage at the SACROC field in the Permian Basin based on extensive groundwater sampling, as well as a study by Jaramillo et al. (2009) which looked at SACROC in addition to for other fields, and noted that the study found that the net life cycle GHG emissions for each project, was actually larger than the CO2 injected and stored in the reservoirs. In particular, the SACROC project had the largest net emissions, exceeding 300 million metric tons of CO2e. In its evaluation of the impact of using EOR for CCS, the EPA should consider this and other analyses that do not draw boundaries that exclude the emissions associated with the full life cycle of power generation and oil production and processing. 
Commenter 9034 stated that the EPA's BSER analysis should have taken into account CO2 emissions generated by combustion of the oil recovered, as required by CAA Section lll. Commenter further stated that the Competitive Enterprise Institute studied this issue and found that if a typical coal plant in compliance with the EPA's proposed emissions standard sells its captured CO2 for EOR, it would generate 1.3 million more kilograms of CO2 emissions per megawatt capacity annually than the plant would "save" using CCS. Commenter further stated that such a negative cost-benefit is unreasonable and unacceptable. 
Commenter 10680 noted that the EPA's proposed rule states that increased supply of anthropogenic CO2 may allow for further oil production from "depleted" oil fields, and will result in increased emissions, as CCS promotes EOR.
Commenter 10680 stated that the rule is fundamentally flawed in that the emissions the EPA wishes to reduce are instead increased as a direct result of the very practices the EPA prescribes to defend partial CCS as BSER. Commenter 10680 noted that new CCS equipped coal-fired power plants coupled with EOR projects inherently lead to net increases in CO2 emissions compared to identically constructed new coal-fired power plants without CCS systems. Commenter 10680 stated that science indicates that when CCS-EOR projects are examined in tandem these systems lead to net positive CO2 emissions.
The EPA reiterates that the BSER determination and regulatory impact analysis for this rule relies on GS in deep saline formations, not on EOR. 
Some commenters expressed concerns regarding the use of captured CO2 for CO2-EOR on a life-cycle basis. Most of those commenting on this issue reference the work by Jaramillo et al. (2009), while other comments present a back-of-the-envelope analysis related to emissions from the combustion of oil. These commenters are mistaken and EPA has in fact thoroughly considered these factors in finalizing the rule.
There is more recent work by Jaramillo and her colleagues, published in 2013, which has expanded on the 2009 work. The 2013 study compares the lifecycle GHG emissions from EOR operations using different sources for CO2 (assuming a 90% capture efficiency at the source in all cases) and to non-CO2-EOR methods. The 2013 study also includes a case of coal as a source of CO2 for EOR based on a reference coal IGCC plant with CO2 capture. Based on its assumptions, the 2013 study concluded that sources of CO2 derived from the scenario of coal as a source of CO2 for EOR result in about 31% lower net CO2 emissions per barrel of oil recovered compared to natural-source CO2-EOR. The paper further notes that if even 25% of the CO2 currently used for EOR came from the scenario of coal as a source of CO2 for EOR instead of natural CO2 sources, then approximately 5-6 million metric tons of CO2e would be avoided and sequestered per year. 
The EPA also notes that very important in the studies by Jaramillo and her colleagues, as well as other researchers that have investigated this topic, are the assumptions for CO2 utilization  -  the amount of CO2 needed to recover the incremental oil from CO2 -EOR  -  which then provides the basis for the amount of CO2 assumed to be stored in the reservoirs from the application of CO2-EOR; the quantity against which offsetting CO2 emissions is compared. A study by NETL   concluded that, by far, this was the most important parameter that can impact estimates of net emissions from CO2-EOR operations. Most studies use assumptions of CO2 utilization (and perhaps ultimately stored) as a result of CO2-EOR that are based on historical CO2-EOR operations. Most of these studies assume values for CO2 utilization on the order of 0.2 metric tons of CO2 per incremental barrel of oil recovered (Jaramillo assumed values ranging from 0.15 to 0.22). Current EOR operations in the Permian Basin have typical utilization values of 0.4 metric tons of CO2 per barrel of oil recovered. Alternative assumptions about CO2 utilization can result in significant increases in the volumes of CO2 stored per barrel of oil recovery, and result in significantly greater amounts of CO2 avoided and sequestered associated with CO2-EOR.
CO2-EOR has been successfully used for decades at many production fields throughout the United States, and is expected to continue for the foreseeable future. The decision to initiate or expand an EOR project is based on the economic viability of the specific project, and driven by broad market dynamics. In making a decision, EOR operators consider many cost components of the EOR project including engineering and design, new infrastructure development, electricity, and fuel costs in addition to the long term cost of purchasing CO2. These costs are balanced against the long-term demand for oil and the price EOR owners or operators can receive for the additional oil produced throughout the lifetime of the project. EOR operators will obtain CO2 from the most cost effective reliable source to make their projects viable. New sources of natural CO2 are available and awaiting the right market conditions for development. Likewise, many new anthropogenic sources other than EGUs such as gas plants are available to support the oil industry's expansion of EOR as market conditions allow. Thus, the industry is not dependent solely on the CO2 from new EGUs complying with this rule to generate additional oil from EOR. Even if one thinks of CO2-EOR's oil as additive, the amount of oil produced through EOR with captured CO2 from new EGUs would vary by project but would likely have a negligible impact on the overall demand for oil, and CO2-EOR provides a net GHG emissions benefit compared to non-CO2-EOR oil production processes due to the amounts of CO2 stored with CO2-EOR.
The commenter is incorrect in asserting that EOR will encourage additional hydraulic fracturing. Hydraulic fracturing creates preferential high permeability pathways for the produced fluids to flow towards the producing well, and would encourage the channeling of injected CO2 though these fractures. EOR projects are designed to create a large uniform front of CO2 to contact the maximum volume of the reservoir and not flow through preferential pathways. Furthermore, the commenter has failed to recognize that hydraulic fracturing is regulated by state and federal agencies. 
Commenter 9780 suggested that EGUs should not be held liable for emissions that may occur during storage or EOR, as this would require EGUs to rely on third-parties to ensure compliance with required operating permits. Commenter 10239 stated that just because a company can recover CO2 does not mean they have a contractual customer or partner willing to purchase the CO2. 
The BSER for the standard is partial CCS, which includes transport of captured CO2 to an on-site or off-site repository reporting under GHGRP subpart RR. This is the affected source's sole obligation regarding sequestration. However, the EPA is further reasonably relying on the protective requirements for injection wells under the Class VI and II UIC rules, complemented by the monitoring and reporting requirements of the GHGRP, to assure long-term and safe sequestration.
Commenter 9666 suggested that extensive time may be required to characterize the storage capability of depleted oil and gas reservoirs for EOR, although likely less than the minimum 5 years cited for saline reservoirs.
Because of the long lead times for planning, permitting and constructing a new power plant, the EPA believes the current state of characterization of potential oil and gas fields for CO2 EOR would not be a barrier to CCS with EOR. The EPA notes that DOE has conducted initial assessments of oil producing states and identified 220 million metric tons of storage capacity in oil and gas reservoirs. DOE has also conducted detailed CO2 EOR modeling of oil fields in nine regions of the United States to evaluate the application of "next generation" CO2-EOR technologies that would significantly increase the geographic extent and accessibility of CO2-EOR operations. 
Commenter 9514 noted that although permanent sequestration of CO2 via EOR is essential for rule's objectives, EOR operations have not historically been designed for this purpose.
The EPA reiterates that the BSER determination and regulatory impact analysis relies on GS in deep saline formations, not EOR. The EPA agrees that EOR operations have not historically been designed specifically for long term storage of CO2, but recognizes that CO2 storage associated with EOR is a common occurrence.
Commenter 10786 stated that the EPA fails to identify the technical and economic complexities of EOR, let alone analyze and discuss them. Commenter explained that the EPA incorrectly suggests, without reference or support, that the EOR industry is ready, willing and able to abide by the current CCS regulatory program, as further revised by the NSPS.
The EPA is reasonably relying on the existing protective standards for injection wells under the Class VI and II UIC rules, complemented by the monitoring and reporting requirements of the GHGRP.
The "current regulatory CCS program" for EOR is identical, for the most part, to the status quo before promulgation of the NSPS: EOR operators receiving CO2 from any source must comply with requirements for Class II injection wells. The requirement in this rule is reporting and monitoring pursuant to the subpart RR GHG reporting regulations. The EPA further notes that commenters to the Class VI rulemaking vociferously maintained that Class II operations are well understood, successful and have a long history of safe operation,  so the commenter's reference here to "technical complexity" is unclear. See e.g. Comments of Texas Carbon Capture and Sequestration Association ("gas storage is substantially similar to EOR and in those instances any regulations for Class VI should more closely resemble Class VI"); Comments of British Petroleum (safety of Class II requirements); Comments of U.S. Chamber of Commerce (same); Sandridge Energy (same).[,][,][,]
Commenter 10618 stated that EOR operators are in the business of timely and cost-effectively producing hydrocarbons, not providing reliable, affordable electricity or playing an integral role in the definition of a best system of emission reductions for another industry. EOR processes operate outside the influence of electricity demand, power prices, or generation outages. EOR operators are part of a larger industry where competition and opportunities for development continue to expand, especially with the growth of hydraulic fracking and shale- gas extraction techniques. In other words, if the power industry is able to provide another supply of CO2 to support EOR operations that is cost- effective, then EOR operators may be willing use it.
DOE-sponsored studies have shown that one barrier to expanded use of CO2 EOR is the availability of CO2. The NSPS will increase the availability and geographic distribution of anthropogenic CO2 for use by the EOR industry, which will provide additional opportunities for development of EOR fields. The increased availability and lower cost from these efforts will provide further cost-effective supplies of CO2 to support EOR operations.
Commenter 9735 stated that in addition to technical feasibility, economic feasibility is required for BSER technologies. This has yet to be demonstrated for CCS. All four of the projects cited by EPA relied on substantial government support and the analysis failed to demonstrate any financial benefit for utility companies or how rates will remain affordable for customers. Commenter 10017 stated that the EPA"s CCS technology examples also skews affordability because every plant uses EOR, which provides a substantial revenue stream to offset the high capital costs and operating costs of CCS. U.S. EPA should not develop a standard based on the economics relevant to only a fraction of the country. Commenter 10087 suggested that plants wouldn't be economic unless they can sell the CO2 for enhanced oil recovery.
The EPA reiterates that the BSER determination and regulatory impact analysis for this rule relies on GS in deep saline formations, not on EOR. The EPA analyzed the cost of partial CCS as a BSER as compared to other fossil fuel and non-fossil fuel options that achieve emissions control, and determined that the cost structure, with and without EOR, is reasonable as defined by case law. The EPA notes that under CAA section 111, an emissions standard may meet the requirements of a "standard of performance" even if it cannot be met by every new source in the source category that would have been constructed in the absence of that standard.  
Commenter 10618 stated that in some cases, EOR operators have been economically driven to minimize the quantity of CO2 left underground in favor of reusing the injected CO2 in other recovery operations.
The EPA recognizes that in some cases the economics of a particular EOR project may minimize the amount of CO2 left underground. Research by DOE has shown that increasing the volume of CO2 used in EOR projects will increase the amount of contact between oil and CO2, and will result in higher oil production. The use of increased CO2 volumes is one of the advanced technologies DOE considers "next-generation EOR" that improve the performance of CO2 EOR floods and result in significant increase in oil production and CO2 storage.  
Commenter 10034 stated that when promulgating rules for oil and gas extraction the EPA should evaluate the effect on EOR use and subsequent demand for captured CO2. Changes in demand for captured CO2 will affect whether the partial CCS technologies prescribed in this rule are actually economically viable for new coal-fired power plants, and whether any further implementation costs will be incurred. The commenter suggested that as the EPA promulgates new regulations related to the extraction of oil and natural gas using EOR, it should consider the cumulative effect on the incentives provided in this rulemaking. 
Commenter 9731 encourages the EPA to adopt a holistic approach to ensuring that CCS and the use of CO2 in EOR operations will be a viable option for controlling GHG emissions and must be mindful of the consequences of other significant regulations including the Underground Injection Control (UIC) Class VI rule and Subpart RR of the GHG reporting rules.
The commenter refers to rules governing oil and gas extraction which are outside the scope of this NSPS. The EPA notes that data from the Oil & Gas Journal Annual EOR survey has shown a steady increase in the number of CO2 EOR projects and the volume of oil produced by CO2 EOR over the last 20 years. Such expansion and increased oil production increase the demand for CO2. 
The EPA believes that the Underground Injection Control (UIC) Class VI rule and Subpart RR of the GHG reporting rules offer an integrated and complementary set of regulations that ensure an appropriate level of verification and accounting of CO2 from EGUs. 
Commenter 7977 stated that if the regulated industry as a whole does not have EOR as a means of reducing costs, CCS cannot be deemed adequately demonstrated to achieve a standard that may apply to the industry as a whole. Therefore, the EPA eliminates new opportunities for coal-fired EGUs in states where EOR is not readily available. 
As explained in section V.N.6 of the preamble to the final rule, and in the Regulatory Impact Analysis supporting the final NSPS, the EPA's consideration of cost for purposes of determining whether the BSER is adequately demonstrated is based on geologic sequestration of captured CO2. We show there that those costs are reasonable for new coal-fired EGUs. This cost analysis is, however, quite conservative. EOR opportunities should exist for some new sources, which have the leeway to site near EOR wells (e.g. the Boundary Dam EGU in Saskatchewan, or the Kemper facility in Mississippi, both of which are located proximate to EOR sites, and Boundary Dam is presently supplying CO2 for EOR operations). In addition, the final standard is a performance standard which may be achievable without using capture and sequestration. 
Commenter 10786 explained that nowhere in the NSPS does the EPA purport to describe the current commercial make-up of the EOR industry, which is relatively small, geographically focused in a handful of areas, and composed of a few companies. Commenter noted that the NSPS suggests falsely that there are many EOR companies dispersed throughout the United States who are poised to purchase and inject NSPS-compliant CO2. Commenter 8501 stated that the presumptions the EPA makes regarding enhanced oil recovery (EOR) as an ancillary form of partial CCS are not supportable, as there is little discussion of the actual demand of CO2 for EOR operations or pipeline delivery capability of the CO2 to the oil fields. If the demand currently existed and it were economically feasible, market forces would dictate greater interest in developing carbon capture projects to meet this demand. It is not apparent this demand has ever materialized or will ever materialize. If, as EPA projects, no one is going to build a coal-fired plant with CCS for at least ten years, then the EOR market to capture and transport the CO2 will never develop.
The EPA believes that the EOR industry is well established, geographically diverse, and is well positioned to expand operations in response to the availability of new sources of CO2. DOE has identified 220 million metric tons of storage capacity in 29 states with oil and gas reservoirs. DOE has identified "next generation CO2 EOR" technologies that improve the performance of CO2 EOR floods that will further increase the EOR production by making CO2 EOR available in reservoirs previously believed to be unsuitable for CO2 EOR. "Next generation CO2 EOR" will further expand the geographic extent and accessibility of CO2-EOR operations in the U.S. DOE sponsored studies have shown that one barrier to expanded use of CO2 EOR is the limited availability of CO2. 
Commenter 10786 noted that the optimistic picture of the EOR industry as potential purchasers of NSPS-compliant CO2 in the NSPS conflicts with the comparable assessments of associated storage via CO2-EOR in GHG PSD and EIS proceedings.
Previous assessments of proposed projects with respect to application of CO2 capture and transport were conducted on a site-specific basis and considered site-specific factors in the analyses. Analyses conducted by FERC and other agencies for the purposes of environmental impact assessments of proposed energy projects are conducted under a different set of criteria than the BSER and BACT analyses conducted under the CAA. A CAA New Source Performance Standard (NSPS) establishes a "BACT floor" that is to be considered in facility-specific BACT analyses conducted under the PSD program.   
The definition of BACT in the CAA specifies that "[i]n no event shall application of [BACT] result in emissions of any pollutants which will exceed the emissions allowed by any applicable standard established pursuant to section 111 or 112 of the Act." This has historically been interpreted to mean that BACT cannot be less stringent than any applicable standard of performance under the NSPS. See e.g. EPA, PSD and Title V Permitting Guidance for Greenhouse Gases, p. 20-21 (March 2011). Thus, upon completion of an NSPS, the EPA reads the CAA to mean that the NSPS establishes a "BACT Floor" for PSD permits issued to affected facilities covered by an NSPS. 
Commenter 10039 noted that EPA's Technical Support Document "Effect of EPAct05 on BSER for New Fossil Fuel-Fired Boilers and IGCCs" indicates that the studies EPA uses to justify the technical feasibility of CO2 injection and storage have shown that 20% or more of CO2 used for EOR is not permanently sequestered but is re-emitted or "produced" with the oil recovered. Consequently the EPA cannot utilize this technology as a justification of the technical feasibility of CO2 injection and permanent sequestration.
The Technical Support Document referenced by the commenter provides background information on several EOR projects, but none of the studies cited in the TSD show that 20% or more of the CO2 used is emitted. Furthermore, CO2 that is produced and recycled is accounted for and reported as part of the Greenhouse Gas Reporting Program requirements at 40 CFR Part 98 subpart RR. 
Commenter 10039 stated that the studies that the EPA cites are not empirical evidence of the permanence of the sequestration process, but instead estimate the viability of the EOR to store injected CO2. The EPA's analysis of the CO2 reduction potential of CCS does not account for the CO2 emissions that will occur. It is not reasonable for the EPA to claim that EOR is the likely method for permanent storage of CO2 but fails to acknowledge that CO2 from EOR does not actually permanently store all of the CO2 injected. It appears that data is extremely limited on the exact extent to which EOR operations permanently sequester CO2 and use of this technology as justification of the Best System of Emission Reduction must preclude any re-emission of CO2 or the reduction potential of the technology is overstated.
The EPA has cited several studies that have demonstrated the safe and effective storage of CO2 in EOR operations. CO2 has been injected in the SACROC Unit in the Permian basin since 1972 for EOR purposes. A study evaluated a portion of this project, and estimated that the injection operations resulted in final sequestration of about 55 million tons of CO2. In a separate study in the SACROC Unit, the Texas Bureau of Economic Geology conducted an extensive groundwater sampling program to look for evidence of CO2 leakage in the shallow freshwater aquifers. No evidence of leakage was detected. The International Energy Agency Greenhouse Gas Programme conducted an extensive monitoring program at the Weyburn oil field in Saskatchewan between 2000 and 2010 (the site receiving CO2 captured by the Dakota Gasification synfuel plant). During that time, over 16 million metric tons of CO2 were safely sequestered as evidenced by soil gas surveys, shallow groundwater monitoring, seismic surveys and wellbore integrity testing. An extensive shallow groundwater monitoring program revealed no significant changes in water chemistry that could be attributed to CO2 storage operations. The International Energy Agency Greenhouse Gas Programme developed a best practices manual for CO2 monitoring at EOR sites based on the comprehensive analysis of surface and subsurface monitoring methods applied over the 10 years. Furthermore, DOE has conducted surface and subsurface monitoring at numerous sites to assess the permanence of injected CO2. The studies provide no evidence to suggest that the CO2 from EOR cannot be permanently sequestered. 
Commenter 10618 stated that EPA is naive in assuming that the EOR experience to date could readily accommodate the requirement to install CCS technologies on fossil-fuel based generating units. Commenter referenced excerpts from the July 2010 PNNL-19557 report entitled "CO2 -driven Enhanced Oil Recovery as a Stepping Stone to What?" by Dooley, et.al. of the Pacific Northwest National Laboratory, which detailed the reasons that CO2 -EOR and CCS is not a viable option. Commenter 10618 stated the viability of opportunities for use of CO2 -EOR faces many challenges, including those associated with the validation and accounting for CO2 storage permanence. Current and past EOR practices have not been required to demonstrate permanent CO2 storage.
Experience from over 40 years of CO2 EOR provides an extensive history that demonstrates the availability of technologies required for geologic sequestration of CO2 captured from fossil fuel based generating units. The commenter refers to the analysis conducted by Dooley et al., but incorrectly summarizes the conclusion of the paper which is that CO2 EOR offers an opportunity to jumpstart climate change mitigation motivated CCS deployment, but is unlikely to be a major or mandatory step to large-scale CCS deployment. The determination that the BSER is adequately demonstrated and the 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 (provided the EOR site complies with the subpart RR reporting and monitoring rules). The BSER determination and regulatory impact analysis for this rule relies on GS in deep saline formations, not on EOR. 
Commenters 5532 and 1612 expressed objection to the inclusion of enhanced oil-recovery (EOR) in the types of carbon capture and storage (CCS) that the proposed standard promotes, even if it stimulates technology development. Commenters 5532 and 1612 do not dispute the science of carbon capture and storage, but are dubious of many of its proponents' claims with respect to the permanence and efficacy of such storage. Commenters 5532 and 1612 support carbon capture in cement or calcium carbonate, but not for additional petroleum extraction. 
The EPA is reasonably relying on the already-adopted, and very rigorous, Class VI well requirements in combination with the subpart RR requirements to provide secure sequestration of captured CO2. The commenters' support for CO2 storage technologies other than geologic sequestration is noted, however from a practical perspective these technologies are not sufficiently advanced that the EPA is prepared to unqualifiedly structure this final rule to allow for their use, nor are there plenary systems of regulatory control and GHG reporting for these approaches, as there are for geologic sequestration. Nonetheless, as stated above, these technologies not only show promise, but could potentially be demonstrated to show permanent storage of CO2. The EPA is establishing a mechanism in this final rule to provide for a case-by-case adjudication by the EPA of applications seeking to demonstrate to the EPA that a non-geologic sequestration technology would result in permanent confinement of captured CO2 from an affected EGU.
Commenter 10137 recommended that the EPA adopt a NSPS that includes provision for using CCS, and that the Agency modify its proposal to allow EGU operators to direct captured CO2 streams to EOR operators who comply with subpart W and subpart UU reporting. Commenter noted that this has been successfully implemented by the agency and the reporting community for several years, and imposes no new mandatory requirement on the EOR operator. Commenter 10137 stated that emissions reported under subpart W can be subtracted proportionately from total CO2 received from the EGU source, which must report the total CO2 sent under subpart PP. Taking this approach would allow for EOR operators to incorporate supplies of anthropogenic CO2 into the supply portfolio if, as, and when such anthropogenic CO2 may become available. However, Commenter noted that the Commenter is not suggesting that using subpart W and UU reporting could make the proposed rule workable, because there are many additional areas that need to be addressed, and the proposal as a whole is a barrier to CCS development.
Under subpart UU of the GHGRP, all EOR operators who inject CO2 are required to report only basic information including the amount of CO2 received. Under subpart W of the GHGRP, onshore oil and gas producers who meet certain criteria are required to report CO2, CH4 and N2O emissions for specified sources at basin-level facilities. While these reporting requirements help provide an understanding of CO2 received for injection and petroleum and natural gas system GHG emissions, neither provide verification of geologic sequestration of CO2. The reporting and monitoring required under subpart RR of the GHGRP is necessary and helps to provide a nationally uniform and practical methodology to provide assurance of long-term storage. 
Commenter 10043 noted that the oil industry captures relatively small amounts of CO2 to help move oil and gas more effectively, that fact says little if anything about the viability and adequate demonstration of CCS on the scale and in the locations that would be required for large coal-fired generating units. In addition, the commenter states that the EOR industry does not have the requisite experience with and technical knowledge of long-term CO2 sequestration. The EOR industry stores CO2 gas for short periods of time, and then transports it by pipeline for use at the next oil and gas recovery site, but the Proposed Rule would require permanent sequestration of CO2 in massive quantities.
The oil industry has successfully employed CO2 EOR for more than 40 years and currently uses more than 72 million metric tons per year of CO2 for EOR. DOE has determined that using today's technology, expanded EOR would demand and store approximately 9 billion metric tons of CO2. This number increases significantly if advanced EOR technologies are employed. While some of the CO2 injected may be available for removal, a large portion may be dissolved in formation fluids or immobile because it is residually trapped in small pores. The dissolved and immobile CO2 is permanently sequestered. 
Commenter 9657 noted that the EPA assumes CCS will be viable based on EOR revenue, and assumes that costs for EOR are uniform throughout the U.S. Commenters 9657, and 9734 and 10105 noted CCS can only be viable for plants near areas geologically suitable for EOR, which are located within sufficient proximity to pipelines that could transport the captured CO2 to EOR operations. Commenter 9734 explained that the EPA rationalizes that locations where EOR is not economical are limited due to other legal or practical limits on building coal-fired power plants, such as high reserve margins and large renewable energy targets. This assumption is not correct. There are numerous areas throughout the country where constructing new coal-fired power plants would be economical, but for the need to comply with EPA rules. In these areas, technical and regulatory uncertainty regarding underground sequestration makes CCS infeasible.
The commenter is mistaken that the EPA assumes CCS will be viable based on EOR revenue. As explained in section V.N.6 of the preamble to the final rule, and in the Regulatory Impact Analysis supporting the final NSPS, the EPA's consideration of cost for purposes of determining whether the BSER is adequately demonstrated is based on geologic sequestration of captured CO2 in deep saline formations, not EOR. The Regulatory Impact Analysis does not assume that EOR costs are uniform throughout the US. The EPA included an analysis with a "low EOR" case and a "high EOR" case. New EGUs could be located near EOR or deep saline formation sites or transport CO2 to the sites via CO2 pipelines. Alternatively new EGUs could be located closer to sequestration sites and provide electric power to customers through transmission lines. The demonstration of carbon dioxide capture, transport and storage at multiple sites has been presented in the preamble. 
Commenter 9513 noted that while permanent sequestration may be feasible in formations used for EOR, the performance of the oil and gas sector in fracking activities over the past few years and the BP Macondo oil well blowout do not provide a basis for a high degree of confidence that what may be feasible will actually occur in practice.
As noted in preamble section V.N, the already-adopted, and very rigorous, Class VI well requirements in combination with the subpart RR requirements provide secure sequestration of captured CO2. 
Commenter 9772 explained that economists at the University of Wyoming employed a method for predicting oil flows for a given reservoir and determined not all fields are suitable for EOR. Lithology, area, thickness, porosity and permeability can all affect a reservoir's viability. Higher oil prices and lower CO2 prices can also determine whether or not a reservoir will be economically viable for EOR, along with geologic, infrastructure and economic factors. Instead of relying on revenue to offset the costs of CO2 capture, EGUs will be required to add significant costs for transport and non-EOR permanent storage. Costs could range from $1 to $10 per ton for transport and $.5 to $10 per ton for permanent storage.
The EPA considers the costs of partial CCS at a level to meet the final standard of performance to be reasonable even without considering opportunities to further reduce implementation and compliance costs. We did not in the proposal  -  and we do not here in this final action  -  rely on any cost reduction opportunities to justify the costs of meeting the standard as reasonable, but again note the conservative assumptions embodied in our assessment of compliance costs.
Commenter 9472 provided a comment letter from the related rule "Draft Underground Injection Control (UIC) Program Guidance on Transitioning Class II Wells to Class VI Wells, EPA-816-P-13-004 (Draft Guidance)" and noted that, in light of the CAA stationary source regulatory programs in which CCS is playing a role, if the Draft Guidance does not meet the needs of the CO2-EOR industry, it also fails to meet the needs of the electricity generators that may be required to rely on EOR operators to comply with their CAA obligations. Commenter 9472 encourages the EPA to work with the CO2-EOR industry to create a certain regulatory framework that ensures its ability to enter into long-term CO2 offtake contracts with CAA-regulated EGUs that preserves existing CO2-EOR commercial operations and will provide the EPA with the human health and environmental protections that it is seeking. 
See preamble section V.N.6 and the Section 6.3 topic titled Geologic Sequestration for a response to this comment. Injection of anthropogenic CO2 into Class II wells does not force transition of these wells to Class VI wells  -  not during the well's active operation and not when EOR operations cease. We recognize the widespread use of EOR and the expectation that injected CO2 can remain underground and not endanger USDWs. 
Commenter 9195 stated that under the law, the advice of scientific experts is a pre-requisite, not an afterthought. Specifically, the Environmental Research, Development, and Demonstration Authorization Act of 1978 (ERDDAA) establishes the Science Advisory Board (SAB) as an independent body charged with providing advice to Congress and the EPA. Commenter questions the EPA, How, when, and in what manner has the Agency considered the advice of the SAB?

Commenter 9195 further stated familiarity with the communications between the Science Advisory Board and the Administrator as well as the meetings held in December 2013 and January 2014 addressing CCS. Commenter also stated that the EPA staff who spoke on your behalf at the December 4-5, 2013 meeting said that looking at sequestration was outside their statutory obligation since other EPA programs would handle the storage or sequestration of the C02. Commenter asks following questions to the EPA:

d. How can the Agency both rely on the benefits of EOR sales for making a CCS system less expensive, and incorporate new storage requirements in the rule (Subpart RR) while simultaneously denying that CCS includes the storage half of the system?
Commenter 9195 asks following questions to the EPA:

a. Would you agree that the ability to do either EOR or geologic sequestration are very site specific, and many states and regions will simply not have EOR or sequestration options?  b. Do you think this rule will put specific states and regions at a competitive disadvantage in terms of compliance? 
Commenter 10786 asserted that NSPS is inconsistent with State laws and regulations governing EOR generally, Class II primacy, and associated long-term storage via CO2 -EOR. The commenter further stated that NSPS purports to preempt these State enactments without reliance on or citation to any Federal law or regulation that authorizes such preemption.
When the Science Advisory Board (SAB) and its workgroups raise questions, the EPA takes them seriously. We use the SAB's routine, transparent, and well-established processes to better understand the nature of the questions and how we can address them. An SAB workgroup asked for information on the potential adverse impacts of carbon capture and sequestration (CCS) in November 2013 and how that issue is addressed in the proposed Carbon Pollution Standards. The SAB workgroup also asked about the adequacy of peer review of U.S. Department of Energy (DOE) National Energy Technology Laboratory (NETL) studies, which the EPA relied on to develop cost estimates for carbon capture technology in the proposed rule. The SAB's transparent, deliberative process provided an opportunity for us to engage in a dialogue to better understand the workgroup's concerns and to provide a clearer explanation of the scope of the proposed rule. The EPA clarified that we are not proposing to set any new requirements related to sequestration in this rule and thus, this rule does not include any new analysis related to such requirements. The EPA also provided some additional information on the basis of the DOE NETL cost studies that the EPA used in developing the proposed rule and the peer review process followed by DOE NETL for that study. The DOE's robust process included outside input from knowledgeable stakeholders including industry, academia and government experts in the design of the study and a peer review of the final report by a wide range of similar experts. While the EPA did not conduct additional peer review of these studies, the different levels of multi-stakeholder technical input and final review meet the requirements to support the analyses as defined by the EPA Peer Review Handbook. 
After consideration of the clarifying information and thorough discussion about the issues during several meetings of the SAB that were open to the public, the workgroup recommended to the full SAB that additional review of the science of sequestration was not necessary in the proposed Carbon Pollution Standard. The full SAB agreed with the workgroup's assessment that the EPA relied on existing requirements for sequestration in the Carbon Pollution Standards and that peer review of the DOE cost studies was sufficient. In a memo dated January 29, 2014, the SAB informed the EPA that it will not undertake further review of the science supporting this action. See also response 2.4.2 below dealing with comments regarding the Data Quality Act.
The EPA is reasonably relying on the already-adopted, and very rigorous, Class VI well requirements in combination with the subpart RR requirements to provide secure sequestration of captured CO2. In developing the Class VI rules, the EPA engaged with the SAB, providing detailed information on key issues relating to geologic sequestration -- including monitoring schemes; methods to predict and verify capacity, injectivity, and effectiveness of subsurface CO2 storage; and characterization and management of risks associated with plume migration and pressure increases in the subsurface. See: http://yosemite.epa.gov/sab/sabproduct.nsf/0/AD09B42B75D9E36D85257704004882CF?OpenDocument. In addition, the EPA developed a peer reviewed Vulnerability Evaluation Framework, which served as a technical support document for both the Class VI and Subpart RR rules. See: http://www.epa.gov/climatechange/Downloads/ghgemissions/VEF-Technical_Document_072408.pdf.
Certain regions of the U.S. have more favorable geology for EOR or saline storage of CO2, however the EPA notes that DOE and USGS resource assessments have identified 39 states that have either saline storage or EOR storage opportunities. Many of the states that do not have storage access are unlikely to see new coal fired power plants because there is no need for the additional power, or there are other preferred power options that can meet the performance standard. The EPA believes that the rule offers a wide range of options that allow states considerable flexibility to comply with the rule without creating an economic disadvantage.
UIC Class II wells are typically, but not exclusively regulated by the states. Nothing in the NSPS rule preempts the states' Underground Injection Control Program primacy in issuing Class II permits. Specifically, reporting under subpart RR does not preempt the Class II permit issued by the states. See preamble section V.N.5.a.
Commenter 10029 stated that the proposal reflects the EPA's assessment that it is unlikely any CO2 reuse technology would, in the foreseeable future, be able to accommodate all of the CO2 captured by an affected EGU. Commenter further stated that whether or not this assessment is correct, it is relevant only to identifying the BSER that is available for the purpose of establishing a corresponding performance standard. Commenter further stated that once the EPA establishes a performance standard (i.e., an emission limit), it is the responsibility of the affected EGU to determine how to achieve it. Commenter also stated that nothing in Section 111 of the CAA prohibits an affected EGU from using more than one technology to achieve a standard, and an affected EGU should be permitted to incorporate a beneficial reuse technology as part of a system designed to meet the CO2 emission limit. Commenter stated an example, an affected EGU should be permitted to sell some portion captured CO2 for reuse in the creation of an advanced biofuel, while transporting the balance of captured CO2 in a pipeline to an oil field for use in enhanced oil recovery (EOR) or disposal through geologic sequestration. Commenter stated that the proposal impermissibly forecloses this and all other options that are otherwise available to affected EGUs.
Commenter 10029 stated that under the EPA's proposal, no technology could be used to achieve CO2 reductions until it has been individually authorized by the EPA through a rulemaking. Commenter further stated that this would have a disastrously chilling effect on the development of CO2 reuse technology and set a dangerous precedent for government interference into and control over private commercial decisions, not only regarding CO2 controls on affected EGUs, but for all air pollutants and all source categories subject to regulation under Section 111. Commenter requested that the proposal be revised to comply with the CAA and allow reuse technologies to be used by affected EGUs, alone or in combination with other technologies to achieve the proposed CO2 emission limit.
The commenter is correct that a BSER determination does not mandate that compliance utilize that technology, or indeed, utilize any specific technology. A source must achieve the numerical level of the standard of performance. Nor does anything in section 111 of the CAA prohibit an affected EGU from using more than one technology to achieve a standard. For example, some facilities may choose to use both saline and EOR options, as SaskPower did with the Boundary Dam EGU. To address the issue of using multiple technologies to meet the standard, the EPA is establishing a mechanism for alternative sequestration technology in this final rule. The rule provides for a case-by-case adjudication by the EPA of applications seeking to demonstrate to the EPA that a non-geologic sequestration technology would result in permanent confinement of captured CO2 from an affected EGU.  The EPA disagrees with the Commenter that the rule will have a "disastrously chilling effect on the development of CO2 reuse". The availability of new supplies of anthropogenic CO2 in geographically diverse areas will enhance the opportunity for EOR and other reuses. 
Commenters (10662 and 10952) stated that the EPA's proposal does not demonstrate compliance with Section 321 of the CAA, which gives the agency an affirmative duty to perform continuing evaluation of potential loss or shifts of employment which may result from the administration or enforcement of the CAA or its regulatory framework. Commenters 10662 and 10952 stated that the proposed standards will give some states a competitive advantage over other states in attracting industry, as the geological features necessary for EOR and sequestration are not evenly distributed throughout the country. Commenter also stated that the proposed regulation will have significantly disparate geographic impacts. Commenter 10662 stated that the EPA must also consider increased fuel transportation costs and increased electricity transmission costs incurred by locating EGU facilities close to geological formations favorable to CCS.
While current locations of EOR are not evenly distributed throughout the country, much of the U.S. has access to either existing EOR sites or oil and gas production that is amenable to EOR. Analysis of recent DOE storage resource assessments indicate that there are 39 states for which onshore and offshore deep saline formation storage capacity has been identified. EOR operations are currently being conducted in 12 states. An additional 17 states have geology that is amenable to EOR operations. There are 10 states with operating CO2 pipelines and 23 states that are within 150 miles of an active EOR location. A few states do not have geologic conditions suitable for GS, or may not be located in proximity to these areas. However, in some cases, demand in those states can be served by coal-fired power plants located in areas suitable for GS, and in other cases, coal-fired power plants are unlikely to be built in those areas for other reasons, such as the lack of available coal or state law restrictions. Therefore the EPA does not anticipate that proximity to existing EOR operations will represent a competitive advantage in attracting new industry. The EPA has conducted the cost analysis in accordance with applicable regulations and case law and determined that the cost structure is consistent with the D.C. Circuit's criteria for determining that costs are reasonable.
 Commenter 10664 stated that the proposal is inconsistent with waste management options that the EPA endorses for other air, water and waste regulations by favoring disposal of CO2 rather than recycling or reuse. The commenter recommended that the EPA embrace beneficial reuse as a first resort and choose disposal, or permanent storage, as a last resort. 
Commenter 9472 stated that existing power plants face a number of site- and plant-specific limitations to participating in a CCS demonstration project, including available surface space on site to construct and integrate a carbon capture unit, proximity to existing pipeline infrastructure to sell CO2 into an EOR facility, suitable local storage geology if EOR is not available or cost effective, the extent of conventional air pollution control and the remaining useful life of the plant. 

Commenter 10786 stated that EOR operators are unlikely to purchase or inject CO2 from CCS, unlikely to assume infinite climate stewardship responsibilities as it is inconsistent with law and business practices. The commenter asserted that operators may demand to be compensated rather than paying for the CO2, and that no operator will agree to a complete restructuring of its business for what the commenter estimates as a 5 percent increase in CO2 supply. Commenter 9426 stated that no effort has been made to investigate whether the price of captured CO2 in an EOR application would overcome the increased costs associated with transporting the CO2 long distances. 
Today's rule is not inconsistent with other EPA actions related to waste. Although the determination that the BSER is adequately demonstrated and the regulatory impact analysis for this rule relies on GS in deep saline formations, the EPA also recognizes the potential for securely sequestering CO2 via EOR. The EPA recognizes that types of CO2 storage technologies other than geologic sequestration are under development (e.g. precipitated calcium carbonate) and some are currently in commercial scale operation. The final rule also does not foreclose reuse or other recycling options (other than EOR, itself a form of recycling), but rather provides for a case-by-case adjudication by the EPA of applications seeking to demonstrate storage methodologies of efficacy equal to (or surpassing) geologic sequestration.
The EPA also does not accept the comment that subpart RR reporting will dissuade EOR operators from accepting CO2 from an affected source. 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 § 45Q(a)(1) and $10.92 per metric ton of qualified CO2 under section 45Q(a)(2).

In sum, the cost of complying with subpart RR requirements, including the cost of MRV, is not significant enough to deter EOR operators from purchasing EGU captured CO2 .
Commenters 9201, 9472, 9426, 9683, 9666, 9678, 10098 and 10239 asserted that willing operators reporting under Subpart RR could be construed as intent to conduct geologic storage, creating a risk that a well operator could become subject to more onerous permitting requirements under Class VI of the UIC program. 
An EOR project reporting under Subpart RR may be permitted as UIC Class II. Reporting under Subpart RR does not cause an EOR project to be permitted as UIC Class VI.
Commenter 8032 stated that the issue of what to do with the captured CO2 is far from resolved.
Commenter 6962 stated that is it not necessary to capture and permanently store CO2 emissions and that is it necessary to capture, fix and manage CO2 emissions. The commenter further states that an Air Emission Recycling (AER) system utilizing the Calvin Cycle can accomplish this goal. 
See sections V.M and N of the final rule preamble.
Commenter 4711 stated that compressed air energy storage (CAES) can represent a cost-effective grid-level storage technology that is able to be used in many parts of the US.
The final rule establishes a case-by-case mechanism whereby the EPA can approve alternative storage methods for CO2 that an applicant demonstrates are as effective as geologic sequestration.
6.3.5 CO2 Transport and Geologic Sequestration Legal and Regulatory Issues

Geologic Sequestration Property Rights
Commenter 10023 stated that CO2 storage raises numerous permitting and regulatory issues, including property rights for subsurface storage. Commenters 9407 and 10952 stated that the proposal and supporting information in the rulemaking docket lacks information that the EPA has considered key legal issues that need resolution, such as property rights. Commenter 10952 references the administration's task force report on CCS projects as previously identified concerns that should be addressed.
Commenters 9425, 9426, and 9666 stated the legal mechanisms for securing property rights for subsurface storage of supercritical CO2 may be unclear or ineffective in many states, leading to unforeseen costs and delays. Commenter 9666 stated that subsurface property rights include subsurface mineral rights as well as pore space ownership, and although some states have enacted laws to clarify pore space ownership, most have not, and without such clarification CCS cannot be undertaken.   
Commenter 9683 stated that the proposed rule gives virtually no consideration to property rights barriers attendant to CCS and describes the need to obtain subsurface rights as the most complex property rights issue facing geologic storage. Similarly, Commenters 9423, 9597, and 10239 asserted that CCS is challenged by legal issues such as pore space ownership. Commenters 9423 and 10239 stated that there are unanswered questions regarding ownership of underground pore space. Commenters 10036 and 10618 described various questions related to pore space ownership and use as key regulatory and legal barriers that pose very significant barriers to the feasibility and adequate demonstration of CCS. 
Commenters 6948 and 9666 stated that in most states the property rights needed for subsurface storage of CO2 are not clearly defined and no streamlined procedure for acquiring pore space has been developed. Specifically, Commenters 6948 and 9666 stated that 5 states have addressed what property rights must be secured for geologic storage of CO2, and only 7 have developed any streamlined procedures for acquiring pore space. 
The EPA notes that issues of individual property rights will involve site-specific resolution if and when they arise in particular proceedings. These issues have not proved impediments to the Class VI projects pursuing GS, as illustrated by the cases of Archer Daniels Midland and FutureGen. The EPA cost estimates for this rule include costs for acquiring both surface land and sub-surface property rights ("pore acquisition").
Commenter 9666 stated that many geological formations suitable for CCS cross political jurisdictions and may involve multiple cities, counties, and states, each with their own requirements. Similarly, Commenter 9425 and 10239 cited concerns over potential differences in laws in multiple jurisdictions.
Commenter 10243 recommended that because geologic formations for storage extend beyond state lines, a uniform national policy should be adopted, as opposed to a state by state patchwork of rules, to help projects move forward once CCS is technologically and economically feasible.
This comment is beyond the scope of this proceeding, but the EPA again notes that resolution of cross-boundary issues is not a necessary pre-condition to issuance of Class VI permits. The EPA notes that 40 CFR 146.82(b) of the UIC Class VI regulations specifies that the UIC Director shall notify any States, Tribes, or Territories within the area of review of a Class VI project based on information provided in the permit application and per state UIC requirements. These issues have not proved impediments to the Class VI projects pursuing GS, as evidenced by the cases of Archer Daniels Midland and FutureGen. Furthermore, EOR with anthropogenic CO2 likewise has been conducted successfully for decades without such issues proving an insurmountable obstacle. In addition, of course, there are compliance alternatives to the promulgated standards that do not involve sequestration, so that the standard can be satisfied in any case in all areas.
Commenter 9666 stated that CO2 repositories must be extensive and due to their size could infringe on existing mineral, water, and private property rights (both surface and subsurface). Similarly, Commenter 9423 raised concern for the private property rights of owners of the surface lands above the injected CO2 plume.   
Commenter 9666 asserted that not all states clearly specify surface vs. subsurface property rights, which will lead to conflicts of interest and potential litigation. The commenter noted that it is not uncommon outside the eastern U.S. for subsurface and surface rights to be separated. The commenter stated there is precedent regarding surface vs. subsurface ownership rights for wastewater injection where operators of wastewater wells have been held accountable for "trespass" of injected wastes into subsurface properties owned by others, for which rights had not been acquired.
Commenter 9666 stated that regional land use controls could be used to ban large-scale CCS projects near valuable natural resources, presenting obstacles to implementing projects in otherwise viable locations.
The EPA notes that issues of individual property rights will involve site-specific resolution if and when they arise in particular proceedings. These issues have not proved impediments to the Class VI projects pursuing GS, as evidenced by the cases of Archer Daniels Midland and FutureGen.
Commenter 9683 noted that scale-up presents complex issues for the storage of CO2. For example, storage of tens of millions of tons of CO2 in a saline or other non-EOR formation requires aggregation of property rights across a broad area potentially encompassing not only areas to which the CO2 may migrate, but areas into which brines and other materials displaced by CO2 injections may reach.
Commenter 9666 stated a critical complication is that subsurface lands with the desired pore space can be privately owned, and CO2 injection can impact owners in multiple states. Commenter 9666 stated that compulsory unitization laws and eminent domain laws have been used to secure access to oil and gas fields from multiple owners, but these laws may be inadequate for CO2 injection. According to the commenter, the key to success is the ability to predict whether injected CO2 will remain in the subsurface property or migrate laterally to other properties and further research is needed to improve the ability to predict and monitor the movement of CO2 plumes from injection sites beyond present capabilities.
This comment is beyond the scope of this proceeding, but the EPA again notes that these issues have not proved impediments to the Class VI projects pursuing GS, as evidenced by the cases of Archer Daniels Midland and FutureGen.
The EPA agrees with the commenter's assertion that the ability to predict whether injected CO2 will remain in the subsurface is key to the success of CCS. The EPA Class VI regulations require that, prior to receiving a permit, a Class VI permit applicant develop and submit to the UIC Program computational models that predict the plume movement based on results of the thorough site characterization process. The Class VI rule also requires regular monitoring of the plume and pressure front during the injection period to determine if the behavior is consistent with model predictions. If the modeled results do not accurately reflect the actual conditions based on operational and monitoring information, the model must be revised. The EPA believes that the modeling and monitoring tools currently available provide the necessary level of information to ensure the safe and secure long-term storage of CO2.     
Commenter 10098 and 10239 stated that if sequestration were permitted on federal land, it is not clear whether the federal government would charge companies rent for storage. According to the commenter, the proposed rule does not attempt to deal with this issue, and, even if it did, the EPA's options are limited. The commenter stated that this issue is one of federal land use law, which is outside of the EPA's purview and it is not expected that the concern would be resolved within any reasonable timeframe. Commenter 10239 concluded that while these and other critical issues are largely outside of the EPA's jurisdiction and control, it is nevertheless arbitrary and capricious for the EPA to simply ignore them when assessing whether geologic storage is currently available.
Determining rental rates for use of federal lands is outside of the EPA's authority and beyond the scope of this rule. The EPA has included land and other property acquisition costs in its cost estimates for the rule. The EPA notes further that Class VI permits have been issued by the EPA, again indicating that land use issues have proved surmountable in practice.
CO2 Transport Legal and Regulatory Issues
Commenters 8022, 9382, 9426, 9666, 9780, 10239, and 10098 noted that CO2 pipeline siting is subject to the laws of individual states, and that involvement of multiple jurisdictions could prevent or delay securing the necessary permits for pipelines to transport supercritical CO2. Commenter 10660 stated that siting of CO2 pipelines raises interagency jurisdictional issues at the regulatory level. Commenter 6984 cited a study that noted that the federal Department of Transportation's Pipeline and Hazardous Materials Safety Administration safety rules are applicable to CO2 pipelines but that states maintain much of the regulatory control over CO2 pipelines. Commenters 9381 and 9780 noted that it is not clear whether legislation would be needed to allow FERC, in lieu of the Surface Transportation Board, jurisdiction to assure reasonable rates and open access to CO2 pipelines. Commenter 9665 also noted the possibility that such legislation would be needed. 
Commenter 9665 stated that there are significant concerns regarding the availability and achievability of the sequestration component of the partial CCS standard because it is unclear whether the current regulatory structure for CO2 pipelines is adequate in the event that CCS is required for all new Subpart Da units, much less natural gas-fired combustion turbines. Statutory changes could be needed to transfer economic regulation of CO2 pipelines to the Federal Energy Regulatory Commission (FERC) in lieu of the Surface Transportation Board to assure reasonable rates and open access. Without such assurance, the EPA would be unable to adequately consider the cost of a requirement for partial CCS as required under Clean Air Act Section 111(a). 
This comment seems misplaced. As described in detail in the preamble to the final standard, there is a comprehensive and effective regulatory program for CO2 pipelines administered by the Pipeline and Hazardous Materials Administration. Over 5,000 miles of dedicated CO2 pipelines exist under this system, and that capacity is expanding due to increased demand. This system is already fully functioning and the commenter asserts but does not explain why a transfer of economic regulatory authority to another agency is necessitated (or desirable). The system functions well now, and is expanding. The suggestion that capacity will be dwarfed by new coal CO2 capture is not well taken, given that so little new capacity is likely to be added to the system. Indeed, the robust growth in CO2 pipeline demand is due to the need for CO2 from other-than coal sources. See section V.I.5 of the final rule preamble of the NSPS.
Issues of pipeline siting can be accommodated in the planning and permitting process. New sources, in particular, have a good deal of siting flexibility, since they are unconstrained by existing conditions.

Safety of CO2 pipeline operations falls under the jurisdiction of the Pipeline Hazardous Materials Safety Administration. States also retain significant control over the regulation of intrastate CO2 pipeline operations. The EPA notes that issues associated with the governance and management of CO2 pipeline infrastructure are beyond the scope of the final rule. Additionally, there is no evidence that current Federal and state laws governing access to and rate regulation of CO2 pipelines has had a significant adverse effect on the development and expansion of CO2 pipelines: in the past several years hundreds of miles of pipelines that carry anthropogenic or natural-occurring CO2 have been permitted and constructed under existing state and federal regulations.
Commenters 9381, 9426, 9666, 9780, 10239, and 10098 asserted that much of the nation's law on CO2 pipeline siting is underdeveloped at this time, potentially resulting in plant owners having to negotiate rights-of-way with hundreds of private landowners to run a CO2 pipeline if state laws do not allow eminent domain as an option for procuring easements. Commenter 9666 suggested that legal issues of siting authority and the prospect of creating a mechanism to establish eminent domain to support timely CO2 pipeline construction merited Congressional attention. Commenter 10098 stated that the proposed rule provides a significant overview of federal regulations pertaining to geologic sequestration and makes only a passing reference to rights-of-way as if their successful acquisition was inevitable and just a cost of doing business.
Additionally, commenter 10098 noted that state law decisions on eminent domain can lead to expensive and time consuming litigation by landowners and non-governmental organizations, and that procuring rights-of-way over federal lands can be especially resource intensive and time consuming due compliance with the National Environmental Policy Act, the Endangered Species Act, other federal land use laws, and public notice and comment periods. 

Commenter 10239 stated that siting of CO2 pipelines are subject to state law, and, because of this, negotiating rights-of-way for CO2 pipelines will be a complicated and expensive process, particularly if a state determines that CO2 pipeline operators are not entitled to employ eminent domain to acquire rights-of-way. The commenter stated that rights of way over federal lands would be further complicated by NEPA. Commenter 10239 stated that while these critical issues are largely outside of the EPA's jurisdiction and control, it is nevertheless arbitrary and capricious for the EPA to simply ignore them when assessing whether geologic storage is currently available.
Commenter 9683 noted that State law is less clear and inconsistent on whether eminent domain authority is available for construction of CO2 pipelines. Commenter 9683 noted that State law may extend eminent domain authority only in cases where the entity building the pipeline is a public utility, or only if the pipeline is needed to serve end-use customers in the State. This may depend on whether the facility generating the CO2 to be sent through the pipeline is within the state in which the pipeline would be constructed. Commenter 9683 also noted that at least one State requires that the pipeline have a "public use" in order to extend eminent domain authority. 
Similarly, commenters 10036 and 10618 stated that the EPA has ignored property rights issues that are barriers to the adequate demonstration and development of CCS, including jurisdictional determinations and how existing programs for eminent domain, unitization, public use, or voluntary acquisition translate to CO2 pipeline development. The commenters state that these issues must be resolved on the state, interstate and national level in order to efficiently and effectively regulate future CCS projects but will take time and resources. 
The EPA recognizes that siting of CO2 pipelines is largely a state-regulated activity, and recognizes that state regulations concerning application of eminent domain vary among the states. The EPA does not consider state-level pipeline siting processes and state-level regulatory authority to be barriers to either the development of individual CO2 pipelines or development of a broader national CO2 pipeline network, as evidenced by the many new CO2 pipelines permitted and placed in service over the past few years alone. The challenges associated with expansion of CO2 pipeline infrastructure are not insurmountable. The legal and regulatory issues cited by the commenters, including eminent domain authority, environmental impact assessment, and time-frame for siting, permitting, and constructing CO2 pipelines are not new issues. For example, land-use issues, acquisition of rights-of-way, and public perception of impacts are issues that all types of pipeline development face, and are all issues that have been dealt with effectively in the past for siting, permitting, and construction of CO2 pipelines. 
Additionally, although CO2 pipeline infrastructure is currently limited to where active EOR production and extraction operations using CO2 are occurring. Several hundred additional miles of CO2 pipeline are either under construction, planned, or proposed which will increase the accessibility and geographic extent of this infrastructure in the near future. Recently planned, proposed, and constructed CO2 pipelines provide evidence that the permitting process does not pose insurmountable obstacles to siting and construction of new CO2 pipelines.
Commenter 9665 noted that it is possible that legislation would be needed to have FERC issue certificates of public convenience and necessity, and related eminent domain rights, to CO2 pipelines comparable to those granted for natural gas pipelines. Commenters 9665 and 10662 noted that Federal eminent domain that is available for natural gas pipelines is not currently available for CO2 pipelines, and commenter 10662 noted that both the FERC (Federal Energy Regulatory Commission) and the STB (Surface Transportation Board) have declined to take jurisdiction over siting of CO2 pipelines, and as a result siting of CO2 pipelines is relegated to the states. Commenter 8925 also cited a study noting that there is no current Federal siting or eminent domain regulatory scheme for CO2 pipelines. Commenters 9381 and 9665 conclude the current regulatory framework for CO2 pipelines cannot confidently be relied on as a basis for development of a much more robust CO2 pipeline network, because CO2 pipeline projects are subject to significant timing and cost uncertainties related to right-of-way acquisition.
EPA recognizes that siting and permitting of CO2 pipelines is largely within the jurisdiction of the states and that regulations concerning eminent domain applicability to CO2 pipelines differ among the states. The EPA also recognizes that CO2 pipeline siting and construction costs will vary by state and by proposed pipeline location. The EPA estimated CO2 pipeline siting and construction costs based on cost studies prepared by the U.S. Department of Energy National Energy Technology Laboratory (DOE-NETL) and other sources (see e.g., DOE-NETL references cited in section V.I.2.a of the preamble). The range of siting and construction costs considered is representative of costs that CO2 pipeline developers would actually incur. The EPA does not agree that state-by-state CO2 pipeline siting regulations and the lack of federal agency regulatory authority over CO2 pipeline siting represent insurmountable barriers to siting and construction of either individual CO2 pipelines or a broader CO2 pipeline network or that state-specific cost factors will result in CO2 pipeline developers incurring costs outside the range of values considered by the EPA in the cost analysis. 
The EPA does not agree that the current permitting framework for new CO2 pipelines cannot be relied upon to enable the siting and construction of new CO2 pipelines. There are several hundred additional miles of CO2 pipeline that are either under construction, planned, or proposed. Recently planned, proposed, and constructed CO2 pipelines provide evidence that the permitting process does not pose insurmountable obstacles to siting and construction of new CO2 pipelines.
Commenter 9780 asserted that legislation would be needed to authorize FERC to issue certificates of public convenience and necessity, and related eminent domain rights, to CO2 pipelines comparable to those granted for natural gas pipelines. Commenter 9665 also noted the possibility that such legislation would be needed to grant such authority to FERC. Commenter 8032 noted that permitting sequestration locations will likely have serious technical, legal and cost issues related to siting and building CO2 pipelines, and cited as an example the issue of utilities not having the right of eminent domain. Commenter 9780 stated that building a natural gas pipeline can take years, and it will take longer to build CO2 pipelines unless the federal government amends the current process to facilitate construction. Commenter 10662 also noted that there is currently insufficient development of key legal issues, such as the process by which to acquire rights-of-way for CO2 pipelines. Commenter 8966 also stated that pipeline siting and construction is complicated by geographic constraints based on the terrain of the pipeline path, local and state siting requirements, and acquisition of necessary rights-of-way. Commenter 9666 stated that the most significant barriers to expansion will be non-technical issues  -  addressing property rights for right-of-way access and multi-state jurisdictions.
Federal and state regulatory requirements for siting and permitting new CO2 pipelines are outside the scope of this rule. However, the EPA does not agree that Federal legislation concerning eminent domain and certification of public convenience and necessity for CO2 pipelines would be needed to ensure timely development of either individual CO2 pipelines or a broader CO2 pipeline network. The EPA agrees that siting and construction of new CO2 pipelines could require several years, however, the EPA does not consider that time frame to be inconsistent with the anticipated time frame for siting and construction of new coal-fired EGUs expected to be few in number. State and Federal agencies have been permitting CO2 pipelines for decades. Moreover, data from the Pipeline and Hazardous Materials Safety Administration show that in 2013 there were 5,195 miles of CO2 pipelines operating in the United States. This represents a seven percent increase in CO2 pipeline miles over the previous year and a 38 percent increase in CO2 pipeline miles since 2004. The EPA views the existing CO2 pipeline licensing process as adequate for siting and construction of new CO2 pipelines that may be needed to provide CO2 transport from new coal-fired EGUs.           
Commenters 9425, 9666 and 9683 stated that multiple jurisdictions, cross-state issues, and high pressures required for supercritical fluid transport could prevent or delay securing the necessary permits for pipelines to transport supercritical CO2, and that proposed CO2 pipelines may incur public opposition. Commenter 9666 noted that groups adversarial to coal-fired generation can impose significant delays. It has been well demonstrated that some organizations have an established track record of contesting projects relating to CO2 by opposing permits and legal action. Such delays both slow progress and escalate cost of building any sequestration site and associated pipeline. For example, each month of delay in the Kemper County construction progress is estimated to add $15-25 million to the final cost.
Commenter 9683 noted that without eminent domain, a project developer would have no recourse but to seek permission from each landowner through whose property the project would traverse, with a "no" answer requiring a re-routing or scrapping the project entirely. Commenter 9683 noted that Tenaska's cancelled Taylorville project included a 450-mile CO2 pipeline to connect to an existing CO2 pipeline. Commenter 10239 noted that Illinois EPA identified access to CO2 pipelines as a logistical challenge to the Taylorville project. 

Commenters 9596, 9197, and 10618 also stated the absence of eminent domain authority for construction of CO2 pipeline could introduce significant and potentially insurmountable barriers to the construction of a new CO2 pipeline. Unlike natural gas pipelines, which can secure federal eminent domain authority, CO2 pipelines must be built with the consent of every intervening landowner. The need to negotiate with and obtain an easement from potentially thousands of landowners for each new CO2 pipeline could dramatically lengthen the amount of time between planning and construction of a CO2 pipeline while dramatically raising costs. These factors, when combined with the time and financial expenditure necessary to obtain state and federal regulatory approval for various aspects of each CO2 pipeline renders this option non-viable for most EGUs. 

Commenter 9596 noted that studies they and others have undertaken demonstrate that there would be significant CO2 pipeline siting issues associated with undertaking CCS in the Southeastern United States. 

Commenter 9666 summarized a West Virginia Chamber of Commerce (Commenter 6948) survey of the state laws, regulations, and policies which found that states do not have adequate regulatory mechanisms in place to support CO2 sequestration. The study by Commenter 6948 (cited by Commenter 9666 and Commenter 10618) noted that only 12 states have provided any streamlined process for the siting or construction of pipelines used to transport CO2. Commenter 10243 noted that while some states, including Michigan, have enacted legislation or regulation that address siting of CO2 pipelines, without a uniform national policy related to right-of-way acquisition for CO2 pipelines, Commenter 10243 expects significant timing and cost uncertainties arising as companies attempt to negotiate contracts to gain access to land, lay pipeline, restore land, and conduct other pipeline siting and construction related activities.CO2 pipeline specifications of the U.S. Department of Transportation Pipeline Hazardous Materials Safety Administration found at 49 CFR part 195 (Transportation of Hazardous Liquids by Pipeline) apply regardless of the source of the CO2 and take into account CO2 composition, impurities, and phase behavior. These rules contain (among other provisions) detailed requirements related to reporting, pipeline design (temperature, pressure variation both internal and external, loads, types of pipes, valves and fittings, connections, closure, and leak detection), construction, pressure testing, and corrosion control. CO2-specific provisions require special design for CO2 at low temperatures. 49 CFR section 195.102 (b). These requirements have applied for years, successfully, to compressed, supercritical CO2 captured, transported via regulated pipeline, and used for EOR. The commenters do not address these requirements, and their successful use in the EOR context, in assuming massive opposition to new pipeline (or use of existing pipelines) or why eminent domain authority would be necessitated. As noted above, issues of pipeline availability and use did not pose obstacles to granting UIC Class VI permits to ADM and FutureGen. Denbury recently completed the final section of the 325-mile Green Pipeline for transporting CO2 from Donaldsonville, Louisiana, to EOR oil fields in Texas, and completed construction and commenced operation of the 232-mile Greencore Pipeline in Wyoming. Chaparral completed an 8-inch, 68-mile CO2 pipeline from fertilizer plant in Coffeyville, Kansas, to an oil field in Oklahoma. These large CO2 pipeline projects demonstrate that long CO2 pipelines can be sited effectively under the current regulatory system. Actual experience has shown that the commenters' concerns are surmountable. 
The EPA does not agree that a significant expansion of the current CO2 pipeline network would be needed within the foreseeable future for transport of CO2 captured from new EGUs because of the expected limited construction of new coal-fired EGUs. The EPA also does not agree that the siting and construction of CO2 pipelines needs to be federally regulated concerning rates and access, or that states that have not done so would need to establish eminent domain procedures, in order for CO2 pipeline transportation to be provided for new coal-fired EGUs. The EPA expects that new CO2 pipelines needed to transport the CO2 captured from a new coal-fired EGU could be sited and constructed within a similar timeframe as would be needed for the planning, siting and construction of the new EGU itself.

The commenters do not address whether new sources could site a source advantageously to account for pipeline availability. The EPA thus regards these comments as overstated. In any case, compliance alternatives exist under the final standard which would not necessitate sequestration.
Commenter 10618 stated that although it is a commonly held belief that CO2 pipelines may be developed to parallel existing electric transmission line rights-of-way, transmission line rights-of-way are commonly specific to above ground structures, and would not apply to pipeline development. Existing transmission line rights-of-way do not always provide access to perform work that is not affiliated with the transmission lines. For example, additional right-of-way permissions from landowners may be required to obtain access to conduct baseline field studies needed for pipeline siting and construction.
The EPA recognizes that electric transmission rights-of-way and pipeline rights-of-way requirements may differ and that there may be restrictions on the use of electric transmission line rights-of-way for other purposes. The EPA did not base the analysis of the technical and economic feasibility of CO2 pipeline siting and construction on the use of electric transmission corridors, and any restrictions on specific rights-of-way do not affect the conclusions of the analysis. 
Commenter 10662 stated that the EPA ignores the realities of the lack of CO2 pipelines across the country and the legal, regulatory and financial hurdles that exist to expand capacity by the orders of magnitude that would be needed to transport EGU CO2 emissions. Commenter 9734 also noted that more CO2 pipelines will need to be built, which would require the acquisition of property rights and compliance with numerous state and federal laws and regulations. Commenter 9666 noted that in addition to construction of CO2 pipelines, a network of booster compressors could also needed to operate the CO2 pipeline network.
The EPA does not agree that a significant expansion of the current CO2 pipeline network would be needed within the foreseeable future for transport of CO2 captured from new EGUs because of the expected limited construction of new coal-fired EGUs. The EPA also does not agree that the siting and construction of CO2 pipelines needs to be federally regulated concerning rates and access, or that states that have not done so would need to establish eminent domain procedures, in order for CO2 pipeline transportation to be provided for new coal-fired EGUs. The EPA expects that new CO2 pipelines needed to transport the CO2 captured from a new coal-fired EGU could be sited and constructed within a similar timeframe as would be needed for the planning, siting and construction of the new EGU itself. The existing CO2 pipeline network includes booster compressors and other ancillary equipment, and the EPA does not consider the need to provide such equipment as a component of new CO2 pipelines to be an impediment to siting, construction, or operation of proposed CO2 pipelines.
Commenters 10029 and 10664 expressed support for the creation of a network of new and existing pipelines throughout the United States, from which CO2 may be introduced by affected EGUs and distributed and sold at various points in the network. Commenters 10664 and 10029 noted that this will distribute the cost to construct and operate the network over a wide range of potential users, and facilitate the commercial deployment of CO2 reuse technologies. 
Commenters 10029 and 10664 stated that the narrow approach in the EPA's proposal, which prohibits any disposition of captured CO2 except geologic sequestration, suggests the need for dedicated CO2 pipelines that are constructed solely to transport the captured CO2 from an affected EGU directly to a geologic sequestration site. Commenters 10029 and 10664 suggested that this unnecessarily narrow approach would severely restrict access to the CO2 pipeline network, prevent the sale or distribution of CO2 as a commodity for reuse, and needlessly increase the costs to construct and operate that network. 
A CO2 pipeline network already exists which allows CO2 from any source to be piped. The final rule does not establish any restrictions on how the CO2 pipeline network is used or the purposes to which CO2 off-taken from the CO2 pipeline network is used.
In addition, the final rule provides an alternative case-by-case compliance mechanism for storage of captured CO2 allowing demonstrations that alternative storage technologies are as effective as geologic sequestration. In addition, the final standard has alternative compliance pathways that do not involve sequestration or other storage of CO2.
The rule generally requires that captured CO2 be either injected on-site for geologic sequestration or transferred offsite to facility reporting under 40 CFR subpart RR. As stated in section V.M.4 of the preamble, there are emerging technologies alternative to geologic sequestration that are designed to safely sequester or otherwise utilize captured CO2 such that it is not released to the atmosphere. These technologies are not sufficiently advanced that the EPA is prepared to unqualifiedly structure this final rule to allow for their use, nor are there plenary systems of regulatory control and GHG reporting for these approaches, as there are for geologic sequestration. In this final rule, the EPA is establishing a mechanism for a case-by-case adjudication by the EPA of applications seeking to demonstrate to the EPA that a non-geologic sequestration technology would result in permanent confinement of captured CO2 from an affected EGU. 
Commenter 10036 noted that the EPA stated that that 95 percent of the 500 largest CO2 point sources are located within 50 miles of a possible geologic sequestration site which would lower transportation costs." Commenter 10036 stated that the EPA's analysis is based solely on the locations of existing sources while the proposed rule applies to only new sources, and that future power plants may need to be sited in locations very different from existing power plants. Commenter 10036 also noted that even fifty miles of new CO2 pipeline would be considerable and might not be possible for a given location. For example, AEP's proposed commercial scale CO2 capture and storage system at Mountaineer Plant included approximately 12.5 miles of CO2 pipeline. Within that short 12.5 mile distance, AEP encountered more than 250 landowners that would have been impacted by the CO2 pipeline crossing their property. Had the project moved forward, AEP would have had to obtain rights-of-way for the CO2 pipeline from all impacted property owners. 
The EPA recognizes that new EGUs may need to be sited in locations different from the locations of existing EGUs, and that siting of new EGUs would take into consideration a number of factors. However, the EPA does not agree that EPA's analysis is based "solely" on the locations of existing sources while the proposed rule applies to only new sources. Potential sequestration sites are located throughout the United States. The EPA also recognizes that acquisition of right-of-way is an essential component of the siting and construction of pipelines, and included estimated acquisition costs as part of its cost assessment.  However, the EPA does not consider the need for proponents of proposed CO2 pipelines to negotiate with individual landowners to be a substantial impediment, as evidenced, among other things, by the Class VI permits issued to Archer Daniels Midland and FutureGen. 
Commenter 9683 noted that while it is technologically possible to build CO2 pipelines, the EPA has given no consideration to the expense, legal and regulatory burdens (and perhaps in some cases impossibilities), and the length of time required for such construction to occur. Commenter 10048 also noted that the advanced CO2 pipeline infrastructure that would need to be developed would require a substantial amount of time to site, design, and construct. Commenter 9780 noted that the EPA has failed to account for the lengthy, costly, and uncertain permitting processes for major pipelines, and has not addressed the fact that the owners of new EGUs installing CCS are not likely to be the entities responsible for permitting, building and paying for the necessary new CO2 pipelines. Commenter 9780 further states that the EPA has made unsubstantiated and unverifiable claims about the ease and cost of building CO2 pipelines.
The EPA recognizes that new EGUs subject to the rule would not necessarily be the constructor or the owner-operator of CO2 pipelines that would transport the captured CO2 to a sequestration site. The EPA does not consider the fact that the new EGU and new CO2 pipeline may have different owner-operators to be a substantive impediment to siting and construction of new CO2 pipelines. Existing CO2 pipelines that have been constructed to transport either captured CO2 or naturally-occurring CO2 to EOR sites are not necessarily owned and operated by the same entity that is operating the EOR sites. The owner-operators engage in a commercial transaction concerning the transportation of the CO2 supplied to the EOR site; the EPA anticipates that new EGU operators may engage in commercial transactions concerning the transportation of the CO2 captured from the proposed EGU to a sequestration site. 
With respect to the time frame for siting and constructing CO2 pipelines, the EPA anticipates that CO2 pipelines that would transport captured CO2 from new coal-fired EGUs to sequestration sites could be sited and constructed within a similar time frame as would be needed for planning, siting and construction of the EGU itself, considering the limited construction of new coal-fired EGUs that is expected.         
Commenter 10105 noted that Nevada lacks the appropriate geology for sequestration and that as a result captured carbon would have to be transported to other states. That would require the availability of significant pipeline infrastructure. In a state like Nevada, with large rural areas, the cost of installing pipelines will likely be prohibitively expensive. Additionally, Nevada's rural areas are prime sage grouse habitat and desert tortoise habitat. The sage grouse is currently in the process of being listed as threatened or endangered, and the desert tortoise is a listed species. The listing of those species and the large size of their habitats would make siting a pipeline even more challenging. Commenter 10618 identified permitting related challenges to the viability of any CCS project, including that the size of the CCS project alone (capture, transport, and storage systems) would require extensive field studies to evaluate biological, cultural, and wetland resources to support the preparation of permit applications.
The EPA recognizes that not all states and areas of the U.S. have potential sequestration capacity, and acknowledges that CO2 pipelines would need to be constructed to transport CO2 captured from proposed EGUs that are not located in the vicinity of sequestration capacity. The EPA does not agree that the fact that certain states and areas of the U.S. do not have potential sequestration capacity renders CO2 capture, transport, and sequestration infeasible. The EPA recognizes that environmental impact review under NEPA would be required as a condition of siting and construction of proposed CO2 pipelines that cross Federal land. Such review would include an assessment of potential impacts of the proposed pipeline to endangered and threatened species in accordance with the Endangered Species Act, as well as assessment of potential impacts of the proposed pipeline to natural, cultural and biological resources. Federal agencies including the BLM have conducted NEPA reviews of proposed pipeline projects potentially impacting sage grouse and other threatened and endangered species habitat and Federal agencies and have established procedures for conducting assessments of potential impacts to natural, cultural, and biological resources. Such environmental impact reviews are outside of the jurisdiction of the EPA and would be conducted by the responsible Federal agency.
Commenter 9201 noted that the EPA did not consider or evaluate the impacts on land use and other environmental values from the construction of CO2 pipelines to transport CO2 to sequestration sites or for enhanced oil recovery as envisioned under the proposed rule. Commenter 9195 questioned whether the EPA considered the potential non-air environmental impacts of the construction of the national CO2 pipeline network. Commenter 10086 noted that the majority of the U.S. lacks pipelines to transport the CO2 and that the EPA failed to account for the lack of transportation infrastructure and the environmental impact and costs of constructing a network of pipelines across the United States. 
Siting and construction of proposed CO2 pipelines is subject to permitting and environmental reviews conducted by state and/or federal regulatory agencies. Proposed CO2 pipelines crossing Federal (e.g., BLM) land would be subject to environmental reviews conducted by the responsible Federal agency under the National Environmental Policy Act (NEPA) and the Federal agency's NEPA implementing regulations. For example, BLM has established and implements procedures for environmental reviews of proposed CO2 pipelines under NEPA under Federal NEPA regulations and BLM's implementing regulations. NEPA reviews of proposed CO2 pipelines include consideration of non-air quality and other environmental impacts of construction and operation of the proposed pipeline. Proposed intrastate CO2 pipelines and proposed interstate CO2 pipelines that do not cross Federal land are subject to permitting and environmental reviews under state regulations and potentially also under Federal regulations. Therefore any CO2 pipelines proposed to transport CO2 captured from new EGUs that are subject to the proposed rule would be subject to project-specific permitting and project-specific environmental reviews including consideration of land use impacts, non-air quality impacts and other environmental impacts of proposed pipeline construction and operation.
Commenter 9780 agrees that CO2 has been safely transported via pipelines in the U.S. for nearly 40 years -- primarily for the purpose of enhanced oil recovery (EOR) -- and there are few technical hurdles associated with CO2 pipelines, there are various legal and regulatory issues that will need to be addressed for any significant expansion of the current, limited, 3,600-mile CO2 pipeline system. These include issues of eminent domain for CO2 pipeline siting and issues of reasonable rates and open access for CO2 pipeline network operation.
The EPA agrees that CO2 pipeline transport is demonstrated and technically feasible. The EPA recognizes that some states have already established eminent domain procedures for siting and construction of CO2 pipelines while other states have not done so. The EPA does not agree that a significant expansion of the current CO2 pipeline network would be needed within the foreseeable future for transport of CO2 captured from new EGUs because of the expected limited construction of new coal-fired EGUs. See RIA chapter 4. The EPA also does not agree that the siting and construction of CO2 pipelines needs to be federally regulated concerning rates and access, or that states that have not done so would need to establish eminent domain procedures, in order for CO2 pipeline transportation to be provided for new coal-fired EGUs. The EPA expects that new CO2 pipelines needed to transport the CO2 captured from a new coal-fired EGU could be sited and constructed within a similar timeframe as would be needed for the planning, siting and construction of the new EGU itself.
Commenter 8925 noted that once permits and rights-of-way were secured, construction of a 12.2 mile intrastate CO2 pipeline was completed within 3 months. Commenter 8925 noted that the applicant needed to consult with eight separate Federal and State agencies as part of the pipeline permitting process.
EPA recognizes that multiple state and federal agencies may need to be involved in siting and construction of CO2 pipelines to comply with regulations. The commenter illustrates that CO2 pipelines can be and have been successfully licensed, sited, and constructed, and that CO2 pipelines can be and have been constructed in a timely manner.
Commenters 9600, 10097, 10098, and 10239 stated that the EPA has already determined that CCS is not technically feasible for EGUs and that the EPA has already identified the cost of building CO2 pipelines as one factor in this determination. Commenter 10098 reviewed the EPA GHG Guidance for determination of Best Available Control Technology (BACT) and asserted that the EPA GHG Guidance expects CCS to be eliminated from further consideration under Step 2 or Step 4 of the decision making process. Commenter 10098 stated that for purposes of Step 2 of the decision making process, pertaining to technical feasibility, the EPA has already acknowledged the significant technical and logistical barriers (including CO2 transport) that hinder CCS. 
Commenter 10618 also noted that the EPA has acknowledged in their guidance document for Prevention of Significant Deterioration PSD permitting for GHGs that the scope of design, construction, and operation considerations are much different and unique for CCS compared to other emission control systems. Commenters 10098 and 10239 cited several project-specific analyses that determined that CCS was technically infeasible because of the lack of transportation infrastructure. 

Commenter 10098 concludes that although the GHG Guidance urges permitting agencies to consider CCS, it left no question that CCS is not ready for widespread use; EPA's own GHG Guidance and decisions based on the Guidance do not consider CCS to be technically feasible.Previous facility-specific BACT determinations were not subject to a regulatory-established "BACT Floor" because no standards were in place at the time the reviews were conducted. 
The definition of BACT in the CAA specifies that "[i]n no event shall application of [BACT] result in emissions of any pollutants which will exceed the emissions allowed by any applicable standard established pursuant to section 111 or 112 of the Act." This has historically been interpreted to mean that BACT cannot be less stringent than any applicable standard of performance under the NSPS. See e.g. EPA, PSD and Title V Permitting Guidance for Greenhouse Gases, p. 20-21 (March 2011). Thus, upon completion of an NSPS, the EPA reads the CAA to mean that the NSPS establishes a "BACT Floor" for PSD permits issued to affected facilities covered by an NSPS. 

It is important to note that a proposed NSPS does not establish the BACT Floor for affected facilities seeking a PSD permit, as just noted above. This is explained on page 25 of EPA's PSD and Title V Permitting Guidance for Greenhouse Gases (March 2011), and is likewise clear from the language of CAA section 169 (3). However, although a proposed NSPS is not a controlling floor for BACT, the NSPS is an independent requirement that will apply to an NSPS source that commences construction after an NSPS is proposed and carries with it a strong presumption as to what level of control is achievable. This is not intended to limit available options to only those considered in the development of the NSPS. 

Once the NSPS is finalized, then the standard would apply to any new source that meets the applicability of the NSPS and has not commenced construction as of the date of the proposed NSPS, including any existing facility that adds EGU capacity by adding a new EGU that is an affected facility under this NSPS. 
Commenter 10052 stated that the EPA has not fully considered many elements of implementing partial CCS that may render the technology commercially unavailable or not technically viable. Commenter 10052 noted that the EPA indicates that CO2 has been safely transported via pipelines in the U.S. for nearly 40 years and that 95 percent of the 500 largest CO2 point sources are within 50 miles of a possible geologic sequestration site, but states that this assessment is broadly conclusory and does not account for the geographically diverse and distant nature of power plant locations in much of the United States. The commenter stated that the EPA has similarly ignored myriad factors that complicate the viability of sequestration sites, for example, in the Midwest and Western U.S., significant CO2 pipeline infrastructure is likely to be needed for widespread deployment of CCS because the location at which the captured carbon may be utilized for enhanced oil recovery (EOR) or geologically sequestered is remote from the location of the resource. The commenter states that this is likely to render CCS prohibitively expensive and potentially infeasible in certain locations of the country, because that the infrastructure required to transport the necessary quantities to CO2 to sequestration sites or enhanced oil recovery locations would outstrip the size of the existing natural gas pipeline infrastructure that exists today and because the ability to obtain the required easements or property rights is questionable.
The EPA recognizes that sites for new EGUs may be geographically diverse and that some proposed EGU sites may not be located in the vicinity of potential EOR sites. The EPA recognizes also that CO2 transport costs for new coal-fired EGUs may vary geographically. There are multiple factors that contribute to the cost of CO2 transportation via pipelines including but not limited to: availability and acquisition of rights-of-way for new pipelines, capital costs, operating costs, length and diameter of pipeline, terrain, flow rate of CO2, and the number of sources utilizing the pipeline. Studies and DOE quality guidelines have shown CO2 pipeline transport costs in the $1 to $4 dollar per ton of CO2 range. The EPA does not agree that the potential geographic variability of potential new EGU sites renders the pipeline transport of CO2 either technically or economically infeasible. Potential sequestration sites, either EOR formation or saline formations or other non-EOR formations, are located throughout the United States and the EPA anticipates that proposed sites for new EGUs will be located in proximity to potential sequestration sites, and provision of electric power generation does not require coal-fired facilities to be co-located with the electric power demand they are intended to serve. State and Federal agencies have permitted CO2 pipelines for decades, and several proposed CO2 pipelines are currently in the state or federal agency permitting process and several others have recently been permitted. The EPA views the existing licensing process as adequate for any new CO2 pipelines that may be needed to transport CO2 from new coal-fired EGUs.       
Commenter 10618 listed out examples of permitting related challenges to the schedule and budget of any CCS project, including extensive field study requirements for permit applications, multiple jurisdictional issues, and lack of experience permitting CCS on both the developer and regulator sides. The commenter stated that the permitting process for the pipeline and well aspects of a CCS project alone could take years to resolve before construction could even begin. Commenter 9472 also identified the long lead times and capital expenditure as issues for siting and construction of CO2 pipelines.
Commenter 10083 noted that the large proportion of federally controlled lands in western states also creates its own challenges with respect to the timely permitting and construction of new generation resources and any needed pipeline infrastructure.
The EPA recognizes that implementation of the rule may entail siting and construction of CO2 pipelines crossing Federal land. Federal agencies have decades of experience in reviewing and authorizing proposed CO2 pipeline projects crossing Federal land, The Federal Bureau of Land Management (BLM), which manages approximately 250 million acres of land in the western U.S., has well-established procedures for permitting CO2 pipelines proposed to cross BLM land, and has issued permits for CO2 pipelines. 
The BLM in 2014 conducted reviews of proposed CO2 pipeline projects under the BLM's legal authority and established NEPA process. 

The EPA recognizes that the review process for siting and construction of CO2 pipelines crossing Federal land differs from processes that would be implemented for CO2 pipelines crossing privately owned or other non-Federal land, and that the Federal land management process may have a longer review schedule than for pipelines crossing privately owned or other non-Federal land. However, the EPA does not agree that the Federal land management process represents a substantial impediment to the timely siting and construction of CO2 pipelines that may be needed, as evidenced by the fact that many of the existing CO2 pipelines cross Federal land. BLM conducted reviews of proposed CO2 pipelines in 2014 and other pipeline projects were proposed for review in 2014. The reviews of proposed CO2 pipeline projects conducted by the BLM demonstrates that the Federal agency review process is a manageable process that would not impede the siting and construction of new CO2 pipelines.
Commenter 9735 stated that EOR is only feasible when coal plants are located relatively close to a mature oil field. The reality is that coal and oil formations are often far apart and CO2 pipelines that would be required do not exist. When EOR is not an option, utility companies will need to transport CO2 to appropriate geologic formations, such as saline aquifers. Commenters 8032, 9197, and 9735 noted that regardless of storage method, a vast pipeline infrastructure for CO2 will need to be built that will have siting, permit, and regulatory challenges that will add additional time and cost to any CCS project.
The EPA recognizes that some new EGUs may not be located in the vicinity of EOR formations and may need to transport captured CO2 to saline aquifer or other non-EOR sequestration sites. Potential sequestration sites are located throughout the United States, and construction of CO2 pipelines is adequately demonstrated. The EPA has addressed comments on storage in the Section 6.3 topic titled Geologic Sequestration. State and federal agencies have several decades of experience with CO2 pipeline permits and the EPA anticipates that existing processes will continue to support future needs for siting and construction of new CO2 pipelines. With respect to the timing of siting and construction of new CO2 pipelines, construction of new EGUs is anticipated to be limited for the foreseeable future, and any new EGUs proposed would need to be planned prior to siting and construction, and the EPA anticipates that the CO2 pipelines needed to transport captured CO2 from new EGUs could be planned, sited, and constructed within a similar timeframe as the timeframe for planning, siting, and constructing the new EGU itself. Therefore the EPA does not anticipate that CO2 pipeline siting and construction will represent a substantial barrier for affected EGUs.
Commenter 9201 cited a study that that the U.S. and Canada will need more than 35,000 miles of additional natural gas transmission pipelines (both mainline and laterals) through 2035 to serve anticipated growth in natural gas demand, and that about three fourths of the incremental growth in demand will arise from the power sector doubling its consumption as a result of EPA policies including CO2 NSPS rules for new and existing power plants. Commenter 9201 noted that the EPA did not consider or evaluate the impacts on land use and other environmental values from natural gas pipeline construction to supply increased demand -- including new natural gas power plants.
Siting and construction of proposed interstate natural gas pipelines is subject to certification by FERC. FERC has established and implements procedures for environmental reviews of proposed natural gas pipelines under Federal NEPA regulations and FERC's implementing regulations. NEPA reviews of proposed natural gas pipelines include consideration of land use and other environmental impacts of construction and operation of the proposed pipeline. Proposed intrastate natural gas pipelines are subject to permitting and environmental reviews under state regulations. Therefore, the land use impacts of any natural gas pipelines proposed to support growth in natural gas demand would be subject to project-specific environmental reviews including consideration of land use impacts. FERC conducts environmental reviews of proposed natural gas pipelines during the course of the natural gas pipeline certification process, which takes an average of fourteen to sixteen months. 
Safe Drinking Water Act's Underground Injection Control (UIC) Program and Resource Conservation and Recovery Act
Commenters 9425 and 9666 stated concerns with monitoring of CO2 geologic sequestration wells. The commenters noted the Class VI program requires extensive monitoring and fifty years of post-closure site care as a default which will add significant cost to CCS. Commenter 9666 also stated the concern that State program administrators could lengthen the site care responsibility indefinitely. Commenter 9426 asserted that a default of 50 years of post-closure site care is too long and adds significant additional costs. The commenter further stated that program administrators could further lengthen the site care responsibility indefinitely, posing a significant potential obstacle to CCS deployment. 
This rule does not change the requirements for site closure of Class VI wells that were established in the Class VI Rule. Site closure is defined by regulation (40 CFR 146.81) as the time at which the Class VI injection well owner or operator is released from post-injection site care responsibilities. Under the Class VI UIC regulations, following cessation of injection, the operator must conduct comprehensive post-injection site care to show the position of the CO2 plume and the associated area of elevated pressure to demonstrate that neither poses an endangerment to USDWs  -  also having the practical effect of preventing releases of CO2 to the atmosphere. Post-injection site care includes appropriate monitoring and other needed actions (including corrective action). The default duration for the post-injection site care period is 50 years, with flexibility for demonstrating that an alternative period is appropriate if it ensures non-endangerment of USDWs. For example, following the operational period for its project, Archer Daniels Midland plans a post-injection site care period of 10 years. Under the Class VI regulations, the owner or operator of a GS site is released from Class VI related post-injection site care responsibilities upon site closure. See generally preamble section V.N.1.
The EPA's cost estimates account for the requirements of the UIC Class VI program, and GHGRP subpart RR, including operational and post-injection site care monitoring, which are components of the UIC Class VI requirements, and subpart RR. Based on DOE/NETL studies, the EPA estimated that the total CO2 transportation, storage, and monitoring cost associated with EGU CCS would comprise less than 5.5 percent of the total cost of electricity in all capture cases modeled. The studies also show that post-injection site care, which includes monitoring, accounts for between 15 and 22 percent of total storage costs. The monitoring costs do not add significantly to the overall cost of CCS. 
Commenters 9423, 9425, 9426, 9666 stated concerns with liability. Commenter 9425 acknowledged that the EPA has established new Class VI regulations under the UIC Program for geologic sequestration wells that address some of the uncertainties in the regulatory framework, including site characterization, design and construction requirements for wells, operating and post-injection monitoring, testing of well integrity and financial responsibility. However, the commenter stated that the proposal does not address liability which remains an impediment to broad deployment of CCS. Commenter 9666 stated that limitation of liability would most likely require congressional action and it is unlikely the EPA could have addressed this issue effectively by rule without additional authority from Congress. The commenter noted this as another indicator that CCS is not an available technology for new EGUs. Commenter 10033 stated that from the perspective of CCS technology itself, although several projects have been successful, these projects have been too small and few in number to provide confidence that carbon sequestration projects will be protective of underground sources of drinking water at the large injection volumes and long time frames that would be found at a commercial power plant. 
Commenter 9472 stated that the EPA did not address two types of significant challenges operating CO2 storage facilities in saline formations face. First, the existing regulations for CO2 injection in saline formations, permitted as Class VI injection wells under the EPA's UIC program, pose practical barriers to project development including the 50 year post-injection site care monitoring period. Second, the long-term liability framework for injected CO2 remains uncertain in many areas of the country and limits the opportunity to store CO2 in saline formations in those regions. This period has the potential to exceed the lifetime of organizations involved in the original injection program, adding contractual and legal challenges to the development of a CO2 injection operation. The commenter also noted that while the full breadth of considerations will vary by site and project, they impact the feasibility of integrating CCS at a power plant, and must be sorted out prior to the beginning of CCS operations because subsurface storage must be operational at all times for a CCS project.
The EPA has addressed comments regarding liability in the Section 6.3 topic titled Liability and post-injection site care monitoring elsewhere in this topic titled Safe Drinking Water Act's Underground Injection Control (UIC) Program and Resource Conservation and Recovery Act. Limitation of liability is not a significant impediment to this rule. The EPA has issued Class VI permits for six wells under two projects. Both permit applicants addressed siting and operational aspects of GS (including issues relating to volumes of the CO2 and nature of the CO2 injectate), and included monitoring that helps provide assurance that CO2 will not migrate to shallower formations. The permits were based on findings that regional and local features at the site allow the site to receive injected CO2 in specified amounts without buildup of pressure which would create faults or fractures, and further, that monitoring provides early warning of any changes to groundwater or CO2 leakage. The permitting of these projects illustrates that permit applicants were able to address perceived challenges, including liability. These permits demonstrate the EPA's view that these projects are capable of safely and securely sequestering large volumes of CO2 -- including from steam generating units -- for long-term storage since the EPA would not otherwise have issued the permits. Furthermore, as shown in preamble section V.M, monitoring studies conducted at EOR and saline sites in the U.S. and internationally have demonstrated that large injection volumes can be safely injected. 
Commenter 10033 stated that while EPA's Class VI rules on carbon sequestration promulgated under the UIC program address many of the potential causes of drinking water contamination, the commenter continues to be concerned with some of the rule's provisions that were included over the strong objections of the drinking water community. For example, commenter noted that the "injection depth waiver" process allowed by the Class VI rule has many limitations that could result in degradation of USDW (underground sources of drinking water). According to the commenter, repeated requests to clarify and limit injection depth waivers to protect USDW have so far gone unanswered and several expected guidance documents, such as the guidance on injection depth waivers, have not yet been publicly released. The commenter and commenter 10786 stated that to their knowledge, there has never been a single Class VI UIC permit issued anywhere, and only a few applications have been submitted. The commenter concluded that although the foundation for a regulatory system exists, it is not yet a mature process and should not be relied upon at a large scale before it has been fully proven. 
Comments regarding the final Class VI rule requirements related to injection depth waivers are outside the scope of this rulemaking. This rule does not change the existing injection depth waiver process, which was established by the Class VI rule. See 75 FR 77254 (December 10, 2010).
In the time since the commenter submitted comments, the EPA has issued six Class VI permits for two projects: an Archer Daniels Midland ethanol facility in Decatur Illinois and the FutureGen Industrial Alliance project. It would not have done so, and under the regulations could not have done so, without demonstrations that CO2 would be securely confined.
Commenter 9596 stated that although the recent promulgation of rules under the Resource Conservation and Recovery Act (RCRA) and the Safe Drinking Water Act (SDWA) for underground CO2 injection wells may remove a certain amount of regulatory uncertainty, it has created new concerns in the oil and gas exploration industry over the regulatory impact of accepting CO2 from EGUs in EOR operations. 
With respect to the RCRA conditional exclusion rule, EPA made clear that that rule was not intended to affect the RCRA regulatory status of CO2 streams that are injected into wells other than UIC Class VI wells, including UIC Class II wells used for EOR. See 79 CFR 355 (Jan. 3, 2014).
In response to inquiries and concerns, similar to those of Commenter 9596, directed to EPA's Underground Injection Control Program, on April 23, 2015, the EPA's Director of the Office of Ground Water and Drinking Water issued a memorandum to its regional UIC Program Directors reflecting the principle that injection of anthropogenic CO2 for enhanced recovery through Class II wells does not force transition of these wells to Class VI wells  -  not during the well's active operation and not when EOR operations cease. See section V.N.5.a of the preamble for a summary of the memorandum.
Commenter 10786 stated that the NSPS is not in accord with SDWA's provisions for delegated State Class II programs, including with respect to the increased risk analysis under section 144.19. Unless taking place within the context of an existing Class II permit (presumably issued by a State agency), none of these collateral inquiries regarding existing CO2-EOR operations is envisioned by or authorized under SDWA and its governing regulations. In a State with primacy over its Class II program, all relevant assessments and decisions under 40 C.F.R. Section 144.19 are in the exclusive domain of the relevant State Class II regulator. Indeed, the Transition Guidance later seems to concede as much, noting that relevant considerations will have to be addressed in specific Class II permits. Transition Guidance, p. 6. 
The EPA encourages Class II and Class VI UIC Program Directors to work together to address the potential need for transition from Class II to Class VI permits. Additionally, the EPA believes that the best implementation approach is for states to administer both the Class II and the Class VI UIC programs. Nothing in this final rule changes the provisions of SDWA or the authority of the states to administer Class II permits. 
Commenter 10786 stated that the Section 144.19 confirms that NSPS is not a "logical outgrowth" of the originally proposed rule. The commenter noted that the EPA's interpretation of 40 C.F.R. Section 144.19 advanced in the Transition Guidance and implicitly adopted by the NSPS provides post-hoc confirmation that this final regulatory provision is not a "logical outgrowth" of EPA's original proposal. It was not until the EPA released the Transition Guidance, as implicitly incorporated thereafter by the NSPS, that industry was made aware that the Agency is now reading section 144.19 as authorizing forced conversions to Class VI (and perhaps at the Class VI Director's discretion). The positions in the NSPS are in direct conflict with both section 144.19 and the Agency's prior statements regarding how EOR was to be treated on these matters. 
The commenter is mistaken. EOR wells across the United States are currently permitted as UIC Class II wells. CO2 storage associated with Class II wells is a common occurrence, and where injected through Class II-permitted wells for the purpose of oil or gas-related recovery CO2 storage can occur in a manner protective of underground sources of drinking water. See also previous response.
Commenter 9423 stated the disincentives created by EPA for use of captured CO2 in EOR activities is further exacerbated by EPA's recent Draft UIC Program Guidance on Transitioning Class II Wells to Class VI wells that gives broad discretion to the EPA to determine when an existing Class II EOR well should be regulated and permitted as a Class VI geosequestration well. According to the commenter, the uncertainty of whether a Class II EOR well would be required to meet Class VI geosequestration well requirements as well as the cost, time, and long-term liability to transition a well from Class II to Class VI will be an additional significant disincentive for EOR well operators to accept utility- produced CO2. Commenter 9423 stated that the Class VI UIC regulations as adopted require a determination as to whether or not the primary purpose of the injection of CO2 is enhanced recovery. If the answer is yes, the well remains a Class II well. If the answer is no, then a determination must be made as to whether risks to underground drinking water sources have increased. 
Commenters 9731 and 10786 stated that if CO2 is to be a viable commercial product for use in EOR, the EPA must be mindful of the consequences of other significant regulations. For example, the UIC Class VI rule will mandate a conversion from the Class II wells currently used for CO2 injection, which will create additional costs with a number of regulatory and legal uncertainties and challenges.
Commenter 10786 stated that long-term storage with EOR will require an understanding of state legal and regulatory frameworks and how businesses can conduct operations under Class VI that is not present in the NSPS.  
Several commenters (9197, 9596, 9780) stated that the need to transition from Class II injection wells to Class VI wells under draft EPA guidance could further discourage EOR operators from accepting CO2 from EGUs for GS. 
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 commenters' concerns are misplaced. The EPA recognizes the widespread use of EOR and the expectation that injected CO2 can remain underground. The memorandum reflected these principles: 
      *       Geologic storage of CO2 can continue to be permitted under the UIC Class II program. 
      *       Use of anthropogenic CO2 in EOR operations does not necessitate a Class VI permit. 
      *       Class VI site closure requirements are not required for Class II CO2 injection operations. 
      *       EOR operations that are focused on oil or gas production will be managed under the Class II program. If oil or gas recovery is no longer a significant aspect of a Class II permitted EOR operation, the key factor in determining the potential need to transition a EOR operation from Class II to Class VI is increased risk to USDWs related to significant storage of CO2 in the reservoir, where the regulatory tools of the Class II program cannot successfully manage the risk. 
Either Class VI or Class II wells may be used for the purpose of complying with this rule. This rule does not require Class II wells to transition to Class VI.
Commenters 9472 and 10098 stated that changing well class is a major business decision carrying many long-term financial and regulatory obligations and would likely require an EOR operator to obtain additional property or other legal rights, all of which create significant uncertainty and materially impact an EOR-to-geologic storage operator's business model. The commenters further asserted that if the source of CO2 can contribute to an Agency decision that a Class II well needs to be re-permitted as a Class VI well, then EPA's Class II to VI Guidance has created a disincentive to using CO2 from a new coal-fired EGU. Taken with the RCRA conditional exemption, the Class II to VI Guidance and the proposed NSPS requirement for an EOR operator to comply with Subpart RR reporting requirements create a strong set of disincentives for accepting a CO2 stream from an EGU subject to the NSPS when other CO2 sources are available.
Commenter 10786 discussed the permitting delays and regulatory risks associated with forcing the operation to convert to Class VI, which may preclude timely access to oil. 
These comments are misplaced. No change in well class would result from the standards of performance adopted pursuant to section 111(b). On April 23, 2015, the EPA's Director of the Office of Ground Water and Drinking Water issued a memorandum to its regional UIC Program Directors reflecting the principle that geologic storage can continue to be permitted under the UIC Class II Program and the of anthropogenic CO2 in EOR operations does not necessitate a Class VI permit. See section V.N.5.a of the preamble for a summary of the memorandum. The memorandum is available at: http://water.epa.gov/type/groundwater/uic/class6/upload/class2eorclass6memo.pdf. With respect to the RCRA conditional exclusion, see previous response.
Commenter 10786 stated that the underlying but unstated premise of the NSPS is that approved State-based Class II programs are somehow ineffective at preventing injections that endanger USDWs; however, all approved State-based Class II programs already have been determined by the Agency to be effective at meeting that goal.
The commenter is mistaken that the premise of the NSPS is that Class II programs are ineffective at protecting USDWs. Geologic storage of CO2 can continue to be permitted under the UIC Class II program. EOR wells across the United States are currently permitted as UIC Class II wells. CO2 storage associated with Class II wells is a common occurrence, and where injected through Class II-permitted wells for the purpose of oil or gas-related recovery CO2 storage can occur in a manner protective of underground sources of drinking water. 
Commenters 8974, 10033 and 10393 stated that CCS should continue to be considered an experimental technology at this time because CCS could pose significant risks to drinking water sources if rushed prematurely to commercial scale. Commenter 10033 stated that it is quite possible that rushing CCS to commercial scale without adequate research and safeguards could make large amounts of US drinking water permanently unsuitable for use as community water supplies through altering the aquifer's chemistry. Commenter 10393 noted that their combined municipal utility has an obligation to protect existing and future drinking water resources located in deep saline aquifers, in addition to providing reliable, affordable and environmentally responsible electricity.
The EPA appreciates that drinking water resources must be protected. The EPA's UIC Program requirements  - for well Classes I through VI (inclusive of Class II enhanced recovery injection wells)  -  are designed to ensure that USDWs are protected regardless of formation type. See Preamble at Section V.N.1. In short, the UIC Class VI rule was developed to facilitate GS and ensure protection of USDWs from the particular risks that may be posed by large scale CO2 injection for purposes of long-term GS. The Class VI rule established technical requirements for the permitting, geologic site characterization, area of review (i.e., the project area) and corrective action, well construction, operation, mechanical integrity testing, monitoring, well plugging, post-injection site care, site closure, and financial responsibility for the purpose of protecting USDWs. UIC Class II regulations issued under section 1421 of SDWA provide minimum federal requirements for site characterization, area of review, well construction (e.g., casing and cementing), well operation (e.g., injection pressure), injectate sampling, mechanical integrity testing, plugging and abandonment, financial responsibility, and reporting. Class II wells must undergo periodic mechanical integrity testing which will detect well construction and operational conditions that could lead to loss of injectate and migration into USDWs. Section 1425 of SDWA allows states to demonstrate that their Class II program is effective in preventing endangerment of USDWs. These programs must include permitting, inspection, monitoring, record-keeping, and reporting components.
The comment that these injection technologies are not available at commercial scale is misplaced. See Preamble sections V.M and V.N. The EPA has issued six Class VI injection well permits under the Class VI requirements, including for injection of anthropogenic CO2 from a coal-burning steam electric facility.
Commenter 6948 stated that for a CCS survey of the 50 states no state has yet received delegation of the Class VI UIC, although one state has an application pending for delegation of the program.
The EPA encourages states to apply for primacy for all well classes, including Class VI. The EPA is in the process of reviewing North Dakota's application for primacy and believes that the best implementation approach is for states to administer both the Class II and Class VI UIC programs. The process of approving primacy for a state to implement the regulations for specific classes of injection wells is not a delegation, rather it is an approval by a rule-making process required by the Safe Drinking Water Act and outlined in the UIC regulations.
Commenter 8032 noted that Class VI injection wells will have to be used since there are not sufficient Enhanced Oil Recovery sites for all of the power generation facilities that will have carbon capture systems. These sites also may not be close to the power generation facilities making them infeasible. Class VI injection wells will have to be carefully designed or there could still be a release of CO2 in to the atmosphere which will be counterproductive, costly and dangerous. Class VI wells must be designed to handle the unique nature of CO2 including the relative buoyancy of CO2, its mobility in the subsurface, its corrosive nature in the presence of water, and the large injection volumes anticipated at these sites.
The EPA agrees that it is important to ensure that CO2 is safely stored, does not impact USDWs and is not released to the atmosphere. Under SDWA and its Underground Injection Control Program, the EPA established minimum Federal requirements to ensure that geologic sequestration (Class VI) wells are appropriately sited, constructed, tested, monitored, and closed to ensure protection of drinking water. The UIC Class VI regulations contain monitoring requirements to protect underground sources of drinking water, including a requirement that Class VI owners or operators develop, implement and maintain a comprehensive testing and monitoring plan, which includes testing of the mechanical integrity of the injection well, ground water monitoring, and tracking of the location of the injected CO2, using direct and indirect methods. Permittees are also required to perform post-injection monitoring and site care to track the location of the injected CO2 and monitor subsurface pressures in relation to USDWs. 
Commenters 9666, 9780, 10098, 10239 and 10660 asserted that the EPA has ignored significant legal and logistical barriers to geologic sequestration by focusing solely on federal regulations under the UIC program, GHG Reporting Rule, and RCRA. Commenter 8966 stated that geologic sequestration is subject to state and local laws that are likely to confound operators unless national legislation is available to address property rights and other legal constraints.
Commenters 9666 and 10098 stated that the proposed rule assumes there is a full infrastructure and regulatory framework in place even though it may take years to put into place. 
Commenter 10098 then stated that the analysis of the legal issues surrounding geologic sequestration, consisting of Class VI well permits, reporting requirements, and RCRA exemptions, is myopic. The commenters then discussed the potential barriers to obtaining contracts for offsite land acquisition, funding, timing of available transportation infrastructure, and developing a site for secure long term storage without state or federal eminent domain as natural gas pipelines have. 
Commenters 10098 and 10239 provided examples of permitting decisions rejecting CCS in part because it was not clear that the applicant could obtain the necessary rights of way in part due to the lack of proven geology favorable for long-term storage and other uncertainties.
Commenter 10137 stated that there are uncertainties surrounding whether subpart RR would constitute waste disposal. The commenter further stated that it appears that subpart RR is inconsistent with typical oil and gas leases if subpart RR converts a hydrocarbon recovery operation into a waste disposal site, because typical leases come to an end and the property reverts to the owner following oil and gas completion. Commenters 10137 and 10786 also noted that the underlying mineral leases pursuant to which EOR operators are authorized to conduct oil recovery operations are granted for the purpose of hydrocarbon recovery and do not authorize the lessee to convert the owners' property into a waste disposal site. Commenter 10786 stated that declaring some CO2 streams to be a "solid waste" under RCRA will make that CO2 stream unsuitable for injection and associated long-term storage in Class II mineral recovery operations, which the NSPS fails to acknowledge.
Two commenters (9731, 9666) stated that compliance with subpart RR will transform an EOR operation from a resource recovery operation/maximization into a waste disposal operation.
The EPA has addressed the issues related to state and local laws in the Section 6.3 topic titled Other CO2 Transport and Geologic Sequestration Legal and Regulatory Issues. With respect to injection-related permitting, in the time since the commenter submitted comments Class VI permits have been issued to two applicants by the EPA. Both applicants, Archer Daniels Midland (ADM) and FutureGen Alliance, addressed siting and operational aspects of GS (including issues relating to the perceived barriers mentioned by the commenter) in their permit applications. The fact that these applicants pursued permits indicates that they regarded any potential property rights issues as resolvable. Analyses of other (non-injection related) permitting decisions with respect to application of CO2 capture and transport were conducted on a site-specific basis and considered site-specific factors in the analysis and were conducted under a different set of criteria than required under the CAA. Eminent domain issues are addressed in the Section 6.3 topic titled Geologic Sequestration Property Rights.
Reporting under subpart RR does not cause an activity to become a waste management activity. In the preamble for the Final Rule for RCRA Conditional Exclusion of CO2 as a Hazardous Waste in January 2014, the EPA stated that sending CO2 streams to Class VI wells for purposes of GS does constitute solid waste disposal. The EPA also noted that should CO2 be used for its intended purpose as it is injected into UIC Class II wells for the purpose of EOR/EGR, it is EPA's expectation that such an injection process would not generally be a waste management activity, and that in any case, the rulemaking did not alter the regulatory status quo of anthropogenic CO2 injected for EOR (which has been done for decades without RCRA obligations being considered to impact or impede those operations). 
Commenter 9683 asserted that the proposed rule does not recognize the legal and regulatory structure needed for CCS, therefore impeding CCS's availability.
The EPA believes that the Safe Drinking Water Act (SDWA), Resource Conservation and Recovery Act (RCRA) and Clean Air Act (CAA) will provide the necessary regulatory framework while ensuring environmental protection and the permanence of CO2 storage. The specific protections offered under these regulations are addressed elsewhere in this section and in preamble section V.N.
Commenter 9666 summarized West Virginia Chamber of Commerce survey of the state laws, regulations, and CO2 which found that states do not have adequate regulatory mechanisms in place to support CO2 sequestration. The survey found that no state has yet received delegation of the Class VI Underground Injection Control ("UIC") program related to underground CO2 injection; only 5 states have addressed what property rights must be secured for the geologic storage of CO2 in pore space; only 7 states have developed any streamlined procedures for acquiring pore space; only 4 states have developed programs addressing the mitigation of the long-term post-closure liabilities that are associated with facilities that store CO2 in geologic formations; and only 12 states have provided any streamlined process for the siting or construction of pipelines used to transport CO2.
Commenters 10033 and 10618 stated that to date, the EPA has not issued a single final Class VI permit and only a handful of states are pursuing primacy. The commenter further discussed if a permit is obtainable given the area required to accommodate the CO2 storage volume associated with a coal-based generation unit. With regard to the permit process, the commenter discussed the time required to prepare an application as well as process and issue a permit. Commenter 10618 cites an example of a 2011 permit application still under technical review to support the statement that the regulatory process is likely to be prohibitive. Commenter 10033 also asserted that at a minimum, there should be several years of successful administration of Class VI permits and associated commercial demonstration-scale projects before the EPA or any other agency considers requiring the implementation of CCS technology on a wider scale.

Commenter 10618 states that with regard to the EPA Class VI injection well monitoring and care requirements, a number of uncertainties during and beyond a 50 years post-injection period must be addressed including transfer of liability after closure, financial responsibility requirements and duration, and post-closure monitoring requirements and duration.
Commenter 9666 is correct that no state has yet received primary enforcement authority (primacy) for the Class VI UIC program. However, the EPA is in the process of reviewing North Dakota's application for primacy and believes that the best implementation approach is for states to administer both the Class II and Class VI UIC programs. The EPA encourages states to apply for primacy for all classes, including Class VI. 
In the time since the commenter submitted comments, the EPA has issued six final UIC Class VI injection well permits for two projects. The fact that these applicants pursued and received permits indicates that they were able to resolve any issues related to the project area or "Area of Review" (referred to by the commenter as "the area required to accommodate the CO2 storage volume"). The EPA believes that the regulatory framework currently in place, and the experience gained from the recent permit application reviews, permitting, and demonstration Under the Class VI regulations, the owner or operator of a GS site is released from Class VI related post-injection site care responsibilities upon site closure. 
Commenter 9426 stated that specific implementation regarding the permitting of Class VI CO2 storage wells is also uncertain and unquantified, as regulatory agencies are just now beginning to address specific requirements regarding how these permits can be issued.
The EPA has issued six final UIC Class VI injection well permits for two projects and has developed a series of technical guidance documents and tools to provide information and possible approaches for addressing various aspects of permitting, constructing, operating, monitoring and closing a Class VI injection well.
Commenter 10618 stated that uncertainties regarding the extent of EOR exemption from RCRA, such as RCRA applicability when the EOR process ends or if the process becomes solely a geologic storage operation, could actually discourage the use of anthropogenic CO2 for EOR operations.
In January 2014 the EPA issued the Final Rule for RCRA Conditional Exclusion of CO2 as a Hazardous Waste in order to facilitate the deployment of geologic sequestration. The rule establishes a set of conditions under which CO2 streams injected into UIC Class VI wells are excluded from the RCRA subtitle C regulations' definition of hazardous waste. In the preamble to the rule, the EPA explained that sending CO2 streams to Class VI wells for purposes of GS is considered solid waste disposal, since the CO2 stream is being "discarded" (see RCRA section 1004 (27)). However, that rule also creates a regulatory exclusion from classification as a hazardous waste, so no RCRA subtitle C regulatory obligations are triggered when the CO2 stream is managed in accordance with the conditions. With respect to beneficial use (rather than disposal in Class VI wells) of captured CO2, the RCRA conditional exclusion rule does not alter the regulatory status quo. The EPA also stated in the preamble that should CO2 be used for its intended purpose as it is injected into UIC Class II wells for the purpose of EOR/EGR, it is EPA's expectation that such an injection process would "not generally be a waste management activity." 
Commenter 10098 discussed EPA's determination that conditionally exempted captured CO2 streams that are injected into Class VI wells, not those injected into Class II wells are a RCRA solid waste. The commenter suggested that CO2 injected into a Class II well for EOR could, in some situations, be considered a waste management activity and creates uncertainty and a significant disincentive for operators utilizing CCS-derived CO2 for EOR purposes. Commenter 9734 also stated that there is regulatory uncertainty surrounding the underground sequestration of CO2 due to EPA's determination that sequestered carbon is a solid waste.
Furthermore, the commenter suggested that the informal "safe harbor" for traditional EOR may only apply to the practice of injecting natural CO2, not captured CO2 streams. Therefore, if an oil and gas operator wants to use a CO2 stream from a new coal-fired EGU for EOR operations and avoid RCRA rules, the commenter stated that it may need to persuade the permitting agency that its EOR operations are not waste management activities or perform RCRA hazardous waste analyses on all accepted CO2 streams. The commenter stated that no standardized analyses exist for this material, so an EOR operator would need to develop them. The commenter also asserted that if a CO2 stream tests hazardous, the EOR operator needs contractual rights to reject and return the non-conforming CO2 stream.
As just stated, these concerns are not borne out by actual experience. The RCRA subtitle C regulations have not been an historic impediment to use of anthropogenic CO2 for EOR, and nothing the EPA has said in this rulemaking or the RCRA rulemaking conditionally excluding CO2 sequestered in Class VI injection wells alters the present status quo. The EPA stated in the preamble of the Final Rule for RCRA Exclusion that should CO2 be used for its intended purpose as it is injected into UIC Class II wells for the purpose of EOR/EGR, it is EPA's expectation that such an injection process would not generally be regarded as a waste management activity. 
Commenters 10098 and 10239 asserted that if geologic storage is a form of waste management, as the EPA contends it is, then even incidental leakage of this CO2 stream could form the basis for RCRA liability and result in citizen suits. The commenter stated that the operator would not be covered by the RCRA conditional exemption if the CO2 stream was injected into a Class II well.
The status of captured CO2 used for EOR in Class II is unaltered as a result of the conditional exclusion for CO2 disposed in Class VI wells, and likewise unchanged by anything in the standards adopted pursuant to section 111 (b). Class II wells have been injecting anthropogenic CO2 for decades under this existing regulatory structure without RCRA obligations being considered to impact or impede those operations.
Commenter 10618 stated that uncertainties regarding the extent of EOR exemption from RCRA, such as RCRA applicability when the EOR process ends or if the process becomes solely a geologic storage operation, could actually discourage the use of anthropogenic CO2 for EOR operations.
The EPA's recent RCRA conditional exclusion rule applies only to CO2 streams that are injected into UIC Class VI wells (among other conditions). In the final rule preamble, the EPA discussed its view that supercritical CO2 streams injected into UIC Class VI wells for purposes of geologic sequestration are RCRA "solid waste." 79 FR 354-55 (Jan. 3, 2014). However, that rule was not intended to, and does not affect the regulatory status of CO2 streams that are injected into other well classes, including UIC Class II wells. Id. at 355. The EPA stated that, should CO2 be used for its intended purpose as it is injected into UIC Class II wells for the purpose of EOR/EGR, it is EPA's expectation that such an injection process would not generally be a waste management activity, and that interested persons should consult with the relevant regulatory authority. Id. Use of anthropogenic CO2 for EOR is long-standing and has flourished in all of the years that EPA's subtitle C regulations (which among other things, define what a solid waste is for purposes of those regulations) have been in place. The subtitle C regulatory program consequently has not been any impediment to use of anthropogenic CO2 for EOR. Thus, the EPA views the commenter's concerns as exaggerated, and not supported by experience. 
Greenhouse Gas Reporting Program
Commenter 9664 stated that they do not agree with EOR operators that have asserted that requiring compliance with the reporting and monitoring, reporting, and verification (MRV) plan requirements of subpart RR would result in operators avoiding the purchase of captured CO2. The commenter stated their belief that it is not inconsequential that available sources of naturally mined CO2 are declining, and that there is significant demand for anthropogenic CO2. Therefore, it is unlikely that existing operators would prefer to go out of business rather than access the market for anthropogenic CO2, simply because of the need for better reporting of the amounts of CO2 managed in EOR activity. The costs of opting into subpart RR by an existing EOR operator with a Class II permit are simply not significant, particularly when compared to the potential revenue from the sale of the produced oil, as provided by EPA calculations in the Energy Information Administration (EIA) for subpart RR rules.
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 agrees with the commenter's assertion that subpart RR requirements will not 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).
. Commenters 9664 and 9514 stated that as proposed, EPA's rule text does not impose any additional requirements on the affected facility to demonstrate that the CO2 has in fact been transferred to a facility that is compliant with subpart RR, that would be incorporated for example into its PSD and Title V permits for the facility. The requirement that the emitting EGU assure that captured CO2 is managed at an entity subject to subpart RR of the GHG reporting rules is exclusively an element of enforcement of the EGU standard. 
Commenters 9514 and 9664 requested revisions to 40 CFR 60.46Da(h) &(i) (concerning reporting and recordkeeping requirements). The commenters recommended amending 40 C.F.R. section 60.46Da(h)(5) in order to clearly establish an enforceable requirement that owners and operators of projects injecting CO2 underground that are permitted under UIC Class II and that receive CO2 captured from EGUs to meet the proposed performance standard will also be required to submit and receive approval of a subpart RR MRV plan and report under subpart RR. 
The commenters interpreted that the EPA means, by using the term "GS" in the regulatory text, to refer to any kind of sequestration, whether by injection into a Class VI permitted well or by injection for enhanced oil recovery via a Class II permitted well. However, the commenters noted the term "GS" is a defined term in the Safe Drinking Water Act UIC program context that is limited to CO2 injection for the primary purpose of long-term containment from the atmosphere, and does not encompass CO2 injection for the primary purpose of enhanced oil recovery, even where incidental long-term containment of the injected CO2 occurs as a result of that EOR activity. As a result, the commenters provided the following suggested revisions: "If your affected unit captures CO2 to meet the applicable emissions limit, your affected unit must use either (i) onsite or offsite GS, pursuant to a permit issued under Class VI of the Safe Drinking Water Underground Injection Program, and that reports in accordance with the requirements of 40 C.F.R. Part 98, subpart RR, or (ii) send the captured CO2 for use in enhanced recovery of oil or natural gas, through injection permitted under Class II of the Safe Drinking Water Act Underground Injection Program for that purpose and that reports in accordance with the requirements of 40 C.F.R. Part 98, subpart RR."
Additionally, the commenters stated that it is a necessary part of the documentation of the achievement of the emissions standards that such reporting must become a condition of the Title V permit for the facility.
The final rule requires that any affected EGU unit that captures CO2 to meet the applicable emissions limit must transfer the captured CO2 to a facility that reports under GHGRP subpart RR, where sequestration is part of the compliance path. In order to provide clarity on the requirement, the EPA reworded the proposed language under §60.5555(f) to use the phrase "If your affected unit captures CO2" in place of the phrase "If your affected unit employs geologic sequestration". This revision is not a change from the EPA's initial intent.
The EPA disagrees that the rule does not provide enforceable reporting and recordkeeping requirements related to the amount of CO2 that is being sent by an EGU to a facility that is compliant with subpart RR. The revisions being finalized at § 98.427(d) specifically provide that EGUs that are capturing CO2 and sending the CO2 to a facility that is subject to subpart RR "must retain records of CO2 in metric tons that is transferred to each subpart RR facility".
See preamble section XII. Implications for PSD and Title V Programs of the preamble for further discussion on PSD and Title V permits.
Commenters 9664 and 9514 asserted that the EPA must add provisions to require any EGU meeting the standard through long-term containment in a subsurface geological formation (either through GS or in enhanced oil recovery), to provide documentation showing that the volume of captured CO2 necessary to achieve the standard has been injected onsite to a facility permitted under the UIC program and reporting under subpart RR, or transferred to a facility that is permitted under the UIC program and reports under subpart RR. 
Commenters 9664 and 9514 suggested the following amendments to Subpart PP reporting requirements at 40 CFR 98.426 to reflect EPA's intent that captured CO2 will be permanently sequestered:
"Section 98.426 Data reporting requirements.
* * * *
(h) If you capture a CO2 stream from an electricity generating unit that is subject to subpart D of this part you must transfer the captured CO2 to a facility or facilities subject to subpart RR of this part, and you must:
(1) Report the facility identification number associated with the annual GHG report for the subpart D facility,
(2) Report each facility identification number associated with the annual GHG reports for each facility to which CO2 is transferred, and
(3) Report the annual quantity of CO2 in metric tons that is transferred to each facility."
The EPA disagrees with the commenter's suggested changes to 40 CFR Part 98 subpart PP. The suggested change would require all EGUs who capture CO2  -  new, modified, and existing  -  to send all of the captured CO2 to a facility subject to 40 CFR Part 98 subpart RR (Geologic Sequestration of Carbon Dioxide). The EPA believes that the current language in 40 CFR Part 98 is appropriate because the GHGRP covers not only EGUs that are subject to the NSPS, but also existing EGUs. It also allows EGUs to send some captured CO2 to other end uses.
Commenter 9766 stated the EPA has ample authority to establish monitoring and reporting requirements under Section 111 and therefore is not restricted only to the existing Greenhouse Gas Reporting Program to ensure proper monitoring and reporting of the disposition or fate of CO2 once transferred from an affected EGU.
The EPA agrees that it has the authority to establish reporting requirements under Section 111 for EGUs. However, the EPA believes that the existing UIC and GHGRP requirements help ensure that sequestered CO2 will remain in place, and provide the monitoring mechanisms to identify and address potential leakage using SDWA and CAA authorities. 
Commenter 1637 stated that there are only requirements that the source report under the GHG reporting rule 40 CFR 98 subpart RR if it is disposed onsite or subpart PP if disposed offsite. This reporting provision only requires a report of where it goes. It could all go to a facility that simply releases it to the atmosphere without any penalty to anyone. A requirement to dispose of it only to a facility that is injecting the CO2 and reporting under subpart RR should be plainly stated.
The EPA does not agree with the commenter's interpretation of the requirements in the rule but does agree generally with the commenter's conclusion that the final rule requires all affected units to send captured CO2 to a facility that is compliant with subpart RR of the GHGRP. 
Commenter 9664 found EPA's intention to require any new fossil fuel-fired boilers or IGCC employing CCS to meet the standard to send captured CO2 only to a facility that reports under subpart RR is reasonable and stated that the EPA properly relies on the subpart RR MRV plan to verify that the CO2 captured from an affected unit is injected underground for long-term containment. 
The commenter stated that for long-term containment occurring incidental to or in addition to EOR operations, a UIC Class II permit and the CAA subpart RR rules establish a similar framework and that since in the near term it is highly likely that EOR will be used to isolate captured anthropogenic CO2 from atmospheric release. It is therefore important for the EGU operator subject to this rule, be able to demonstrate that captured CO2 is sent either to a Class VI GS facility or to a Class II EOR facility reporting under subpart RR. 
The commenter further stated that EOR using mined natural CO2 presents the same risks of CO2 to atmospheric release, as does the use of captured CO2 from a power plant, and for that reason, and because there are no significant economic or technical impediments to requiring all EOR activity to report using subpart RR, the commenter urges the EPA to revisit the UU v. RR distinction, in the context of its reporting rules, and require RR reporting for all enhanced oil recovery activity permitted under UIC Class II. 
The EPA appreciates the commenter's shared view that relying on subpart RR to verify that the CO2 captured from an affected unit is injected underground for long-term containment is reasonable. The EPA agrees, and the final rule requires, that regardless of the class of well, Class II or Class VI, any facility receiving CO2 from an EGU that is capturing CO2 to meet the standards of this rule must comply with subpart RR requirements. The EPA does not agree with the commenter's suggestion to require all EOR facilities to report under subpart RR, and the comment is beyond the scope of this rulemaking in any case. Should the EPA be deemed to be required to answer the comment, the EPA maintains that the current subpart UU and subpart RR monitoring and reporting requirements are appropriate. 
Commenter 10618 stated that reporting tools upon which the EPA is relying have never been used. According to the commenter (10618), for calendar year 2012, only two facilities submitted any information to EPA's GHGRP for carbon injection activities. Both of these facilities have been granted research and development exemptions for GHG reporting, and both of them reported only the volume of GHGs received at the facility under subpart UU, not the detailed information required by subpart RR. The commenter (10618) continued that there were no estimates of the amounts of GHGs actually successfully sequestered, and neither facility has developed the kind of monitoring protocols required under subpart RR. Similarly, commenter 10095 stated the EPA cannot ignore that no injection site, of any size to date, has demonstrated the injection, storage, and monitoring of CO2 under subpart RR requirements. According to the commenter (10618), the remaining facilities listed in EPA's reporting tool are only subject to subpart UU, and are only required to report volumes of "new" CO2 received at the facility, not the amounts that are used in, recovered, and recycled through EOR or other operations, nor any amounts that may be emitted from those operations. As a result, the commenter stated that no useful information about the actual amounts of CO2 in recovered oil and gas, or emitted to the surface in connection with an EOR operation, has ever been submitted to the EPA. Based on this information, the commenter (10618) concluded that the EPA has no basis for its assumptions regarding the ability of EOR operators to successfully design a monitoring program that would meet the requirements of subpart RR.
One commenter (9666) stated that none of the 1,000 million metric tons of CO2 injected to date have been subject to subpart RR. About 120 million have been reported to the EPA since the reporting rules took effect beginning in 2011, all of which has been reported under subpart UU and not a single ton has come under the subpart RR rules. There are no approved MRV plans for CO2 injection in EOR operations for reporting under subpart RR. Hence, rather than being "adequately demonstrated", the subpart RR rules and procedures are unused, uncertain and unworkable for EOR operations.
The EPA disagrees that subpart RR is unworkable. First, subpart RR is built upon an understanding of the mechanisms by which CO2 is retained in geologic formations, which are well understood and proven. See Preamble section V.N.3. Second, international experience with large scale commercial GS projects has demonstrated through extensive monitoring programs that large volumes of CO2 can be safely injected and securely sequestered for long periods of time at volumes and rates consistent with those expected under this rule. This experience has also demonstrated the value and efficacy of monitoring programs to determine the location of CO2 in the subsurface and detect potential leakage through the presence of CO2 in the shallow subsurface, near surface and air. These projects have demonstrated that comprehensive monitoring can be accomplished at saline and EOR sites. With respect to EOR, and as discussed in Preamble section V.N.3, CO2 from the Great Plains Synfuels plant in North Dakota has been injected into the Weyburn oil field in Saskatchewan Canada since 2000. Over that time period the project has injected more than 16 million metric tons of CO2, with extensive monitoring by U,S. and international partners which has demonstrated that no leakage has occurred. The EPA also notes that the DOE has created a network of seven Regional Carbon Sequestration Partnerships (RCSPs) to deploy large-scale field projects in different geologic settings across the country to demonstrate that GS can be achieved safely, permanently, and economically at large scales. In April 2015, DOE announced that CCS projects supported by the department have safely and permanently stored 10 million metric tons of CO2.
One commenter (10095) noted that the EPA references the geologic storage opportunities in Canada and Dakota Gasification synthetic natural gas plant's utilization of EOR in the Weyburn oil field in Saskatchewan, Canada. According to the commenter, if the EPA intends to require any reporting, much less subpart RR, the EPA must elaborate on how it intends to enforce reporting requirements in other countries or eliminate these potential storage opportunities and plants from the Agency's analysis.
The commenter appears to misunderstand the discussion of the Great Plains Synfuels plant in North Dakota and Weyburn oil field in Saskatchewan, Canada, which provides an example of how geologic sequestration has been demonstrated. CO2 from Dakota Gasification has been injected into the Weyburn oil field in Saskatchewan Canada since 2000. Over that time period the project has injected more than 16 million metric tons of CO2. It is anticipated that approximately 40 million metric tons of CO2 will be permanently sequestered over the lifespan of the project. Extensive monitoring by U.S. and international partners has demonstrated that no leakage has occurred. 
One commenter (10618) stated that it appears that 85 facilities listed as being subject to subpart UU required no "new" CO2 (i.e., not the amounts that are used in, recovered, and recycled through EOR or other operations, nor any amounts that may be emitted from those operations) for their operations during the entire year, leading one to question the availability of EOR opportunities for the large amounts of CO2 that would be captured at even a single, partially controlled coal-fired steam generating unit. Based on this information, the commenter (10618) concluded that the EPA has no basis for its assumptions regarding the availability of sequestration at EOR operations.
40 CFR Part 98 Subpart UU requires the reporting of the amount of CO2 received for injection. The data element referenced by the commenter was previously determined to be confidential business information (CBI) at the facility level. 77 FR 48072 (August 13, 2012) Therefore the data is not made available on a facility-by-facility basis. The amounts reported by facilities are CBI and not zero. According to data reported to the GHGRP, approximately 60 million metric tons of CO2 were supplied to EOR in the United States in 2013. 
Commenter 9196 stated that the proposed rule relies heavily on the potential for power plants to sell CO2 to EOR operators as a means of defraying the tremendous costs of CCS, however, EOR operators are signaling that the subpart RR requirements in the proposed rule may be prohibitive. Broad coalition of groups, from EOR operators to electric power providers, has raised concerns about EPA's plans. The commenter requested that the EPA address the following concerns:
   a. 	Please explain in detail the new requirements for EOR operators that would accept CO2 from power plants?
   b. 	Have you spoken with any groups potentially impacted by the new subpart RR reporting requirements? How have you taken their concerns into consideration?
   c. 	Would reporting under subpart RR potentially trigger the transition of an EOR well from Class II to Class VI under the UIC program-as EPA draft guidance suggests?
   d. 	A significant part of EPA's economic justification for the proposed rule relies on the assumption that the CO2 from power plants will be a valued commodity used in EOR operations. How do the economics of the proposed rule change if this is no longer an option?
   e. 	Can you commit that EPA will not use reporting under subpart RR to push any EOR operations into Class VI. 
The EPA does not agree with the commenter's statement that the proposed rule relies heavily on the potential for power plants to sell CO2 to EOR operators. EOR facilities may facilitate early mover projects, but the proposal and final rule rely on CO2 being sent to deep saline formations, as indicated by the discussion in the preamble and the Regulatory Impact Analysis. 
The EPA also offers the following responses to the commenter's questions.
   a. Under the rule, any facility receiving CO2 from an EGU that is capturing CO2 to meet the standards of this rule must comply with the existing requirements of subpart RR. 
   b. Subpart RR of the Greenhouse Gas Reporting Program is not new. Rather, the regulations promulgating Subpart RR were finalized in 2010. The EPA reviewed and responded to public comments as part of the rulemaking that promulgated the Subpart RR requirements. As part of the notice-and-comment process of this rule, the EPA has reviewed and considered public comment on the proposal.  
   c. 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.
   d. Facilities using carbon capture are doing different things with the captured CO2, ranging from EOR to storage to using it for food products. While it is true that selling captured CO2 for EOR can generate revenue and help offset the costs of capturing carbon, this does not mean plants can only build in areas near EOR. In estimating costs for the proposed rule, the EPA considered various scenarios. See the Regulatory Impact Analysis for more discussion on the scenarios which the EPA considered and their estimate impacts. In estimating impacts, and in assessing costs for purposes of determining if partial CCS is BSER adequately demonstrated, the EPA relied conservatively on the case where CO2 would be sent to a deep saline GS formation. Therefore, the commenter is simply incorrect in stating that EPA's economic justification for the rule relies on the assumption that the CO2 from power plants will be used in EOR operations.
   e. An EOR project may be permitted as UIC Class II and report under Subpart RR. The regulatory provisions regarding transitioning from UIC Class II to UIC Class VI are set forth at 40 CFR 144.19. Reporting under Subpart RR of the Greenhouse Gas Reporting Program is not one of the factors specified in 40 CFR 144.19(b).
One commenter (10034) stated that the information collected through the GHGRP can be used to measure some of the agency's anticipated outcomes.
The EPA agrees with the commenter that the information collected through the GHGRP can help measure and track some of the EPA's anticipated outcomes. The EPA is finalizing changes to the reporting requirements of subpart PP of the GHGRP to help track these outcomes. 
Commenter (4733) stated that the EPA issued subpart RR to complement the UIC Class VI Rule. Compliance with subpart RR will allow GS operators to provide proof of sequestration, eliminating another barrier to CCS.
Similarly, commenter 9035 stated that the EPA has provided a pathway for demonstrating the geologic storage of CO2 utilized in EOR by meeting certain requirements of the Underground Injection Control Program and the Greenhouse Gas Reporting Program.
The EPA agrees that subpart RR complements the UIC Class VI regulations. The EPA also agrees that subpart RR will provides a mechanism for demonstrating the efficacy of GS, including in conjunction with EOR.
Commenter 9666 stated the reporting obligations under subpart RR are poorly defined, and may discourage CO2 injection facilities from accepting CO2 generated by sources subject to the proposed NSPS, particularly EOR facilities, which are not currently required to report under subpart RR. According to the commenter, because no entity has reported data to the EPA under subpart RR, there is lingering uncertainty as to what would be required from a subpart RR monitoring, reporting, and verification plan. Other commenters (9201, 9683, 10036, 10098, 10137, 9731, 10095) also expressed concerns with the potential uncertainty and risks compliance with subpart RR creates for EOR operators. 
One commenter (10098) opined that requirements to comply with subpart RR opined that this is problematic because there are no standards governing what may constitute an incomplete or otherwise unacceptable MRV plan, nor any timeline for approval, creating a completely open-ended and undefined regulatory framework. 
The EPA does not agree that the reporting obligations under subpart RR are poorly defined. There are clearly defined reporting requirements outlined in 40 CFR Part 98.446. As part of these requirements, the EPA has provided flexibility to reporters in regards to annual monitoring reports (40 CFR 98.446(a)(12)); the EPA views this as a way to balance the burden in reporters as each sequestration site is unique as opposed to a uncertain requirement. 
There are also clearly defined requirements for what must be included in a complete and acceptable subpart RR MRV Plan. The EPA identified all required components in a subpart RR MRV Plan in 40 CFR Part 98.448(a). In outlining these requirements, EPA's approach allows for site-specific flexibility for MRV plans and does not prescribe particular monitoring technologies. The approach also allows the owner or operator to leverage the site characterization, risk assessment, and/or monitoring required by other authorities as the foundation for demonstrating compliance with the MRV plan requirements of 40 CFR Part 98, subpart RR. 

The evaluation criteria and what would result in approval for a subpart RR MRV Plan are highly flexible. While the EPA recognizes that this may be mistaken as uncertainty, the geology and other conditions among facilities conducting GS vary. To provide more clarity for reporters, the EPA provided information in the General TSD of the Subpart RR final rule (Docket ID EPA-HQ-OAR-2009-0926) on the technical evaluation of MRV plans, including illustrative examples describing the types of information that may be included in the MRV plan to fulfill the regulatory requirements at 40 CFR 98.448.

In regards to the comment that asserted that there is not a timeline for approvals MRV plans, the EPA does not agree. 40 CFR 98.448(b) outlines a clear timeline for MRV Plan submissions, reviews, and iterations between the EPA and reporters (e.g., specifying the number of days allowed for each step in the process). 

All of these components of subpart RR results in a clearly defined regulatory framework for accounting for GS. 
Commenter 10137 noted all decisions (about subpart RR MRV plans) are open to litigation by any "interested person" under Part 78 litigation procedures, and hence, prior to closing financing to allow construction to begin, the developer of a new power plant seeking to implement carbon capture and storage as the compliance tool for meeting the new standards is unlikely to be able to obtain a commitment from an EOR operator to become subject to undefined and open-ended requirements that may extend decades into the future.
The commenter is correct that subpart RR MRV Plan final decisions may be appealed to EPA's Environmental Appeals Board by an interested person per the requirements under Part 78. However, the EPA does not agree that this process prevents EGUs from obtaining a commitment from EOR operators. Without the administrative appeals process, the reporters' and interested person's only option becomes litigation, which the EPA believes would be more disruptive and costly, and delay implementation of MRV plans further. Additionally, while the EPA anticipates that many early geologic sequestration projects may be sited with EOR projects, this rule relies on CO2 being sent to deep saline formations. Therefore, the EPA does not foresee the commenter's assertion as a potential deterrent to the overall compliance with this rule.
One commenter 10098 stated that once approved, the MRV plan must be maintained under the rule for a duration determined by the EPA, and not the EOR operator. Further, the commenter noted that subpart RR provides that operational changes - even the drilling of a new injection well that had not previously been identified- can start the whole MRV approval process over again. 
Under subpart RR, the EPA has provided clear requirements regarding the length of time for which a GS facility must report and maintain an MRV plan under subpart RR. Under subpart RR facilities may discontinue reporting when they can demonstrate through monitoring and modeling that the injected CO2 is not expected to migrate in the future in a manner likely to result in surface leakage or when the facility has closed pursuant to its Class VI permit, which is sufficient evidence to ensure to the EPA that there is no risk of CO2 leakage to the surface. In setting these requirements, the EPA can ensure it has access to accurate and complete data that represents the amount of CO2 sequestered at a GS site.
An MRV plan may require revision and resubmittal if a material change was made to monitoring and/or operational parameters that was not anticipated in the original plan, if there has been a change in the permit class of the reporter's UIC permit, if the reporter is notified by the EPA of errors in their MRV plan or annual monitoring report, or if the reporter chooses to revise their MRV plan for any other reason. The EPA anticipates that MRV plan resubmissions will be a result of isolated changes to the MRV plan, hence the review and approval process and timeframe will be reflective of that.
Commenter 10095 questioned how the EPA would deal with instances of non-compliance if CO2 complying with subpart RR is comingled in a pipeline with CO2 that is not complying with subpart RR, given that NSPS requires CO2 from an EGU to comply with subpart RR of the mandatory GHGRP. 
If injection occurs offsite, the rule requires captured CO2 to be transferred to a facility that reports in accordance with GHGRP Subpart RR. The hypothetical raised by the commenter (CO2 being transferred in a common pipeline) would not in itself cause non-compliance with the NSPS. 
Liability
Commenters 9381, 9425, and 9666 stated that, to date, the insurance industry has provided only short-term policies that cover a few years of CCS operations with limited options for renewal, potentially making financing of full-scale CCS projects very difficult. According to the commenters, at this time there is no guarantee that there will be sufficient insurance coverage available to manage risks associated with long-term storage of CO2. Commenter 9683 asserted that, although insurance may be available during the operation and post-injection site care phase, commercial risk management instruments are not available for post-closure liabilities. Similarly, Commenters 9780 and 10239 stated that there are unanswered questions regarding long-term-liability and insurance.
In general, the risks associated with geologic sequestration of CO2 are expected to be highest during the operational phase of the project, when the commenter notes that insurance or other financial mechanisms for risk management would likely be available. The risks are then expected to decrease over time. The 2010 Report of the Interagency Task Force on Carbon Capture and Storage discusses how scientific research has concluded that there is substantial evidence that CO2 will remain in place for extended periods if the injection site is chosen properly, injection operations are conducted according to regulations, the site is monitored adequately, and post-injection and closure operations are conducted appropriately.  The EPA's existing regulations for geologic sequestration provide a framework to assure the safety and efficacy of GS, which can help assure lenders considering financing sequestration facilities. Although the commenters focus on the use of insurance to cover long-term liabilities, there are other financial mechanisms that could cover post-closure liabilities. Furthermore, first mover projects are in operation and have been able to obtain needed financing.  
Commenters 9407 and 10052 stated that legal and financial liability associated with geologic sequestration is uncertain, increasing the level of risk associated with implementation of CCS. 
Commenter 9666 stated that the current federal and state regulatory framework continues to create significant uncertainties as to how risks to human health or private property in the event of leakage will be managed, and how liability will be allocated in the event of a leak. Commenters 9197 and 9596 noted that experts and stakeholders have raised significant questions about the long-term feasibility of sequestering large amounts of CO2 underground and who will be liable for upsets or adverse changes to the reservoir of stored CO2. Commenter 10086 stated that many liability issues need to be resolved before CCS can be deemed adequately demonstrated, including (1) who is liable for the captured CO2, (2) when does ownership of and liability for CO2 transfer during the capture, transport, and storage process, and (3) what are the ramifications if the transportation and storage components fail.
Commenter 9666 also stated that repositories located across state lines will introduce jurisdictional questions - particularly as CO2 plumes migrate. According to Commenter 9666, legal precedent addressing such complex subsurface issues does not exist. CO2 -derived liabilities are not fully defined and there is little basis for resolving disputes. The commenter noted that the legal framework which exists has evolved from oil and gas rights and application of EOR may not apply to larger CO2 disposal rates and the timeframe for monitoring CO2 from sequestration covered under the proposal.
The 2010 Report of the Interagency Task Force on Carbon Capture and Storage discusses how present scientific research has concluded that there is substantial evidence that CO2 will remain in place for extended periods if the injection site is chosen properly, injection operations are conducted according to regulations, the site is monitored adequately, and post-injection and closure operations are conducted appropriately. 
At the Federal level, the EPA developed the UIC Program to regulate the underground injection of fluids in a manner that ensures protection of USDWs. Although the regulations for Class VI and Class II injection wells are designed to ensure protection of USDWs from endangerment, the practical effect of these complementary technical requirements is that they also prevent releases of CO2 to the atmosphere. These requirements decrease the likelihood of the events of concern raised by the commenters, including leakages, upsets, adverse changes to the reservoir, and plume migration. Furthermore, EPA's regulations provide required actions for remediation in the event of a leak, ensuring minimal impact on human health and the environment in the surrounding area. The EPA has concluded that the UIC requirements will protect human health and the environment from potential risks associated with CO2 streams and prevent migration of sequestered CO2 both to underground sources of drinking water and to the atmosphere over the long-term.
Commenter 9666 stated CCS presents a unique problem because the underground storage of CO2 might affect the flow and location of groundwater and the disruption of on-site groundwater wells, especially those used by public water systems, might expose the owner of the CCS operations to liability. Commenter 10023 stated that CO2 storage raises numerous permitting and regulatory issues, including liability related to groundwater effects. 
The EPA does not believe that this presents a unique problem or an insurmountable challenge. Similar to other commercial operations that create risks to human health or the environment, geologic sequestration of CO2 will need to be performed in a manner that does not endanger USDWs. The EPA's UIC program, promulgated under the authority of the Safe Drinking Water Act, establishes a risk management framework to protect underground sources of drinking water through requirements ensuring that geologic sequestration wells are appropriately sited, constructed, tested, monitored, and closed. The EPA has concluded that the UIC requirements will protect human health and the environment from potential risks associated with CO2 streams.   
Commenter 8966 stated the realm of liability is particularly broad due to recognition among experts that much more investigation is necessary to understand the effects of carbon sequestration on health and groundwater quality. Yet, the commenter stated, the proposed rule provides no indemnification or transfer-of-title safeguards, nor makes any effort to clarify the bounds of potential liability. The commenter noted that this liability may be a barrier to CCS development. The commenter also stated because of this uncertainty, new facilities implementing CCS would likely be required to install multiple monitoring wells to ensure the integrity of the reservoir. The commenter referenced the AEP Mountaineer Plant, noting that for a commercial-scale CCS system, monitoring costs are likely to be great, corresponding to the greater potential liability associated with storage of millions of tons of CO2 underground. 
Defining the scope of liability or limiting liability through indemnification or transfer-of-title at sequestration facilities is beyond the scope of this rulemaking. The EPA does not believe that lack of a liability limit is a major impediment to near-term deployment of CCS, as stated in the 2010 Report of the Interagency Task Force on Carbon Capture and Storage. With respect to AEP's experience with the Mountaineer demonstration project, notwithstanding difficulties, the company was able to successfully dig wells, and safely inject captured CO2. Moreover, the company indicated it fully expected to be able to do so at full scale and explained how. The EPA notes further that a monitoring program and its associated infrastructure (e.g., monitoring wells) and costs will be dependent on site-specific characteristics, such as CO2 injection rate and volume, geology, the presence of artificial penetrations, among other factors. It is thus not appropriate to generalize from AEP's experience (especially given that the site was a retrofit to an existing source, not initially sited with sequestration in mind), and assume that other sites will require the same number of wells for site characterization or injection. In this regard, we note that the ADM and FutureGen permits for Class VI wells involved far fewer injection wells than AEP references. 
Commenter 9666 stated that assigning responsibility for seismic disruption damages caused by carbon injection may be difficult because of scientific uncertainty and lack of legal precedent. The commenter noted that in the case of natural seismic action leading to future CO2 leakages, assigning liability based on fault may be impossible and lead to difficulty in handling any resulting damages.
EPA's UIC regulations help ensure that CO2 injection activities will not result in significant seismic activity. The permitting process identifies risks and eliminates unacceptable sites prior to injection. The regulations specify criteria for site selection and monitoring that must be met before a site can be considered suitable for CO2 injection. See Preamble section V.N.1.
Commenters 9423, 9426, 10036, and 10618 stated that among the legal and regulatory issues that must be overcome before CCS technology for EGUs can move forward is the current lack of clarity surrounding long-term stewardship and liability for stored CO2. Commenters 9407 and 10952 stated that the proposal and supporting information in the rulemaking docket lacks information that the EPA has considered key legal issues that need resolution, such as long term liability. The commenter references the administration's task force report on CCS projects as previously identified concerns that should be addressed. Similarly, Commenter 10043 stated that the EPA does not know the long-term effects or the risks of storing large amounts of CO2 underground and asserted that the uncertainty associated with this long-term liability creates an immeasurable risk. 
Commenter 9683 cited a 2011 National Coal Council report to the Secretary of Energy that stated that "The management of long-term liability risks is a critical consideration for CCS projects. In terms of supporting the broad deployment of CCS across the coal based generation fleet, uncertainty regarding long-term liability remains a challenge."  Commenter 9396 cited a 2013 Congressional Research Service analysis of the status of CCS, noting "liability, ownership, and long-term stewardship for CO2 sequestered underground are issues that would need to be resolved before CCS is deployed commercially."  The commenter also stated that a key issue in the siting of the FutureGen post combustion capture and storage demonstration project was the extension of liability coverage by the State of Illinois for claims associated with underground storage, however, such liability extensions by state governments appear to be a thing of the past, leaving private entities uncertain as to how to resolve future legal liability. Similarly, Commenter 9597 stated that CCS is challenged by long-term storage concerns regarding indemnification of potential releases of stored materials. 
Commenter 8349 stated U.S. Congress has not yet considered or taken any action on the long term liability issues associated with long term storage of CO2. Commenter 9666 asserted that only four States have developed any additional programs to address long-term care.
The EPA notes that liability issues have not proved impediments to issuing of Class VI permits to date, as illustrated by the various permits issued to Archer Daniels Midland and FutureGen. EOR with anthropogenic CO2 likewise has been conducted successfully for decades without such issues proving an insurmountable obstacle. See also responses immediately above. In addition, there are compliance alternatives to the promulgated standards that do not involve sequestration, so that the standard can be satisfied in any case.
Commenter 10618 stated that the Class VI UIC regulation should not be misconstrued as having addressed all barriers to the geologic sequestration of CO2. The commenter cited a 2014 Congressional Research Service report discussing EPA's authority to protect underground sources of drinking water but not other major issues such as the long-term liability for injected CO2, regulation of potential emissions to the atmosphere, and legal issues if the CO2 plume migrates underground across state boundaries.
The EPA agrees with the commenter that the Class VI UIC regulations did not address all barriers to commercial deployment of geologic sequestration of CO2. For example, to address other barriers, the EPA promulgated GHG Reporting Program Subpart RR and the conditional exclusion from RCRA Subtitle C of CO2 streams that are sequestered in a Class VI well. Specific responses to the three example barriers raised by the commenter are discussed in detail in other responses within this section. 
Commenter 9683 asserted that a key concern for power generators is the applicability of CERCLA to the CO2 generated at their facility and transferred to a third party. Commenter 9683 stated that generators were particularly concerned because CERCLA applies a joint, strict, and several liability scheme. Furthermore, the Commenter noted that in the UIC Class VI proposed rule the presence of materials other than CO2 in CO2 injectate could cause the material to be considered a "hazardous substance," the term, according to the commenter, that triggers liability under CERCLA.    
The EPA acknowledges that although CO2 itself is not listed as a hazardous substance under CERCLA, the CO2 stream injected into a geologic sequestration well could contain a listed hazardous substance or may mobilize substances in the subsurface that could react with ground water to produce listed hazardous substances. Whether such substances may result in CERCLA liability from a GS facility depends entirely on the composition of the specific CO2 stream and the environmental media in which it is stored (e.g., soil or ground water). However, CERCLA exempts from liability under CERCLA section 107, 42 U.S.C. 9607, certain "Federally permitted releases" as defined in CERCLA, 42 U.S.C. 9601 (10), which would include the permitted injectate stream as long as it is injected and behaved in accordance with the permit requirements. 
Other CO2 Transport and Geologic Sequestration Legal and Regulatory Issues
Commenters 6948, 9426, and 10137 stated that legal and regulatory barriers must be addressed to complete the development of CCS and allow for it to be commercially viable. Focusing on the long-term storage aspect of CCS, Commenters 10024 and 10088 stated that many legal and regulatory impediments exist. Commenters 9426 and 10243 asserted that site specific non-technical issues including permitting, public acceptance, property rights of pore space, pipeline siting and construction, interstate transport and safety, liability, and long-term closure issues must all be addressed by the EPA before CCS can be deployed. Commenter 10095 listed several legal issues, including pore-space ownership and long-term storage liability as discussed by the Interagency Task Force on CCS, and provided an example highlighting the gaps, uncertainties, and inconsistencies that may be problematic for projects in states without such laws and for projects that would span multiple states. Commenter 10618 asserted that undeveloped regulatory and legal considerations may alone prohibit the development and adequate demonstration of CCS projects, citing several assessments that recognize developmental challenges related to legal and regulatory issues, and a survey of all 50 states and their readiness to regulate CCS.
Legal and regulatory barriers described by the commenters were thoroughly discussed by the Interagency Task Force on Carbon Capture and Storage, which concluded that such challenges were surmountable. The EPA notes that issues of individual property rights and liabilities will involve site-specific resolution if and when they arise in particular proceedings. These issues have not proved impediments to the Class VI projects pursuing GS, as illustrated by the cases of Archer Daniels Midland and FutureGen. The EPA has responded specifically to each of the legal or regulatory issues raised by the commenters elsewhere in this Section 6.3; see the topics titled Geologic Sequestration Property Rights, CO2 Transport Legal and Regulatory Issues, Safe Drinking Water Act's Underground Injection Control Program and Resource Conservation and Recovery Act, Greenhouse Gas Reporting Program, Liability, and  Other CO2 Transport and Geologic Sequestration Legal and Regulatory Issues.
Commenter 9780 supports EPA's determination that EGU responsibility for captured CO2 ends once the EGU has ensured that the storage or EOR project operator reports under subpart RR, because EGUs should only be responsible for emissions over which they have control.
This rulemaking includes a numeric emissions standard and a requirement that the emitting EGU assure that captured CO2 is managed at an entity subject to the GHG reporting rules. 
Commenter 8022 stated that the proposed rule is flawed because it requires CO2 capture only and does not mandate or regulate sequestration, which the commenter characterized as the only component of CCS that might reduce CO2 emissions generated by a new source. 
As already noted, this rulemaking includes a numeric emissions standard and a requirement that the emitting EGU assure that captured CO2 is managed at an entity subject to the GHG reporting rules. See also preamble section V.N. 
Commenter 10083 stated that there is no precedent for regulating activity beyond the facility generating CO2, nor are the facilities at which sequestration is likely to occur subject to this rule. The commenter noted that it is significant that parties (e.g., CO2 sequestration facility operators), who are responsible for handling the CO2 after it has been turned over by the CO2 generator, are not subject to the rule because it is not practical or practicable for the generator to account for the CO2 after the generator has turned it over to a third party.
The final standard of performance requires the EGU to transfer the captured CO2 to an entity reporting under subpart RR where sequestration is part of the compliance path.
Commenters 9407, 9600 and 10097 asserted that although the proposal does not seek to regulate or address offsite facilities where transport and storage would take place, these components are required to augment the BSER or otherwise captured CO2 could be subsequently emitted offsite. 
Similarly, Commenter 9201 stated that the EPA failed to properly account for the entirety of the system by focusing on carbon capture and omitting an account of the transportation and storage components of CCS. Therefore, the commenter asserted that EPA's proposed NSPS is incomplete and cannot be considered BSER. Unless the EPA considers transportation and storage, the commenter stated that the NSPS is an arbitrary and capricious application of CAA section 111(b).
As already noted, this rulemaking includes a numeric emissions standard and a requirement that the emitting EGU assure that captured CO2 is managed at an entity subject to the GHG reporting rules. See also preamble section V.N.
Commenter 9683 stated that the proposed rule makes possible the circumstance that a coal-fired power plant that must run for an area to maintain compliance with electric reliability requirements, which are binding and enforceable by FERC under the Federal Power Act, could be forced to violate the proposed rule if it was unable to sequester CO2 due to a leak at the only available geologic sequestration facility. Commenter 9683 notes that the House Committee on Energy & Commerce is considering legislation that could address this issue, but the Commenter notes that the legislation under consideration leaves the generating facilities at risk. The commenter stated that the proposed rule would not encourage CCS unless other laws and regulations are concurrently amended to resolve this potential situation.  
Commenter 10095 stated that if third parties are willing to accept CO2 from CCS operations at EGUs, power generators will need to enter into a contract with a third party that would receive the CO2 and take responsibility for ensuring continuous storage, and under such arrangements, the EGU would be dependent on a third party for both operations and compliance. The commenter added that if the third party cannot or will not accept the CO2, the EGU would likely be forced to shut down, and thus, the risk of contract breach could jeopardize the ability of the EGU to meet electricity demand. According to the commenter the lack of an established mechanism for these types of legal issues is further evidence of the complexities of relying on CCS when electricity production is at stake.

Commenter 9197 stated the proposed rule does not adequately consider the potential for downstream outages to impact EGUs' ability to consistently meet the proposed NSPS-an issue that would not affect the demonstration projects or industrial facilities on which the EPA relies because these facilities can simply shut down when sequestration is not available. According to the commenter, the EPA has not addressed the possibility that a CO2 pipeline, EOR operator, or geologic sequestration well operator could experience technical or other difficulties that would prevent these third parties from taking a regulated EGU's CO2.
Commenter 10095 described the Final Determination of Compliance for HECA's proposed polygen facility, which specifies HECA's proposed GHG BACT analysis for its CO2 Recovery and Vent System that includes the ability to vent captured CO2 during periods when compression, transportation, or the delivery system is unavailable due to cold gasification block startup, CO2 compressor or pipeline unplanned outages, or third party CO2 off-take issues. The commenter urged EPA to consider how these types of risks can impact compliance with the proposed rule.  
The EPA believes that the rule provides sufficient flexibility to avoid the compliance issues described by the commenters. In the event that there is a malfunction condition, the EGU would not be immediately required to shut down or be required to shut down within a certain specified period of time. EGUs that are unable to export their captured CO2 emissions could continue to operate without capturing their CO2 emissions in accordance with the terms of their operating permits and in accordance with numerical CO2 emissions limit to which the facility is subject. 
Commenter 10083 discussed the difficulties associated with deploying CCS in the West, such as complexity and time to obtain permits, complexity and costs of assessing storage suitability, and costs of covering liability risks related to transport and injection.
The EPA has responded to the issue of permits in the Section 6.3 topic titled Safe Drinking Water Act's Underground Injection Control (UIC) Program and Resource Conservation and Recovery Act, geologic sequestration assessment in the Section 6.3 topic titled Geologic Sequestration, and liability in the Section 6.3 topic titled Liability. The EPA notes that issues of liability will involve site-specific resolution if and when they arise in particular proceedings. 
Commenter 9731 stated that the commenter opposes any efforts that would make CO2-EOR more costly or burdened by an unworkable regulatory framework.
The EPA believes that the Underground Injection Control (UIC) Class VI rule and Subpart RR of the GHG reporting rules do not place an excessive burden on EOR operators. The existing framework offers an integrated and complementary set of regulations that ensure an appropriate level of verification and accounting of CO2. 
Citing a Congressional Research Service report, Commenter 9423 stated that legal and regulatory uncertainties may make broad community acceptance of CCS a challenge.
According to commenter 9666, public opposition to permitting CO2 storage sites due to safety related concerns has occurred recently in Europe. The commenter concluded that public acceptance can be a major issue at any proposed site. 
Public awareness and support have been widely recognized as critical components in the development of new energy infrastructure, including CCS deployment. Efforts have been made to design strategies for successful outreach to the public. For example, under the DOE Regional Carbon Sequestration Partnerships, DOE has been engaging with local communities to educate and inform them about planned pilot and demonstration projects in their areas. DOE's Best Practices for Public Outreach and Education for Carbon Storage Projects presents lessons learned through the planning and implementation of CCS projects, as well as best practices for community engagement. 
Commenter 9426 stated that without a strong price signal for CO2, only public funding will possibly advance CCS and funding is highly uncertain. 
As discussed in the proposal, the 2010 Interagency Task Force on CCS report recognized that, as an alternative to a strong price signal for CO2, a regulatory framework that promoted CCS was a mechanism for encouraging the commercial deployment of CCS (79 FR 1480). This rule is an important component in developing that framework, which could, even in the absence of a strong price signal for CO2, advance CCS. 
Commenter 8949 stated that an environmental and cost impact assessment of the development and implementation of a CCS regulatory structure, either at the federal or state level, should be included in the agency's decision making process.
In its regulatory impact analysis, the EPA determined that identifying partial CCS as the BSER for coal-fired power plants would not have adverse impacts on the power sector, national electricity prices, or the energy sector. Furthermore, this rule relies on existing regulatory frameworks under the UIC Program and GHG Reporting Program. 
Commenter 10618 asserted that the EPA should have listed a new source category that includes all of the affected facilities necessary to effectively control CO2 emissions rather than relying on the existing source category described under Subpart Da. The commenter stated that EPA's assertion that it is regulating the same source categories currently regulated under Subpart Da is inaccurate because those sources do not include the CO2 transport and sequestration or end use processes necessary to segregate the captured CO2 emissions from the atmosphere. 
Furthermore, Commenter 10618 disagreed with EPA's reliance on the GHG Reporting Program to track the captured CO2 that is geologically sequestered as a means of avoiding redefining the source category. The Commenter stated that without an effective method to establish an enforceable standard for sequestration, such as requirements for successful sequestration and a better reporting tool, EPA's proposal to require capture and reporting of CO2 emissions is ineffective and arbitrary.
 The EPA disagrees with the commenter's assertion that it is not regulating the same source categories currently regulated under subpart Da because those sources do not include the CO2 transport and sequestration or end use processes necessary to segregate the captured CO2 emissions from the atmosphere. The subpart Da requirements for criteria pollutants similarly do not include requirements for transportation and storage of particulate matter, SO2 scrubber residuals. We have described separate requirements for transportation and storage of captured CO2 in the preamble section V.N. and elsewhere in this response to comments document. The EPA also disagrees with the commenter's assertion that there is no effective method to establish an enforceable standard for sequestration. Separate regulatory requirements exist under SDWA's UIC program that regulate the entities involved in geologic sequestration of carbon dioxide. And the current rule requires that the emitting EGU assure that captured CO2 is managed by an entity subject to the GHG reporting rules. The primary intent of the requirement that the emitting EGU make this assurance is to account for captured CO2 that is geologically sequestered. See the Section 6.3 topic titled Greenhouse Gas Reporting Program and preamble section V.N.2 for discussion related to the GHG Reporting Program.
Commenter 9407 stated that there are geographic locations where insufficient EOR and deep well sequestration infrastructure prohibits NSPS compliance, but where coal-fired plants are required to satisfy local needs. The commenter asserted that the proposal is unlawful because the requirements prohibit source locations where CCS infrastructure is unavailable, despite the location's need for a reliable grid source or economic development.
A few states do not have geologic conditions suitable for GS, or may not be located in proximity to these areas. Where GS capacity is unavailable, electricity demand in those areas can be served by coal-fired power plants built in neighboring areas with GS. For other of those areas, coal-fired power plants are either not being built due to state law restrictions, or other available compliance alternatives exist allowing a new coal-fired power plant meeting the promulgated NSPS to be sited. The EPA has also noted compliance alternatives that will allow affected new facilities to meet the final standard without the use of CCS technologies  -  notably by using natural gas co-firing.
Commenter 8743 argued that EPA's description of legal precedent regarding the absence of a requirement under CAA section 111 that a New Source Performance Standard be able to be met by every new source in the source category misconstrues legislative intent. Commenter 8743 states that the legal precedent that the EPA relies on, which relates to attaining National Ambient Air Quality Standards, to justify this assertion is misplaced and cannot be properly applied to the emissions standards for CO2 for which no ambient air quality standard or distinct air quality related value exists. Commenter 8743 concludes that the EPA has overstepped by disadvantaging large geographical areas that are technically and economically precluded from CCS, which the commenter believes the EPA acknowledges by trying to argue that there is no requirement that a New Source Performance Standard be able to be met by every new source in the source category.
The EPA believes that a new steam generating affected source could meet the promulgated standard and be located anywhere in the country. There is available sequestration capacity in most areas of the country, and there are alternative ways a new EGU could meet the standard, not involving sequestration, should a new source decide to locate in an area where these sequestration opportunities are unavailable. See Portland Cement Ass'n v. EPA, 665 F. 3d 177, 191 (D.C. Cir. 2011), holding that the EPA could adopt section 111 standards of performance based on the performance of a kiln type that kilns of older design would have great difficulty satisfying, since among other things, there were alternative methods of compliance available should a new kiln of this older design be built. The court also noted that it was highly unlikely that such a new kiln would ever be constructed and that the EPA could consider this in adopting a standard of performance reflecting a different type of kiln design. Similarly here, there is significant doubt that a new steam generating unit would be sited in one of the few areas without ready access to sequestration or EOR opportunities (and commenters have supplied no information indicating that such a possibility actually exists). Finally, the promulgated standard of performance can be met without capturing CO2 or sequestering it, using alternative means of control which have no associated geographical constraints. 
6.3.6 CCS Is/Is Not BSER
Commenters 7977, 8032, 8501, 8949, 8973, 9194, 9197, 9318 9422, 9505, 9590, 9596, 9600, 9678, 9683, 10033, 10036, 10050, 10051, 10087, 10618 disagreed with the choice of partial CCS as BSER. 
Commenters 8973 and 9318 strongly objected to EPA's consideration of "partial CCS" as BSER for new coal plants and new integrated coal gasification/combined cycle (IGCC) plants, as the same technological immaturity, accessibility, and transportation arguments (used for full CCS) can certainly be made for these units. In addition, the commenter stated that the cost-effectiveness of partial CCS--particularly if involving permanent geologic sequestration and not temporary enhanced oil recovery (EOR)--is entirely unproven and not commercially available, regardless of type.   
Commenters 7977, 8501, 9197, 9683, 9677, 10033, 10050 10137, noted that CCS was not adequately demonstrated, citing feasibility and costs as additional problems. Commenter 9678 recommended that the EPA adopt standards that are achievable using state-of-the-art technologies. Commenter 10134 stated that the EPA did not properly evaluate the two options of highly efficient generation technologies and efficiency measures in comparison to CCS. Commenter 9194 noted the need for vendor performance guarantees. Commenter 10134 stated that the EPA did not properly evaluate the two options of highly efficient generation technologies and efficiency measures in comparison to CCS. Commenters 9422, 9596, 10051 recommended that the EPA reconsider CCS as BSER, and issue a new proposed rule. 
Commenter 7977 stated that the selection of CCS as BSER for coal-fired EGUs is arbitrary and capricious.
Commenter 10089 provided general support for the proposed rule as a step in the right direction to reduce the greenhouse gas emissions of the electric power sector, suggested that CCS may not be BSER, given the cost impacts.  
First, partial post-combustion CCS is demonstrated at commercial scale, and has been operated successfully at the Boundary Dam facility since October 2014.  Permanent sequestration in Class VI deepwells is likewise demonstrated.  See preamble section V.N.  Vendors are providing guarantees for CCS.  See preamble section V.F. The EPA carefully considered the issue of compliance costs, and based its cost estimates on updated costs reflecting recent vendor quotes and performance information and application of the Shell Cansolv amine scrubbing process that is currently being used at the Boundary Dam Unit #3 project.  Based on this most up-to-date information, the EPA adjusted the final standard of performance to 1,400 lb CO2/MWh from the 1,100 lb CO2/MWh proposed.  The EPA's analysis of why the cost of this standard are reasonable under section 111 (a) is found in sections V.H and I. of the preamble to the final rule.
Commenters 4814, 7977, 9426, 9590, 10043, 10047, 10135, 10466, 10929 stated that CCS is developing but is not is not technologically or economically viable at this time, and thus should not be a basis for a standard. 
Commenter 4814 summarized work developing CCS technologies. The commenter noted that these projects are bringing CCS closer to economic and commercial viability over the next decade. 
 These comments were unduly negative.  CCS is clearly technically viable as it is being implemented now. For example, the Boundary Dam Unit #3 facility is operating successfully at full scale. The EPA has also determined that a new unit can utilize partial CCS to meet the final standard of performance at reasonable cost. The EPA has also issued six Class VI permits for underground injection.  See generally preamble section V.
Commenter 9678 stated concern that EPA's determination that partial CCS is BSER for coal and IGCC units is flawed and will not survive judicial review. According to the commenter, EPA has not shown that CCS for coal units is adequately demonstrated and relies on arbitrary presumptions in reaching its conclusion and these inadequacies in EPA's analysis may make the proposed standard vulnerable to remand on judicial review, which would delay the promulgation of the rule and the associated benefits of having a final rule in place. To ensure that the rule is legally defensible, the commenter recommended that EPA establish a standard for coal and IGCC units that is not based on CCS, but is instead based on other adequately demonstrated emissions control technologies.   
According to commenter 9505, the agency's BSER determination will not survive judicial review, as it is contrary to the statutory text and a wealth of evidence, and is not supported by reasoned decision-making. The commenter stated section 111 of the Clean Air Act does not permit EPA to force an experimental technology through an NSPS, although this is precisely what the proposal attempts to do. Accordingly, the commenter recommended EPA reverse its determination that CCS is the BSER for the proposed NSPS.
Partial CCS is an adequately demonstrated control technology.  See preamble section V.D.  The EPA does not believe that basing a standard on performance of "capture and CO2 compression technologies [that] have commercial operating experience with demonstrated ability for high reliability" is arbitrary and capricious.  See NETL (2015) at p. 36.  See also statement of Alstom senior Vice President for Power and Environment Policies Joan MacNaughton (August 4, 2011): "The technology works."   See: www.alstom.com/Global/US/Resources/Documents/Press%20Releases/PR_JMacN_CCSbriefing_FINAL.pdf
Commenters 9725, 10050 stated that the EPA has used estimates from hypothetical IGCC and SCPC units with CCS, not actual operating experience. The commenters stated that the EPA's approach is unprecedented, unlawful and a stunning departure from over 40 years of regulatory history that relies upon actual emission data from representative units operating with adequately demonstrated technology. 
Commenter 10039 stated that the EPA cannot attribute all new coal fired generation as unequivocally base load for purposes of justifying CCS as technically feasible for this source, and not include intermediate (load following) and peaking units. 
 Partial CCS is demonstrated at commercial scale in this industry (Boundary Dam, in particular), and (for pre-combustion, should this be pursued) in a related, transferrable context (Dakota Gasification).  These are not hypothetical facilities.  EPA's cost estimates reflect the most up-to-date information available: recent vendor quotes and performance information and application of the Shell Cansolv amine scrubbing process that is currently being used at the Boundary Dam Unit #3 project.  The EPA does not unequivocally attribute all new coal-fired generation unequivocally as base load units for the purpose of justifying CCS as technically feasible. The EPA does believe, given current and projected market conditions, that a project developer would be most likely to build a new unit for the purposes of providing high capacity factor, base load generation. Still, the EPA has shown that the promulgated standard is achievable for an affected EGU using the BSER under a range of operating conditions and that the 12-month average is indicative of, and accommodating for, variable operations (and excursions).  In confirmation, as shown in the Technical Support Document, actual 12-month averages of two recent highly efficient SCPC are close to those projected here.  
.  See preamble section V.J and New Steam Achievability Technical Memorandum (July 2015).
Commenter 10618 stated that EPA's position on the feasibility and adequate demonstration of CCS in the proposed rule are in many ways contradictory to its assessment of the technology in the PSD and Title V Permitting Guidance for Greenhouse Gases document. The commenter provided numerous excerpts from the document in which EPA suggests that CCS be considered in a BACT analysis and that CCS will likely not apply because it is not technically feasible and/or because it is not cost-effective - both reasons also support the conclusion that CCS has not been adequately demonstrated. The commenter concluded if the level of development is insufficient to generally apply CCS as BACT, it is also insufficient to support the determination that CCS is the BSER.
   With regard to the commenters who stated that a BSER for EGUs that is based on partial CCS would be inconsistent with BACT determinations in previous GHG PSD permits, it is important to recognize that a BACT determination is a case-by-case analysis and that technological capabilities and costs evolve over time. Thus, language from an historic guidance document, providing context for case-by-case application rather than for national rulemaking, hardly has determinative effect here.  Moreover, the commenters quote selectively from that guidance.  In fact, the 2011 GHG Permitting Guidance states that "although CCS is not in widespread use at this time, EPA generally considers CCS to be an `available' add-on pollution control technology for facilities emitting CO2 in large amounts and industrial facilities with high-purity CO2 streams." GHG Permitting Guidance at 35. The Guidance goes on to note that CCS may not be available at modified sources, or in other specific circumstances. Id. at 36 ("While CCS is a promising technology, EPA does not believe that at this time CCS will be a technically feasible BACT option in certain cases....EPA recognizes the significant logistical hurdles that the installation and operation of a CCS system presents and that sets it apart from other add-on control that are typically used ... Logistical hurdles for CCS may include obtaining contracts for offsite land acquisition ..., the need for funding..., timing of available transportation infrastructure, and developing a site for secure long term storage. Not every source has the resources to overcome the offsite logistical barriers necessary to apply CCS technology to its operations, and smaller sources will likely be more constrained in this regard"); id. at 42-3 (noting that CCS may be expensive in individual instances and thus eliminated as a control option for that reason under step 4 of the BACT analysis, noting further that revenues from EOR may offset other costs).  See also UARG v. EPA, 134 S.Ct. 2427, 2448 (2014) (noting that EPA's GHG Permitting Guidance states that carbon capture is reasonably comparable to more traditional, end-of-stack BACT technologies, and that petitioners do not dispute that).  See generally, preamble section XII.C.
As explained at preamble section V.I.5, in determining that partial CCS is BSER for new fossil fuel steam electric plants, EPA has carefully considered the issue of logistics (including cost estimates for land acquisition, transportation, and sequestration) and costs generally. Nor would new plants face the same types of constraints as modified or reconstructed sources in a BACT determination, since a new source has more leeway in choosing where to site. Moreover, the GHG Permitting Guidance considered BACT determinations for all types of sources, not just those for which EPA has determined in this rule that partial CCS is the best system of emission reduction, and the concerns voiced in the Guidance thus must be considered in that broader context.
Commenter 10618 stated that EPA's evaluation of each of the four factors in the BSER determination is flawed due to: 
   * a series of premature, inaccurate conclusions on the development, demonstration, and performance of advanced generation and CCS technologies; 
      Response: The EPA disagrees.  See preamble sections V.D and E.  See also NETL (2015) p. 36 characterizing CCS as a technology with "commercial operating experience with demonstrated ability for high reliability".
   * minimal consideration and an abrupt dismissal of widely-acknowledged barriers to CCS becoming a technically feasible and adequately demonstrated control option; 
      Response:  See previous response.
   * an inadequate consideration of the lessons learned from actual projects and the conclusions reached by major public and private assessments of CCS development; 
      Response: The "major public and private assessments" that were mentioned largely referred to full, rather than partial CCS (see preamble section V.F).  The EPA has carefully considered lessons learned.  It is for this reason that the agency sought out and utilized the most recent cost information on post-combustion CCS, basing its cost estimates on those from vendors supplying the technology in commercial use at the Boundary Dam #3 facility.  See also preamble section V.I.2. indicating consistency of NETL cost estimates with those of other leading experts in the field, as well as with those of recent industry cost estimates. 
   * an inconsistent use of criteria to perform the BSER analyses and to inform the Administrator's judgment within this proposal and compared to other rulemakings; 
      Response:  See Portland Cement v. Ruckelshaus, 486 F. 2d at 389 (NSPS are judged on their own merits, not by comparison with NSPS established by EPA for other source categories).
   * an inadequate evaluation of the impacts to all sources within the source category; and use of underlying energy policy goals that do not allow for an objective evaluation of BSER in accordance with the Clean Air Act. 
      Response: the commenter is mistaken.  The NSPS is justified, and may only be justified, by the statutory criteria set out in section 111 (a).
Commenter 9664 stated EPA correctly bases the level of the proposed standard for new subpart Da fossil fuel-fired boilers and IGCCs on the application of partial carbon capture and sequestration as the Best System of Emission Reduction. According to the commenter, EPA's careful consideration of the cost, energy, and non-air quality, environmental impacts of CCS satisfy the statutory requirements for the Agency to balance these required statutory factors in designating a CAA section 111 BSER.  
Commenter 101008 stated that EPA has given sufficient consideration to the statutory factors in making its BSER determination. The commenter referenced several court decisions to support their argument. The commenter noted that in determining that partial CCS is BSER for coal-fired power plants, EPA appropriately weighed the efficacy of achieving emission reductions as its prime consideration. The commenter added that in its BSER analysis, EPA ruled out highly efficient coal-fired generation without CCS in part because that technology alone would not result in significant reductions of CO2. According to the commenter, CCS is by far the most effective process available for reducing carbon pollution from new coal-fired power plants, and this factor thus weighs highly in favor of EPA's BSER determination. 
Commenter 9514 stated EPA is justified in setting CCS as the BSER for new fossil fuel-fired boilers and IGCCs. According to the commenter, CCS provides significant emissions reductions and co-benefits, CCS systems are available for fossil fuel boilers and IGCCs and the technologies have been utilized in industrial applications for decades, and the costs are reasonable and can be accommodated by industry. 
Commenters 8020, 8939, and 8967 stated that using partial CCS strikes a good balance between economics and the environment, and that the technology will help to prevent significant amounts of C02 from being emitted into the atmosphere.
 
The EPA largely agrees with these comments, although the final standard of performance strikes a somewhat different balance than struck in the proposal, albeit using the same methodology.
Commenters 8501, 9194, 9201, 9426, 9671, 10618 disagreed with the difference in the way that CCS was or was not determined to be BSER for subpart Da and subpart KKKK units. 
Commenters 9194, 9201, 9426, 9671, 10618, stated that CCS is currently inappropriate as BSER for both gas-fired and coal-fired EGUs.
Commenters 8995, 9194, 9201, 9426, 9671, 10039, 10618, 10876 stated that many of the reasons the EPA cites for rejecting full or partial CCS technology as BSER for natural gas-fired stationary combustion turbines are equally applicable to IGCC and fossil fuel-fired boilers, yet the Agency reaches a different conclusion for the two sources. Commenter 10039 noted that the EPA errs by saying CCS is feasible at coal fired units regardless of dispatch order despite its acknowledgement that load following may (and likely will) adversely affect the efficiency and reliability of a unit with carbon capture systems.
Commenter 8501 stated that there is little evidence to support a distinction between coal-based generation to NGCT for the technical challenges and costs for CCS, and stated that the EPA fails to distinguish why CCS is not BSER for a natural gas-fired plant.
Commenter 10618 discussed the differences in discussions of CCS as applied to subpart Da and subpart KKKK units, noting that there was very limited discussion about broader industrial CCS experience in the BSER analysis for NGCTs, but there was for coal-based generation. The commenter stated that the literature review was unevenly applied to the two source categories. The commenter stated that large-scale demonstration projects have not yet occurred for either of the two source categories.
Commenter 10618 stated that although the Econamine capture system that has been used by NGCC processes has yet to be demonstrated on a single coal-based generating unit, EPA assumes in its cost analysis for the BSER that new pulverized coal units with CCS will be equipped with the Econamine system.
Commenter 9201stated that the way the EPA has weighed the factors to determine that CCS is BSER is unreasoned and an abuse of discretion. 
Commenter 10017 stated that there is a significant difference in the reductions required in CO2 emissions between subparts Da and KKKK.
A discussion of the EPA's final rationale regarding CCS as a component of BSER for combustion turbines is provided in the final preamble at section IX.C.4.
Commenter 9600 stated that the EPA has not documented its extrapolation of technology performance in other industries to that for coal-based generation. The commenter stated that as a result, there is 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.
 First, post-combustion CCS is demonstrated at commercial scale at a source (Boundary Dam) that is a full-scale, fully integrated coal-fired EGU.  No inter-industry transfer of technology is at issue.  Pre-combustion CCS (should a source consider that alternative compliance pathway) is likewise demonstrated at full commercial scale.  See preamble section V.E.2.a for why this same technology and performance is transferable to an IGCC generating electricity. 
Commenter 10618 stated that the EPA's consideration of emission reductions is flawed because the agency uses ambiguous criteria to determine emission reductions. The commenter stated that the EPA fails to fully consider the magnitude of emission reductions that may be achieved from highly efficient processes alone, and utilizes loose, qualitative statements on CCS related emission reductions. The commenter stated that the EPA provides no information on the baseline used to assess emission reductions and provides no information on the types of criteria considered in determining "significant" and "meaningful."
 See preamble section V.K quantifying the difference between a highly efficient SCPC and a highly efficient SCPC meeting the standard of performance based on the BSER.  See also RIA chapter 5 quantifying the benefits of that difference in performance and showing that those benefits exceed regulatory costs under a range of assumptions.
Commenter 4710 stated that the EPA has chosen to disregard DOE and OMB statements and documents that do not support CCS readiness, economics or feasibility.
 Those statements referred to full CCS, not partial CCS.  DOE's latest statement regarding CCS reliability ("demonstrated ability for high reliability") is found at p. 36 of its July 2015 NETL study.
Commenters 9195, 9201, 10036, 10239, 10395 noted that the EPA has changed BSER in this proposal from the determination of BSER in the 2012 proposal. 
Commenters 10239, 10395 stated that the EPA has provided no rational explanation for the change.
Commenter 9195 asked for the basis for the change. 
Commenter 10239 stated that nothing has changed since 2012 to make CCS BSER, and noted that the EPA does not cite any new information or new projects in this rulemaking that were not available to it in the 2012 proposed rule. The commenter stated that there is no rational basis for the EPA to reverse course and conclude that CCS is adequately demonstrated and is BSER for coal-fired EGUs without some new data or evidence of changed conditions. The commenter stated that such a conclusion is fundamentally at odds with the most basic principle of administrative law that, when an agency changes its position, it must supply a reasoned analysis for doing so.
 The EPA indicated in its 2012 proposal that CCS was a feasible technology option for new power plants in the original proposal, so much of this comment rests on a mistaken premise.  See 77 FR at 22414-417.  The agency withdrew the 2012 proposal largely in response to industry comment that future new fossil-fuel fired steam electric capacity (i.e. coal-fired) was possible and therefore that separate standards for utility boilers and IGCC, on the one hand, and NGCC units on the other, was warranted. 79 FR at 1432. The EPA did not find that CCS was the BSER in that 2012 proposal because the proposed standards were for a combined category that included both NGCC units and steam generating units. In the current action, the EPA proposed and is finalizing separate standards of performance for both stationary combustion turbines and steam generating units, with separate BSERs for each. With respect to CCS, among the developments that have occurred since the 2012 proposal are the successful operation at commercial scale of post-combustion CCS and issuance of six permits for deep well injection of captured CO2, as well as more recent cost information reflecting operating experience.  The EPA has fully articulated its basis for the final standard reflecting an adequately demonstrated BSER, and this extended discussion amply indicates why EPA is adopting a different assessment than found in the 2012 proposal.  See preamble section V.
Commenters 9001, 9428, 9595, 9601, 10238, 10358, 10387, 10501 stated that although CCS holds promise for the future, the technology for electric generation today remains both costly and unproven.
 See preamble section V.
Commenters 10083, 10606 asked that regional impediments to CCS be considered, particularly the lack of good CO2 sequestration sites.
 See preamble section V.M.
Cost
Commenter 9666 stated that EPA's attempt to calculate the cost of CCS is inadequate, as there are no commercial units operating to provide experience from which to validate designs that were developed for small-scale. The commenter noted that although no commercial-scale CCS project has been completed at a coal-fired or IGCC unit, and thus no reliable indicator of the full cost of CCS at this scale exists, some cost information is available for the Kemper County IGCC unit, which is scheduled for completion in 2015. According to the commenter, during the course of Kemper County's construction, the project's costs have escalated from an estimated $2.4 billion in 2010 to $5.5 billion at the latest estimate in 2014, representing several successive cost increases. The commenter recommended  a more robust approach for determining casts would be to solicit price quotes for power generation equipment in the present economic and fuel price environment; employing several sources of such data (e.g., not a single proprietary database); and conducting a rigorous peer review.
Commenter 9666 also stated that due in part to a lack of relevant operating experience, CCS remains exorbitantly costly to install and operate. The stated the uncertainty surrounding the actual cost of any IGCC project incorporating CCS presents another hurdle to financing and constructing these units. According to the commenter, developers will find it difficult to obtain financing due to their inability to predict the actual cost of any IGCC project involving CCS. The commenter stated that the costs of CCS are so high and uncertain that the proposed IGCC standard will effectively prohibit the construction of any new Subpart Da IGCC unit. The commenter also stated in addition, at all of the commercial-scale projects that have been proposed, the CCS system is justified in the fundamental business case for the project because the separated CO2 stream will be used directly by another industrial process, such as enhanced oil and gas recovery. According to the commenter, such opportunities are limited and only a few early projects would be able to take advantage of these opportunities.
Commenter 9033 also stated that it is unaware that any supplier of this technology is ready or able to offer commercial guarantees for such full-scale systems of carbon capture. The commenter noted that all utility generators require extensive performance guarantees and warranties which cannot be offered without proper demonstration at scale. According to the commenter, all the projects that form a basis for the EPA rule would require extensive revenue sources from niche market opportunities like EOR and chemicals and large federal subsidies, none would stand alone on a common commercial basis which would in turn mean that no new coal burning plant could be permitted or financed. Hence the commenter noted it is unlikely that such systems will be available prior to the EPA obligatory eight-year review of this proposed NSPS.
Commenter 9486 stated they are not certain that an accurate costing estimate can be performed at this time given the state of CCS technology and lack of full scale implementation at a coal-fired power plant. The commenter also expressed concerns with U.S. EPA's reasoning that the costs for CCS will decrease as the technology advances. As U.S. EPA stated, the current economics dictate that very few coal-fired power plants will be constructed even without the requirement to add CCS. According to the commenter, if there is no market for CCS technologies at coal power plants, the cost will remain high for CCS technologies. The commenter concluded that the unproven full scale costing of CCS makes it extremely difficult, if not impossible, to accurately evaluate and determine the cost impacts of this rule.
Commenter 8966 stated the costs of CCS technology are difficult to quantify, in part because there are no examples of currently operating commercial-scale coal-fired power plants equipped with CCS. The commenter stated however, AEP's experience with installation of a validation-scale chilled ammonia-based CCS system at its Mountaineer Plant is particularly valuable in gaining insight into the potentially massive costs of a commercial-scale CCS system.
Commenter 10100 stated there are no commercial ventures in the United States that capture, transport, and inject industrial-scale quantities of CO2 solely for the purposes of carbon sequestration. The commenter also stated that commercial-scale CCS demonstration projects are nascent, and of the five CCS projects that DOE has supported with significant financial incentives, only one appears to be moving forward. Commenter 10391 stated that although no full-scale operational CCS system at a coal-fueled power plant exists in the U.S., EPA conveniently excluded "first of its kind" costs from its rulemaking consideration. According to the commenter, when evaluating increased costs and risks, pilot CCS and experimental projects are largely irrelevant because these projects have been government subsidized. Similarly, EPA likely undervalues regulatory hurdles and risks and overvalues potential revenues from CO2 waste stream sales for possible use in enhanced oil recovery (EOR) fields.
Commenter 9427 stated that instead of focusing on comparative costs for levels of emissions limitations within the Subpart Da source category for justifying a standard level, EPA inappropriately focused on comparing the cost of coal-fired steam generating units using "partial CCS" with costs for another source category or with costs for electricity generation with technologies that are not even regulated under Section 111 to show that coal with partial CCS is "competitive" with other technologies. According to the commenter, because the construction is not complete and operation has not yet begun on actual projects employing CCS cited by EPA in its proposal, the actual costs of projects are completely unknown at this time. Commenter 9505 stated none of the pilot projects described in the proposal actively capture CO2 from plant exhausts or store CO2 in the ground, and because CCS is not operational at these pilot projects, there is no data about continuous operations, commercial scalability, or costs. Hence, the commenter stated, these experimental projects cannot form the basis for a finding that the technology is available.
Commenter 9666 also stated the cost of CCS at smaller demonstration facilities cannot be reliably scaled up to inform predictions about the cost of CCS at commercial units. Indeed, all that is known about the cost of CCS is that it is exorbitantly high. The commenter also stated EPA's estimate of the baseline cost of coal fired power generation is incorrect, which also skews its assessment of the proposed standard's relative cost.
Commenter 10043 stated that because CCS is neither commercially available nor proven at the appropriate scale or size needed by the four pilot projects, the EPA's cost analysis, upon which the EPA based its conclusion that CCS technology has been adequately demonstrated, is highly questionable. The commenter also noted that EPA is contradictory in foretelling reductions in the capital costs of CCS because of research, development and implementation of the technology while also estimating that no new coal-fired power plants will be constructed
  Commenter 9666 refers to the cost overruns at the Kemper facility.  The Kemper site undoubtedly experienced massive cost overruns, but did so for reasons that are not generally applicable, and which cannot legitimately be used as a basis for assessing costs for other facilities.  For example, as documented in detail in the April 15, 2014 Independent Monitor's Prudency Evaluation Report ("Independent Monitor's Prudency Evaluation Report for the Kemper County IGCC Project", prepared by Burns and Roe Enterprises for Mississippi Public Utility Commission staff), at least partly in an effort to obtain an annual tax credit, the project team chose to adopt "a compressed schedule which led to a just-in-time approach to engineering, design, procurement and construction...".  Report, p. 14.  In essence, basic engineering decisions were not made in advance of construction: "By committing to this approach, engineering and design changes which are a normal result of detailed engineering and design were occurring at the same time as, rather than ahead of, construction activities." Id. p. 6.  In BREI's opinion, "several areas were not adequately addressed, executed or implemented in a reasonable manner."  These areas include: project planning/scheduling. The development of a risk management program with sufficient detail and look ahead time horizon, the late development of the original integrated EPC schedule with adequate resource loading, commodity cost estimating and monitoring (which controlled the project estimated cost to the certification estimate of $2.4 billion until the original low contingency was depleted), and the implementation of SCS's and MPCo's internal procedures and policies (or failure to implement certain policies and procedures), and other areas discussed in this report.  All of the areas listed above which were not addressed, executed or implemented in a reasonable manner raise serious doubt to BREI as to the appropriateness and reasonableness of those actions taken by MPCo in implementing this Protect." Report, pp. 14-15. Moreover, the Report indicates all issues with cost related to the gasification unit, not to carbon capture and sequestration.  
Commenter 9666 also urges that costs reflect CCS used at full commercial scale, and that costs should not be extrapolated from small scale designs.  Commenters 10391, 10043 and 9505 made a similar comment.  The EPA has carefully considered comments that costs should be assessed reflecting technologies being used at full commercial scale.  For the final standard, the EPA made particular use of the most recent NETL cost estimates for post-combustion CCS, which reflect up-to-date vendor quotes and incorporate the post-combustion capture technology  -  the Shell Cansolv amine-based process  -  that is being utilized at the Boundary Dam Unit #3 facility.
The same commenter indicates the substantial uncertainty for IGCC projects incorporating CCS. The BSER for the final rule is a highly efficient SCPC using partial CCS, not IGCC.  See preamble section V.H. for EPA's cost analysis of the BSER.
Regarding the issue of vendor guarantees (commenter 9033), see preamble section V.F.
A number of commenters (e.g. 9486, 10043) posed a purported chicken-egg type of issue: how can there be learning by doing when new coal-fired plants aren't being constructed.  EPA addresses this issue in preamble section V.I.4.
Commenter 9666 and others maintain that because CCS is such an uncertain technology, there will be hurdles to financing.  Although the EPA does not accept the commenters' characterization of the technology (see e.g preamble section V.F. (vendor guarantees)), but has based estimates of financing costs on "high-risk financial assumptions".  NETL (2015) at p. 18. 
The EPA has carefully studied both AEP's comments, its reports on the Mountaineer effort, and the FEED study it prepared (commenter 8966).  AEP especially singled out its difficulties in siting monitoring wells and otherwise siting a sequestration site.  As explained in preamble section V.I.5, this site-specific experience reflects an individual siting challenge which may not be generally applicable.  For example, none of the Class VI permits issued to date by EPA required the number of monitoring wells as at the Mountaineer site.
Commenter 9427 questions the use of the LCOE metric. This issue is addressed in preamble section V.I.1. The commenter also stated EPA's estimate of the baseline cost of coal fired power generation is incorrect, which also skews its assessment of the proposed standard's relative cost. The EPA used DOE/NETL estimates for the baseline cost of coal fired power generation and believes that they are reasonable estimates of the cost of a new coal-fired power plant.  DOE/NETL stated "[T]he cost estimates for plant designs that only contain fully mature technologies, which have been widely deployed at commercial scale (e.g., PC and NGCC power plants without CO2 capture), reflect n[th]-of-a-kind (NOAK) on the technology commercialization maturity spectrum." Further, 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  -  for a plant using bituminous coal). This close agreement is another validation of the NETL cost methodology.
Commenter 9033 suggested that in setting economic criteria for technology, EPA consider the "typical commercial power plant" which will not have federal subsidies and will likely not have access to chemical or EOR revenue. According to the commenter, EPA needs to recognize that both chemicals and EOR are niche opportunities and not available to most power plants. The commenter added that even in the most optimistic cases, people forecast EOR has consuming perhaps 100 million tons of CO2 (including current natural CO2) and chemicals are in the low millions of tons when compared with the billions of tons required to be reduced.
Commenter 10095 stated EPA cannot rely on revenues from EOR activities, government subsidies, or regulatory programs to defray the cost of partial CCS and that EPA fails to acknowledge that these activities and policies are not widely available, impermanent, not guaranteed, and subject to significant political uncertainties
The EPA is not relying on EOR revenues in its cost analysis.  This is a conservative approach to assessing costs, given that new coal plants are being sited to take advantage of such opportunities. See preamble section V.H.8.  
Commenters 10098 and 10239 stated that EPA has pointed to no evidence that any CCS-enabled power plant has been fully funded by a private entity, undercutting EPA's conclusion that CCS actually "can be accommodated by the industry." According to commenter 10098, every CCS project identified in the proposed rule is receiving significant government grants, loan guarantees, and other subsidies, a point that EPA concedes but states that it does "not consider such government subsidies to mean that the costs of CCS would otherwise be unreasonable. Commenters 10098 and 10239 also noted that CCS cannot be accommodated by the industry as evidenced by many examples of the rejection of CCS as BACT on cost grounds and the failure of CCS projects for various economic reasons.  
Commenter 10952 also stated that there is no basis to conclude that industry is "accommodating" the costs or can accommodate the costs as only three projects are planned or under construction. The commenter also noted that since none are operational, it is impossible to conclude that their technical configurations are capable of meeting the duty cycle demands placed on base-load EGUs. The commenter referenced EPA's first proposal in which a ten year timeline and the need for ten up and running demonstration projects, noting that this timeline was lacking from the current proposal. According to the commenter, absent any explanation accompanying the proposal, and there is none, here EPA is making nothing short of a guess, a guess that is in clear conflict with its earlier determinations and conclusion, the hallmark of arbitrary rulemaking.  The commenter also stated that the proposal fails to address how CCS projects would be financially viable without such federal funding, specifically EPA must address what alternative financing means outside federal grant monies are available to support an EGU CCS project where CCS is inordinately costly and an unproven commercial technology.
Commenter 10098 stated that EPA's assertion that the costs of CCS can be accommodated by the industry lacks any factual basis, as EPA relies solely on facilities that have received significant government subsidies for construction and there is no guarantee that such subsidies will be available in the future. The commenter also stated that the proposed rule not only fails to acknowledge EPA's current position against counting such subsidies, as discussed in EPA's NSR Manual, it provides no explanation of why a change in position is warranted. According to the commenter, EPA must provide a reasoned analysis as to why it is now abandoning its current, well-established position that tax credits or other government subsidies for a pollution control should not be included in cost analyses.
Commenter 10029 also stated that the Clean Air Act does not permit the EPA to offset costs by relying on general subsidies available to an industry. The commenter referenced 42 CAA Section 111(a)(1), and stated that under that section , the EPA must tak[e] into account the costs of achieving such reduction (i.e. the standard of performance), not the net costs (after accounting for subsidies) of constructing and operating the stationary source.
Commenter 7977 stated that EPA's conclusion that "a section of the industry is already accommodating the costs" of CCS is based on demonstration projects that receive DOE financial assistance. According to the commenter, that financial assistance was available due to legislation that was passed to stimulate the economy during a recession by increasing spending in a specific time period, and it is unreasonable to conclude that the costs of CCS are not exorbitant under circumstances when such funds are limited and will not be available indefinitely.
 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. 
Commenter 10046 stated even if CCS were technologically feasible, which it is not, the Proposed Rule imposes astronomical costs, which makes new coal-fired power plants economically nonviable. According to the commenter, EPA's own cost numbers demonstrate that partial CCS costs are unreasonable.
Commenters 9590 and 10050 stated the cost of deploying CCS technology is exorbitant and unreasonable, and this factor alone disqualifies CCS as BSER for coal base load power plants.
Commenter 9596 urged EPA to reconsider its decision to designate partial CCS as BSER until the costs of implementing this system of emission reduction come down to more reasonable levels.
Commenter 9423 stated the proposed BSER standard is economically unreasonable and EPA's analysis does not appropriately consider the cost of ancillary factors such as pipelines, transportation of CO2, and storage. The full cost of the proposed standards could substantially affect competition. BSER is applied to a particular source and not the entire industry. Had EPA fully evaluated the costs of BSER, the proposed BSER standard based upon IGCC and CCS would have been rejected as economically unreasonable on its face without looking further at the effects on the industry. By itself, CCS is 30 to 50 percent of the total capital cost of a project, and the 30 percent parasitic loss resulting from CCS corresponds to a large annual operating cost. However, the proposed BSER is the proverbial "straw that breaks the camel's back" when considering the total cost of the proposed BSER along with other costs of controls in this source category. If one were to follow EPA's rationale for not having to consider a pollutant-specific endangerment finding, because the justification and analysis is based upon source category, then one should also apply that rationale to evaluating total costs necessary to meet BSER for all pollutants, not just the newly added pollutants. CCS and other pollution controls for a PC unit would easily account for up to 80 percent of the total cost of a project. In terms of operating cost, CCS and other pollution control equipment combined can account for over 50 percent of the overall annual operating costs. Total costs, both capital and operating, of complying with BSER for all pollutants regulated in the subpart, including CCS controls and other existing required controls, are not economically reasonable. 
A number of commenters (e.g. 9407) claimed that the proposed rule would lead to exorbitant cost increases, comparing an SCPC with and without CCS.  Several commenters projected capital cost increases on the order of 50%.  Commenter NRECA (10952 p. 38) projected an increase of 24% which is roughly the rate of increase projected by EPA for the final rule, albeit for a less stringent standard than proposed (so capital costs would presumably be somewhat less than NRECA projects under its methodology).  EPA explains in preamble section V.H.4 why these cost increases are reasonable  -  in particular, that the industry has absorbed such costs for other NSPS.  The same commenter notes that a 12 % capital cost increase was found reasonable in the first Portland Cement case.  The commenter is correct as to the result of the case, but the EPA does not accept the innuendo that 12% is an upper bound of what level of capital cost increase could be considered reasonable under section 111 (a).  The EPA believes the more germane comparison is with capital cost increases in prior NSPS for this industry, which (like the standard in Portland Cement) were also upheld upon judicial review.   
 Commenters 9423 and 10952 also maintain that EPA simply failed to consider certain costs.  Commenter 9423 maintains that the NSPS are the `straw that breaks the camel's back' and that EPA failed to also consider the costs of other pollution control standards for this industry.  This is incorrect.  In assessing costs, the EPA relied on the NETL studies which assume a coal-burning steam generating unit in compliance with applicable environmental standards, including MATS for hazardous air pollution emissions, and the most recent NSPS for criteria pollutant emissions.  NETL (July 2015) at p. 29.  Commenter 10952 mistakenly stated (Comment p. 38) that EPA had failed to consider transportation and storage costs for captured CO2.  The EPA's cost estimates do in fact include costs associated with transportation and storage of CO2. See preamble section V.I.5.  
Commenter 9514 stated EPA correctly concluded that the costs of installing and operating partial CCS for any new coal plants that may be constructed as a result of the proposed standards are reasonable, and clearly not exorbitant or too high for the industry to bear. The commenter noted EPA has concluded that few, if any, new coal plants would be built in the coming years even in the absence of the proposed NSPS due to the changing economics of the utility sector. According to the commenter, requiring installation and operation of partial CCS at only a few plants would therefore incur costs that the industry as a whole could easily absorb and for this reason, EPA's proposed NSPS would not entail exorbitant costs, and fully satisfy section 111 in this regard. The commenter also stated from an industry-wide perspective, the incremental costs of partial CCS on few new coal-fired plants spread over a region would be inconsequential and thus the costs of EPA's partial CCS standard easily meet the standard under Section 111. 
Commenter 9035 stated that a CCS requirement for new power plants, coupled with federal support, could aid in the development and deployment of this critical technology. According to the commenter, the approximately 18 percent cost difference between coal plants without and with CCS (assuming no EOR price) found by EPA is roughly in line with estimates made by other experts. The commenter referenced a 2013 report by ICF International for the National Association of Regulatory Utility Commissioners and the Eastern Interconnection States Planning Council in which ICF reported that the inclusion of CCS technology on an IGCC coal plant would add to the levelized cost of electricity by roughly 18 to 30 percent. According to the commenter, since this estimate assumes no return from EOR, net CCS costs should be lower.
Commenter 10525 stated it may be easier for EGU owners and operators to absorb financially the cost of incorporating partial CCS versus full CCS. The commenter also noted that depending on the location of EGUs, owners and operators will have an opportunity to use or sell their captured CO2 for EOR.
The EPA largely agrees with these comments.  The EPA agrees that costs of the rule are absorbable by the industry on a national basis.  Preamble section V.H.6. The EPA has also assessed costs on a per-plant basis and found them to be reasonable.  The EPA agrees that EOR opportunities may be used to further reduce costs, but is not premising its cost analysis on availability of EOR opportunities.
Commenter 9592 noted EPA also cited the greater cost to employ CCS for gas-fired EGUs when compared to coal-fired. The commenter noted that, however, the 2013 update of the NETL Report concluded: "When today's technology for CO2 capture and sequestration (CCS) is integrated into these new power plants, the resultant COE, including the cost of CO2 TS&M, is: 86 mills/kWh for NGCC; 108 mills/kWh (average) for PC; and 112 mills/kWh (average) for IGCC.  While the commenter agreed that the estimated cost of CCS for gas-fired EGUs is too great for the technology to be considered BSER, they noted that the NETL concludes that the cost for coal-fired EGUs is even higher. The commenter stated that it does not seem reasonable that if the gas-fired CCS cost is too high to be considered BSER, then the more expensive CCS for coal-fired EGUs could be BSER. 
Commenter 9201 stated the following:
"According to the Interagency Task Force on Carbon Capture cited by EPA, DOE analyses indicate that post-combustion CO2 capture on a 550 MWe net output NGCC plant would increase the capital cost of that plant by 80 percent---about the same increase that would result from employing post-combustion capture on an SCPC plant. The incremental cost increases of electricity for NGCC with CCS is significantly lower (33%) than for a SCPC plant (60%) given fuel cost estimates, lower capital costs for NGCC units, and other factors. DOE's analyses also show that for CCS: 
   * NGCC has the lowest total overnight cost (TOC) at $1,842/kw as compared to SCPC ($4,391/kw) or IGCC ($4,086/kw); 
   * NGCC has the lowest cost of electricity (COE) at $90.43 MWh as compared to SCPC ($147.27/MWh) or IGCC ($141.27/MWh); and 
   * The increase in the COE for NGCC would be about 45 percent as compared to 70 percent for SCPC.<FOOTNOTE 170>
As a general matter, NGCC with CCS looks more favorable than coal-fired EGU with CCS considering that (1) the capital costs of NGCC turbines are roughly one-third the cost of those for SCPC units; (2) there is less CO2 to capture, compress and store for a NGCC unit; and (3) lower natural gas prices forecasted by EPA will lower the overall TOC and COE for gas as compared to coal, even with CCS on those units."
A number of commenters maintained that if CCS is not BSER for NGCC for reasons of cost, then it should not be BSER for coal-fired power plants, since the costs are even higher.  The EPA is not identifying CCS as BSER for NGCC, but it is on grounds of technical uncertainty.  See preamble section IX.C.4.a.  Commenter 9201 also bases its analysis on the interagency Task Force Report, which was addressing full CCS, so the costs quoted are much higher than those for the actual standard of performance adopted by EPA in this rule.
Commenter 10095 stated that EPA's cost analysis is incomplete and potentially mischaracterizes the cost of pre- or post-combustion CCS technologies to support its proposal. The commenter noted EPA's methodology and reliance on the DOE NETL for partial CCS cost estimates for SCPC and IGCC generation technologies. According to the commenter, it is necessary for EPA to provide the most accurate cost estimates as possible when establishing such critical performance standards, and for an emerging technology like CCS, for which cost estimates are changing, it is imperative that EPA use multiple sources and the most up-to-date costs from ongoing projects to develop the most accurate estimates. The commenter also stated that contrary to EPA's assertions, the proposal, in fact, intermingles DOE NETL-based and EIA-based technology cost estimates in some instances. The commenter noted that the two sources use dissimilar methodologies as described in the Coal Utilization Research Council's (CURC) comments. The commenter stated that EPA needs to address these inconsistencies to allow for more comparable results. 
 In response to this and similar comments, and also consistent with the EPA's attempt to utilize the most up-to-date information, cost estimates for post-combustion CCS reflect recent vendor quotes for the Cansolv process  -  the process currently in full-scale commercial use at the Boundary Dam facility.  In response to comments maintaining that the LCOE values are derived from different sources which do not use identical methodologies, the EPA notes that the latest publication of the Global CCS Institute "examines the costs and emissions intensities of low emission technologies in power generation.  It uses cost data for the US from a variety of published sources and applies these in a common methodological framework based on the levelised cost of electricity (LCOE) that allows comparison between different technologies in terms of emission reductions."  The estimates for full CCS (the study does not estimate partial CCS costs) are in the same range as NETL and other techno-economic expert cost estimates.  See preamble Table 10.  Nuclear estimates are likewise within the same range of other techno-economic expert estimates.
Commenter 2471 stated USEPA has falsely made assumptions to support the CCS technology, such as in its cost consideration to society-at-large, rather than the costs at individual units, and utilization of an unreasonable future timeframe to justify its cost-benefit analyses. 
 The EPA has analyzed costs at both the per-plant and national level.  See preamble section V.H.
Commenter 9034 stated that even assuming CCS technology could be successfully implemented at commercial coal-fired EGUs, it still would not be the BSER for coal plants, because implementing this technology would be cost prohibitive. The commenter noted that Section 111 of the CAA requires EPA to take costs into account when determining the BSER for new sources, and the D.C. Circuit has explained that EPA's BSER determination will not be sustained when the costs of using the technology are "exorbitant" or "excessive."
Commenters 7977, 9197, 9201, 9600, and 10880 stated that partial CCS is not BSER when costs are considered.  Commenter 10880 referenced the recent rejection of CCS at Edwardsport due to costs and noted that several engineering studies concluded that the costs for a coal EGU with 90% capture will increase costs by 70-79% over a plant without CCS. Commenter 9201 stated that technology experts and utilizes agree that CCS is not adequately demonstrated, providing the discontinuation of the Mountaineer project as evidence, along with citing testimonies from DOE and Duke Power on the high costs of CCS. The commenter also provided reasons why a new coal plant with CCS would cost substantially more than one without CCS including equipment costs and the energy penalty. 
Commenter 9596 stated EPA's assertion that CCS is adequately demonstrated notwithstanding the exorbitant costs represents a departure from EPA's previous practice in setting performing standards. 
Commenter 10618 stated that EPA's rationale for eliminating full capture CCS as the BSER based on costs is equally applicable to partial capture CCS. The commenter provided additional reasons that full or partial CCS is not the BSER, including technical, financial, regulatory and practical considerations. According to the commenter, the experience of recent projects and findings of major studies demonstrate that EPA's cost analysis is flawed and that CCS is not the BSER. For example, the commenter stated that EPA's range of a 12 to 60% cost increase for CCS is far below the estimates of DOE and others that approach 80% or more. The commenter concluded that If the 40-60% increase was sufficient to eliminate full capture, then the 80+% increase experienced by active projects and estimated by DOE and others is more than sufficient to also eliminate partial capture as the BSER. 
Commenter 8966 stated under Section 111 of the CAA, technology constituting a BSER cannot impose an exorbitant cost to achieve a performance standard; however partial CCS is exorbitantly costly. According to the commenter, enactment of the proposed rule would make it virtually impossible for any new coal power plants to be constructed and remain viable. The commenter continued that as the existing fleet of aging coal power plants is retired and not replaced by new coal-fired plants, the costs imposed by the proposed standard would indeed be greater than the industry could bear and survive, which violates the Section 111 cost provision.
Commenter 10952 stated that while EPA's conclusion that carbon capture is BSER is not supported by the rulemaking docket and is otherwise arbitrary, EPA's sole rationale for concluding such is based on exclusive reliance on information gleaned from projects that EPA is prevented from considering. According to the commenter, for these DOE funded projects, EPA has not and cannot point to any full scale project that utilizes the technology identified as BSER, nor can it point to any project with an operating history that can yield real costs associated with actually employing carbon capture at an EGU that would allow appropriate and needed analysis regarding operational costs and viability so to justify its BSER determination.
 A number of commenters pointed to costs incurred at the Edwardsport and Mountaineer projects as evidence that a CCS-based BSER is exorbitantly costly.  The commenter acknowledges that its cost estimates for Edwardsport reflect full CCS, which is not the basis for the BSER determination in the final standard.  Nor is BSER based on IGCC, and the EPA notes that at both Edwardsport and Kemper, it was cost overruns on IGCC (rather than CCS) that were the source of cost overruns.  Indeed, Edwardsport is IGCC only at present, so cost overruns obviously have nothing to do with CCS.  Mountaineer was a retrofit, not a new source, and incurred high costs for reasons one might expect relating, at least in part (and as stressed in its public comments), to sequestration siting difficulties after already locating at a site selected without consideration of sequestration opportunities.
 Commenter 10628 (AEP) maintained that partial CCS is exorbitantly costly by EPA's own logic.  The commenter maintains that the EPA rejected full CCS as BSER yet the cost of partial CCS is within this same range, properly analyzed and considering the upper end of the NETL range of cost estimates.  The EPA has adopted a somewhat less stringent standard of performance than proposed in large part due to considerations of cost.  The final standard of performance is comparable to nuclear, including at the upper range of potential cost estimates.  See preamble at Table 8.  Moreover, the comment is somewhat misleading. The EPA indicated not that a certain cost was too great, but rather that the cost was too great in relation to the cost of other non-NGCC low-carbon technologies with which it would be competing.  As it happens, the cost of the final standard of performance (normalized to LCOE) is far lower than the values cited in the comment, even though this is not the proper metric to evaluate.
 Commenter 10952 indicates that the proposed standard of performance rests on EPAct facilities which EPA cannot properly consider.  In fact, EPA at proposal noted that Boundary Dam was due to commence operations, and it has in fact done so.  The commenter's claim is therefore incorrect for post-combustion CCS, and is also incorrect with respect to pre-combustion CCS.  See preamble section V.D and E.
Commenter 8966 stated that that as the existing fleet of aging coal power plants is retired and not replaced by new coal-fired plants, the costs imposed by the proposed standard would indeed be greater than the industry could bear and survive.  However, coal is already significantly less economic than new NGCC capacity and is projected to remain so for the foreseeable future.  RIA chapter 4.  Thus, if new coal is added, it will be because developers believe it prudent to pay a cost premium.  An additional cost premium associated with partial CCS still leaves coal cost competitive with nuclear, the baseload dispatchable non-NGCC technology which might also be added for the same reason.  See preamble at Table 8.  The EPA further notes that in a lower-carbon future, CCS may prove to be the technology that allows new coal to continue to be constructed.  This appeared to be the view of commenter AEP:  "AEP still believes the advancement of CCS is critical for the sustainability of coal-fired generation."
Commenter 9664 provided information to support EPA's cost analysis and BSER determination for CCS. The commenter stated that when evaluating a performance standard's projected costs, EPA may take into account the standard's long-term impacts on both a plant-wide and nationwide basis, including effects on the national economy and the legislative history affirms that the term "best technology" encompasses considerations of long-term growth, long-term cost savings, and financial incentives for improved technology. The commenter also stated EPA appropriately recognizes that the construction and operating costs associated with CCS technologies will decrease as further experience with them is gained in response to the standard, referencing the setting of mobile source air emission limits as a previous example. The commenter also stated the statute and case law authorize EPA not only to evaluate the costs of achieving the standard, but also any offsetting revenue streams, and to weigh the severity of the pollution problem to be addressed, in selecting missions control options comprising the "best" system of emission reduction.
The commenter also stated Section 111(a)(1) directs EPA to "take into account" the cost of achieving reductions and any nonair quality health and environmental impacts and energy requirements when selecting the BSER and setting performance standards. The commenter provided additional discussion on several D.C. Circuit court cases to support their argument. The commenter also stated that as EPA correctly observes in the preamble to the proposed rule, the D.C. Circuit has never invalidated an NSPS as too costly, providing information on several court cases. 
 The EPA largely agrees with this comment.
Commenter 8966 stated coal-fired plants depend on fundamentally distinct processes. CO2 emissions from coal plants are greater than other sources due to the intrinsic properties of coal during combustion. As a result, the magnitude of CO2 capture is greater and will cost significantly more than for other industries. The commenter provided additional concern with EOR re-use and future expectations of reduced CCS costs, noting the costs of CCS implementation are heavily amplified for prospective coal power plant operators, marking a particularly exorbitant cost that distinctly hits the coal industry.
See preamble section V.H.8.
Commenter 9407 disagreed with EPA's conclusion that the proposal, if finalized, will have no cost, stating that this proposal's cost to the nation in terms of a flawed energy policy and resulting costs to the nation's electric consumers would be substantial. According to the commenter, these are compelling reason to rethink this NSPS proposal.
Commenter 2470 stated EPA should avoid one-size-fits-all mandates that would unnecessarily increase utility costs.
Commenter 9592 stated not only is CCS technology not ready for commercial deployment, it will be excessively costly to the consumer. 
Commenters 8024, 8966, 9505, 9592, 9780, 10662, 10667, 10880, cited U.S. DOE statements that CCS technology would increase the cost of producing electricity by as much as 80 percent.
Commenter 8918 stated CCS costs are not reasonable, as Great River Energy's mission calls for "affordable rates" to our member cooperatives. According to the commenter, approximately 83% of their member cooperatives' energy sales are residential.  The commenter noted that as discussed in NRECA's comments, relying on a reasonable cost criterion being less than the cost where "industry could not bear and survive" ignores the majority of the people to whom we and our member cooperatives supply electricity.
Commenter 9780 stated that the level of cost increase resulting from the proposal to require partial CCS for coal plants would likely be a "death knell" for any projects aimed at increasing fuel diversity in the electric generating fleet, as no customer would be willing to pay such a premium. According to the commenter, it is highly unlikely that any state public utility commission would approve its construction, and that certainly no competitive wholesale electricity market would bear such costs. According to the commenter, customers and retail rate regulators demand reliable electricity, but they also demand that it be provided at a reasonable price; however, the costs and parasitic load impacts of CCS technologies significantly increase the projected cost of building a coal plant which is why CCS is routinely rejected in GHG BACT analyses for new or modified plants. The commenter noted that the Power4Georgians plant that EPA cites as an example of one that customers would be willing to pay a premium for was designed as a conventional coal plant without CCS in order to compete with natural gas. 
Commenter 9196 stated that the proposed rule will limit fuel options and cause increases in electricity costs. According to the commenter, removing coal from our country's energy mix in the future raises additional concerns due to the volatility that exists in the other energy markets. The commenter cited testimony from David Wright regarding the need for a diverse resource portfolio to protect ratepayers against price increases that one fuel may experience. The commenter also stated that increases in electricity costs harm the economy, public health, and the environment. According to the commenter, affordable, reliable energy is one of the main drivers of economic growth, and increasing the cost of energy and thereby forcing U.S. industries oversees is something we cannot risk as our country continues down the path of economic recovery. The commenter noted that higher electricity prices will disproportionately impact vulnerable individuals. The commenter also noted the proposed rule is likely to adversely affect public health in three ways: by increasing the cost of medical care and treatment; by imposing real threats on human health by suppressing economic growth and the improved health it brings; and by focusing on expensive rulemakings with little incremental benefits when those resources, if more sensibly deployed, could save many times more lives. Furthermore, the commenter suggested that the higher electricity prices will be largely borne by companies in energy-intensive manufacturing, where higher prices will make it more difficult to expand operations and increase employment, and provided information on the link between unemployment and public health. The commenter also provided information on energy costs for hospitals and the implications for their budgets. 
Commenter 9770 stated EPA would need to evaluate the energy and costs, including the cost of electricity to communities of partial CCS in order to determine that CCS is an "adequately demonstrated" system of emission reduction.
Commenter 9505 stated that the proposal fails to address the significant financial barriers that will simply result in higher costs for ratepayers, and ultimately, the taxpayers of the States.
Commenter 9107 stated industry concerns that CCS is not proven and it will increase costs of coal use and resulting into higher costs to the public. According to the commenter, high cost of this otherwise most economical coal fuel will take away the competitive advantage of the manufactured goods by the US industries compare to the countries who continue to allow their industries to operate without such mandates. The commenter suggested alternate solutions are needed which will allow the use of abundant resources of coal in USA while mitigating environmental and climate control concerns as you are seeking per these EPA mandates without increasing costs.
Commenter 4162 stated that EPA should avoid one-size-fits-all mandates that would unnecessarily increase utility costs.
Commenter 9423 stated disagreement with EPA's conclusion that the cost of BSER "could be passed on without substantially affecting competition." TCEQ, PUC, and RRC noted that costs can be passed on more gradually and over a longer period of time in a regulated electric market than in a competitive electric market like Texas' Electric Reliability Council of Texas (ERCOT). According to the commenter, companies in a competitive electric market are more sensitive to additional costs, and are more likely to transfer those increased costs to electric consumers in the short term. Consequently, the commenter stated that the ability to pass on the cost of BSER is likely to affect competition.
A number of commenters maintained that consumers would pay the cost of increased electricity prices associated with a standard of performance reflecting performance of partial CCS (e.g. commenters 8918, 9780).  Commenter 9196 projected significant costs in reduced manufacturing output and general economic non-competitiveness.  These comments appear to assume that new non-compliant coal capacity will be constructed, yet all evidence is to the contrary, and for reasons unrelated to the standard of performance adopted here.  See RIA chapter 4.  Even in Kentucky, the very heart of coal country, new capacity is NGCC.  EPA explored scenarios using alternative assumptions with considerably higher future electric demand and higher natural gas prices, and no scenario resulted in new conventional coal by 2020.  Independent analysis and projections from EIA confirm this trend. EPA does not project any change in energy prices as a result of this rule, and as such does not expect negative impacts on the affordability or reliability of electricity. Thus, EPA's conclusion that there is likely to be no new non-compliant capacity built during the section 111 (b) review period is well founded.  Nor does the EPA believe there is compelling evidence that new coal capacity would be competitive but for the cost increment associated with partial CCS.  See preamble section V.I.4.
 Commenters 2470 and 4162 urged the EPA not to adopt a `one size fits all' standard.  In fact, there are alternative compliance pathways available to meeting the final standard of performance while using coal as the fuel.
In response to Commenter 9423's statement regarding cost recovery in competitive energy markets, the EPA notes that competitive electricity markets were designed to send price signals to incentivize the development of cost-effective generation, allowing for cost recovery for those units through different market mechanisms depending upon the design of the specific competitive market. Through security constrained economic dispatch (SCED), the system operator determines which resources will be dispatched to meet system load, utilizing available resources to serve load as inexpensively as possible. Competitive markets have mechanisms that allow the recovery of environmental compliance costs, similar to how other generator costs are recovered. The system operator will dispatch those units that are needed to reliably serve load, with dispatched units receiving the market price.
Commenter 9684 stated the recycled Carbon Rule is still a fuel-switching mandate, although not as overtly so. The commenter stated in the first go-round, EPA decided that CCS was not an "adequately demonstrated" system of emission reduction. The commenter noted that the levelized cost of new coal power plants already exceeded that of new NGCC plants, and according to EPA's 2012 proposal, today's CCS technologies would add around 80% to the cost of electricity for a new pulverized coal (PC) plant, and around 35% to the cost of electricity for a new advanced gasification-based (IGCC) plant. The commenter noted EPA has since changed its tune, arguing that during the period between the original and revised proposals, several utility-scale CCS projects have made significant progress towards completion, so the technology now qualifies as adequately demonstrated. The commenter provided information on the increased costs associated with the Kemper project noting that unless a utility intending to build a new coal power plant wants to go bankrupt, it's only real choice is to fuel-switch and build an NGCC plant instead.
Commenter 9486 stated concern that compliance for new coal-fired power plants relies on CCS control technologies that are new and unproven when applied to the coal power industry as a combined system for control and are cost prohibitive to implement at this time. According to the commenter, the cost of CSS control technologies could be so high that U.S. EPA will be inadvertently eliminating a much needed piece of the nation's complex future energy supply puzzle which includes coal, natural gas, nuclear, wind, solar as well as other renewable resources.
Commenter 9197 stated the extremely high cost of producing electricity from coal with partial CCS, combined with the need to account to both regulators and shareholders for their investment decisions, will likely preclude most-if not all-utilities from investing in new coal-fired generation. For most of these utilities, the costs of implementing partial CCS-in relation to natural gas combined cycle (''NGCC"), which is the only other truly viable option for new baseload power-will be so excessive as to make investment in new partial CCS-capable facilities unreasonable. Thus, as existing coal-units retire, the proposed NSPS will effectively preclude the supply of new coal-fired electricity to future electricity markets. For all of these reasons, we do not agree with EPA that CCS is adequately demonstrated when considering cost.
 See preamble sections V.H and I.  Costs of new coal are already not competitive with new NGCC, and the final standard of performance preserves the possibility of coal for fuel diversity reasons by adopting a standard with an LCOE within the same range as new nuclear technology, the other baseload dispatchable non-NGCC option.  Nor does it mandate a single manner of compliance, given that there are various potential compliance paths available to achieve the final standard of performance.
Commenter 10239 (pp. 17-18) referenced two Iowa DNR PSD permit decisions which concluded that CCS was too costly. The commenter noted that in one of the decisions, the Iowa agency highlighted transport costs to suitable GS sites as a key impediment to CCS. The commenter stated that EPA reviewed each permit and did not comment or question Iowa DNR's conclusions on CCS. The commenter also cited to the State of Michigan's action in rejecting CCS as BACT for the Wolverine facility.
The commenter refers to actions taken by state agencies in rejecting CCS on cost grounds when making individual BACT determinations.  First, these agencies were evaluating full CCS, not partial CCS.  Second, the agencies all evidently found that CCS (even full CCS) was technically feasible (since determinations were not made at step 1 of the BACT analysis), but rejected on grounds of cost, especially (in the case of the Iowa determinations) cost of transport and sequestration.  The final standard of performance has alternative pathways not involving sequestration, in the event a new source chooses to site in a location without ready access to sequestration (and this is a very limited area  -  see preamble section V.M and Availability TSD).  Third, these are state determinations, not determinations of EPA.  As explained in preamble section XII.C, state agencies that have their own approved state implementation plan, the state has primacy over their permitting actions and discretion to interpret their approved rules and to apply the applicable federal and state regulatory requirements that are in place at the time for the facility in question. The EPA's role is to provide oversight to ensure that the state operates their PSD program in accordance with the CAA and applicable rules. If the EPA does not adversely comment on a certain permit or BACT determination, it does not imply EPA endorsement of the proposed permit or determination.
Commenter 9677 stated EPA relies on data that shows CCS increases capital costs for a supercritical pulverized coal unit by 34.6%, fixed O&M costs by 28.5%, and variable O&M costs by 36.4%. The commenter noted that in the Portland Cement case, which is referred to in the Proposal's cost discussion, it was determined that the cost of technologies that a new facility would need to install to meet the standard was around 12 percent of the capital cost for the entire facility with annual operating costs increasing by 5-7 percent. It was also determined that these costs could be recovered "without substantially affecting competition."  By contrast, the commenter concluded, the CCS incremental capital cost and operating cost increases, mentioned above, are much higher than those which were discussed in the Portland Cement case as being acceptable.
The commenter is correct that the capital cost increases here are higher than those found acceptable in the first Portland Cement I case, although that case did not say that the costs were at the upper range of acceptability.  As shown in preamble section V.H. 4, the capital cost increases here are within a range found acceptable for this industry in prior NSPS.  The increases associated with the final standard of performance  also are less than those cited by the commenter, given the reduced stringency of the final standard of performance compared to the proposed standard. See RIA at Table 4-4, showing capital cost increase (in the bituminous coal case) of 21.3%, FOM increasing 19.75%, and VOM increasing 11%.
Commenter 7422 stated concern that the level of funding available from government assistance programs in the future may be less than the EPA asserts and that the costs of CCS may decline less than forecasted. The commenter also stated that in a restructured market, the impact on market-based investment decisions is even more dramatically impacted by reliance on government funding availability as merchant generators do not have customers from whom they can recover costs like traditional, vertically-integrated utilities. This distinction is critical and should be an important consideration in this rulemaking. The commenter stated that this is all the more reason to allow for state and regional consideration and flexibility. According to the commenter, the cost of installing CCS on a new coal boiler is sufficiently high to make it extremely unlikely for a regulated utility or merchant generator to consider construction of coal-fired generation when constructing new generation resources.
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.
 The EPA has reasonably determined that costs of partial CCS, at the level of capture reflected in the final standard of performance, are not exorbitant and are reasonable.  See preamble sections V.H and I.
Commenter 9318 stated the agency's assumptions in the new unit rule about the availability of CCS are unreasonable and unproven. According to the commenter, if these positions are repeated or incorporated into  the existing source rule, impacted units will likely not be able to comply with any existing source rule in a cost-effective way. The commenter stated CCS is at best an unproven and expensive experimental technology that should not be used as the basis for emissions standards in the existing source rule. The commenter urged EPA to decline to adopt these assumptions in the existing unit rule in light of the agency's assertion that it is seeking cost-effective and flexible solutions. 
 BSER under the guidelines for existing sources does not include CCS.
Commenter 9666 stated the methodology to project SCPC and NG/CC cost for a 30-year time period should be improved. The commenter suggested the methodology should consider the following:
Varied Capital Cost Sources. Additional cost sources should be sought. The six studies cited in this report invoke three sources of data - two proprietary databases and the EIA - and results show capital cost estimates depend on the data source. A key variable is how escalation is handled.
Role of Suppliers and Vendors. The inputs provided by vendors or suppliers, and how they are used, should be evaluated. As discussed in the critique in Appendix A, (of the commenter's attachment) costs submitted by vendors in some cases should be adjusted for scope, fuel type, or other variables.
A more robust approach soliciting budgetary quotes for this material and reviewing in the context of more than one in-house database, constructed from recent cost data, and using a more realistic sensitivity analysis that reflects the actual variations in capital cost incurred and anticipated is advised.
According to the commenter, the cost estimates cited by EPA used to dismiss SCPC as a viable power generating option over the next three decades appear based on data from one engineering firm, the bulk of which appears gathered during the time period of 2005-2007. How these costs were adjusted for market conditions and price escalation is not clear from the reports. Discussion is presented in two reports suggesting that rather than escalating 2005-2007 costs to latter years, a separate procurement document was prepared and issued to revise estimate. This approach appears limited to certain categories of ancillary equipment. For the cost estimate published in September 2013 that is used by EPA, it is not possible to tell if the cost is determined using (a) data from 2004-2007 that is escalated using a cost index, versus (b) recent commercial bids in response to a procurement.
The commenter also stated that NETL estimates for the capital cost for SCPC and NG/CC equipment are compromised by several factors: the escalation of capital equipment prices due to strong global demand; the drop in natural gas price and improved cost viability of NG/CC equipment; and the overnight drop in SCPC equipment demand. These factors should be considered in estimating equipment costs going forward for 30 years.
Commenter 9666 (UARG) suggests a variety of means of assessing costs of SCPC and NGCC technologies for the next 30 years.  Before answering the specifics, the EPA notes that the 30-year time frame suggested by the commenter is not compelled by statute (section 111 (a) does not specify a time frame for consideration of costs), nor any compelled factual justification.  The time frame generally considered in the RIA  -  through 2022, the year of the next review cycle for NSPS under section 111  -  is reasonable.  
The commenter's specific suggestions also are somewhat misplaced.  The commenter requests the EPA to evaluate other sources for capital cost estimates than used at proposal.  EPA has made every effort to use the latest figures.  The NETL (July 2015) cost figures reflect recent vendor quotes for the Shell Cansolv process, the process in (successful) full scale commercial use at Boundary Dam.  The NETL methodology for financing involves assuming "high-risk financial costs" (p. 18).
 The commenter's request regarding use of vendor quotes is answered immediately above.
 The EPA has also evaluated the NETL estimates against those of other techno-economic estimates and marketplace quotes from suppliers and found them to be consistent.  See e.g. preamble at Tables 8-11.  
The commenter also questions the reliability of the NETL cost estimates vis-à-vis SCPC technology.  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  -  for a plant using bituminous coal). This close agreement is another validation of the NETL cost methodology generally, and for SCPC specifically.
Commenter 10119 provided the following discussion: 
"Nonetheless, EPA states it may decide to exempt the plant because there might be "opportunity costs"---specifically market opportunities that could be realized only by beginning construction immediately---associated with complying with the standard. Of course, because it has formed "no view" as to the facility's construction status or market opportunities, EPA has no idea whether these opportunity costs even exist, much less whether compliance with the performance standard would impose opportunity costs. Incredibly, EPA declines to determine whether the statute even authorizes it to consider "opportunity costs," claiming it is unnecessary to do so in light of EPA's own uncertainty as to whether there are any "opportunity costs" to consider. EPA cannot justify an exemption from plain statutory requirements on the basis of facts it declines to find and legal analysis it declines to undertake. The requisite process of notice and comment is fatally undermined when a proposed rulemaking omits the factual basis, the legal rationale, and even aspects of the rule itself, leaving the public to guess at what action the agency might take and why the agency chose to take it. A final rule announcing a decision based on such an entirely inadequate notice and comment process would be invalid for this reason alone.
In any event, reliance on "opportunity costs" to exempt a project that has not yet commenced construction is just as impermissible as consideration of "sunk costs" (we do appreciate, however, EPA's withdrawal of "sunk costs" as a possible reason for exempting sources from NSPS). Though nebulous, EPA's concept of "opportunity costs" seems, in essence, to amount to no more than ordinary but unverifiable and highly fluid commercial expectations of profits. Thus, EPA characterizes opportunity costs as those involved in forgoing the ability "to meet a valuable near-term resource need or market opportunity." But meeting such needs and market opportunities is precisely why all industrial plants are conceived and pushed forward, and why pre-construction costs are incurred in the first place: these opportunities and needs, and the profits expected from capturing them, must be anticipated to be sufficiently large and near-term to justify the planning and pre-construction costs in every case. The promulgation of new NSPS standards and their concomitant additional expenses and potential construction delays will always affect these market opportunities, and each specific source will be affected differently depending on a myriad of individually applicable factors. Those factors and their evaluation are far outside the agency's ken, and include the specific and shifting business, financial, strategic and contingency plans of each facility, its owners, investors or lenders, as well as the characteristics of the market opportunities themselves---information which often consists of highly valuable, confidential business information closely guarded against disclosure by all the market participants. In other words, the promulgation of new standards will always affect the often confidential business opportunities and profitability projections of projects anywhere along the pre-construction stage, and will do so in ways unique to each project and shifting over time. Congress clearly recognized this problem, and thus set an unambiguous cut-off point that determines when a project will have to comply, and its market opportunities will therefore be affected: that cut-off point is whether construction has or has not commenced at the time a standard is proposed. The statutory language is clear, and EPA has longstanding regulations enforcing it. EPA may not override Congress' express judgment on this point."
 EPA's position on sources under development are set out in preamble section III.J.  EPA notes further that it has ample discretion under section 111 to create subcategories, and can reasonably do so under the circumstances set out in preamble section III.J.
Commenter 10667 stated coal and lignite are vital to Texas' continued economic success and electricity security and any impacts to these industries place the entire Texas economy at risk.
 The EPA is of course sympathetic to these and related comments.  As shown in chapter 4 of the RIA, however, new non-compliant coal technology is very unlikely to be constructed anywhere in the country for reasons unrelated to the new standard of performance.
Commenter 10869 stated for CCS to play a major role in reducing CO2 emissions, new infrastructure must be constructed to capture, process, and transport large quantities of CO2. Support for commercial-scale, fully integrated CCS demonstration projects at coal-fired power plants should be a part of our energy strategy, alongside investments in R&D on other low carbon energy resources. Careful selection and monitoring of geologic storage (or "sequestration") sites, and the development of regulatory standards and mechanisms to guide this process, will be needed to minimize the environmental risks associated with CO2 leakage (including groundwater contamination). 
As more CCS projects are undertaken, learning opportunities and economies of scale could help drive down costs and improve performance of this technology. The ultimate costs of complying with regulations for limiting other pollutants, including SO2 and NOx, have turned out to be much lower than either the EPA projected or industry warned. EPA's carbon standard for new power plants provides an incentive to industry to undertake investments in CCS. Projections from EIA, MIT and IEA show that CCS costs could come down over time as the technology is more widely deployed. For example, in AEO 2013, EIA projects coal PC with CCS capital costs to fall 9 percent by 2025, 14 percent by 2030 and 23 percent by 2040 compared to 2015 costs. Studies by the Department of Energy (DOE) also project cost declines for advanced PC and IGCC power plants with carbon capture, of 27 percent and 31 percent, respectively, relative to current costs.41 EPA carbon standards could be an important driver for these cost reductions.
 The EPA agrees with the tone of this broad policy-oriented comment, although the existing CO2 transportation infrastructure is more extensive than the commenter appears to envision.  See preamble section V. M.
Adequate Demonstration 
Commenters 2525, 7433, 8349, 8501, 8971, 8974, 9001, 9192, 9194, 9396, 9407, 9425, 9428, 9595, 9596, 9725, 9735, 9770, 10024, 10028, 10036, 10086, 10087, 10096, 10098, 10105, 10238, 10242, 10387, 10392, 10393, and 10501 stated that CCS is not adequately demonstrated. Similarly, Commenters 0840, 7977, 8971, 9034, 9194, 9382, 9601, 9648, 9773, 10044, 10083, 10103, 10242, 10391, 10395 and 10097 stated that EPA has not demonstrated that carbon capture meets NSPS statutory requirements for adequate demonstration because no full scale power plants currently operate with CCS.  Commenter 9472 also proposed that EPA's determination that CCS is adequately demonstrated conflicts with its own permitting decisions. Commenter 9596 commenter that the performance standard itself is also invalid as a matter of law because CCS has not been adequately demonstrated. Commenter 10098 stated that EPA's conclusion that CCS is adequately demonstrated is based on a series of misunderstandings and mischaracterizations of existing data.   
Commenter 10392 cited technological immaturity, accessibility and transportation issues as arguments against adequate demonstration. Commenters 9773, 10028 and 10030 cited feasibility and cost as reasons why they disagree with the BSER determination. Commenters 9407 and 9194 cited the lack of transportation, storage and monitoring infrastructure as reasons why CCS cannot be BSER. Commenter 9396 stated that EPA has not addressed pipelines, monitoring, sequestration, or impacts related to non-air quality health, environmental, costs, or electricity reliability as required to demonstrate achievability. Commenter 9770 stated that EPA has ignored cost, land use and feasibility issues, such as the cost and time needed to build and permit pipelines and find suitable sequestration sites.  Commenter 7433 cited cost, transport and safety concerns as reasons adding to the uncertainty of the technological feasibility. Commenter 0775 noted that while there are some active CCS projects, they have diminished since last year and few of the active projects demonstrate the feasibility of using CCS. Commenter 10062 also cited IPCCs concerns about the operational safety and long-term integrity of CO2 storage. 
Commenters 0588, 8966, 9381, 9396, 9423, 9648, 9666, 10046 and 10619 also added that technical feasibility is not the same as adequate demonstration and CCS is not adequately demonstrated. Commenter 9382 stated that not even IGCC is adequately demonstrated. Similarly, Commenter 8501 states that 'projected to be available' is not the same as 'adequate demonstration'.
Commenter 9497 recommended that EPA reexamine the rule in four years to determine if CCS is then adequately demonstrated and Commenter 10046 recommended that EPA wait a year or two to gather the necessary operating data. Commenter 9317 recommended that EPA not consider CCS until an 8 year technology review has been conducted to ensure concerns have been addressed. Commenters 2470, 10062 and 10880 recommended that EPA must wait to determine if CCS is adequately demonstrated until reliable data at commercial scale EGUs is available. Commenter 9683 encouraged EPA to re-propose the rule so as to not discourage the continued development of CCS, and Commenter 10518 encouraged EPA to re-propose the rule using optimized heat rate efficiencies. Commenter 8949 stated that EPA should be prepared to revise or revoke the proposed rule should the reference facilities fail to meet the anticipated emissions reductions. Commenters 9190, 9666, 9678, 9725, 10083, and 10680 stated that the CAA does not allow for unproven technologies to be considered and therefore, EPA should adopt a BSER standard that does not rely on CCS. Commenters 2470 and 9648 encouraged EPA not to require CCS until the technology has been adequately demonstrated on more than one type and size of coal plant.
Commenter 9396 asserted that the rule's interpretation of the CAA only serves to promote uncertainty and instability.  
Most of these comments are fully addressed in the preamble to the final rule.  See, e.g. preamble sections V.D and V.E (post- and pre-combustion partial CCS are demonstrated technologies); V.H., V.I and V.O (efficient SCPC and partial CCS are adequately demonstrated considering issues of cost, nonair quality health and environmental impacts and energy requirements).  Issues relating to pipeline and sequestration (commenter 9396) are addressed in preamble section V.I.5 and V.N.  Comments maintaining that individual BACT determinations (none of them involving EPA determinations regarding fossil-fuel fired EGUs, as it happens) are addressed in preamble section XII.C. and other comment responses.  Commenters' undocumented claims of safety issues and reliability issues associated with CCS (e.g. comment 10062) are lacking in basis.  Boundary Dam is operating highly effectively.  Dakota Gasification has been operating full CCS effectively for decades.  See NETL (2015) at p. 36: "The capture and CO2 compression technologies have commercial operating experience with demonstrated ability for high reliability."
Commenter 1959 remarked that CO2 storage has not been demonstrated sufficiently to win public acceptance and that public opposition to storage may preclude CCS at some locations.
Public awareness and support have been widely recognized as critical components in the development of new energy infrastructure, including CCS deployment. Efforts have been made to design strategies for successful outreach to the public. For example, under the DOE Regional Carbon Sequestration Partnerships, DOE has been engaging with local communities to educate and inform them about planned pilot and demonstration projects in their areas. DOE's Best Practices for Public Outreach and Education for Carbon Storage Projects presents lessons learned through the planning and implementation of CCS projects, as well as best practices for community engagement. 
Commenters 9035 and 10869 cited several projects that indicate that broad experience with CCS although it has not been deployed at the commercial scale. Commenter 9035 also noted that all commercial scale projects rely on EOR and that EPA has provided a pathway for demonstrating geologic storage through EOR by meeting requirements for UICP and GGRP.
The EPA agrees that geologic sequestration is adequately demonstrated and that the regulatory requirements and safeguards of the Underground Injection Control Program and complementary monitoring and reporting requirements of the GHGRP, together ensure that sequestered CO2 will remain secure and provide the monitoring to identify and address potential leakage.
Commenters 1902, 1959, 2470, 4217, 6871, 8952, 8954, 9190, 9201, 9202, 9382, 9426, 9472, 9487, 9497, 9505, 9597, 9657, 9666, 9678, 9683, 9725, 9780, 10023, 10033, 10036, 10098, 10137, 10239, 10243, 10393, 10396, 10466, 10660, 10662, 10680, 10974 and 10975  stated that CCS is not adequately demonstrated because coal EGU (including pulverized coal and simple cycle units) has ever used CCS in commercial operations or achieved the proposed emission limit. Commenter 10023 added that EPA cannot rely on estimates of performance.
Commenters 9201 and 10662 remarked that EPA dismisses SCPC and IGCC technology as BSER without assessing the recent improvements and analyzing industry investment patterns. Similarly, Commenter 4814 proposed that a more practical option would be to base the standard on the latest coal technologies such as the CFBC or ultra SCPC. Commenter 9201 also discussed EPA's assertion that all new coal builds are designed with CCS in mind, stating that the majority seeking permits have since failed or switched to natural gas.
Commenters 10974 and 10975 stated that in contrast, CO2 emissions will increase due to the parasitic load associated with CCS.
 Post-combustion CCS is demonstrated in full commercial scale at Boundary Dam #3.  In response to comments urging that supercritical PC alone be BSER (e.g. comment 9201), see preamble section V.P.1.  EPA notes as well that it is fully aware of, and has considered the latest performance for supercritical and ultra-supercritical boiler performance. Id.  This technology forms part of the basis for the BSER determination.  In addition, highly efficient SCPC with natural gas co-firing is an alternative compliance pathway to achieve the standard of performance.  The EPA has also carefully evaluated the issue of individual plant energy requirements due to parasitic load, and found them to be reasonable.  See preamble section V.O.3.
Commenters 1959, 2864, 6870, 7433, 9194, 9317, 9320, 9396, 9422, 9425, 9678, 10082, 10083 and 10086 stated that CCS cannot be implemented in all parts of the country, particularly due to the availability of storage sites. For example, Commenter 10083 discussed the large distances between western power plants and suitable geological formations, and the potential for interconnectivity issues, environmental impacts, siting difficulties and project costs with increased distance. 
Commenter 10083 also stated that while saline formations may be suitable, they are not located near potential power plant locations and have not been characterized extensively. Commenter 8971 states that CCS selects winners and losers among states and areas. Commenter 9320 stated that EPA has failed to adequately consider the unique circumstances faced by sources in Florida with respect to the proposed standards for combined-cycle combustion turbines. Similarly, Commenter 2864 stated that only five to eight states have the means to capture and use CO2. Commenter 9422 asserted that an EPA regulation should not disallow the construction of power plants in large sections of the country simply due to the geological makeup of those areas.
Commenter 9396 provided an example of a DOE research project that assessed the ability store carbon in an aquifer and determined that the site was unsuitable and would have cost 1 million dollars per each of the 100 wells needed to secure the site.
Similarly, Commenters 1902, 6870 and 9194 discussed the misalignment of the majority of power plants with EOR opportunities. Commenters 6870 and 10082 further noted that transporting large quantities of CO2 is not easily addressed financially, technically or legally. Commenter 10086 stated that EPA failed to account for the lack of transportation infrastructure and the environmental impact associated with developing a network of pipelines.
Commenter 10393 noted the legal and regulatory challenges to long-term sequestration. Commenter 10083 states that there are no planned projects in western states except for the HEC project in California.  
Commenter 10395 asserted that CCS will not be developed, even in areas with EOR and sequestration opportunities, until additional research dollars are invested to evaluate whether it is an available, effective, and commercially viable technology.  
 See Section V.M. of the preamble with respect to geologic and geographic availability, and V.N. of the preamble with respect to the legal and regulatory framework of GS. 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. The design, construction, operation, and safety requirements for CO2 pipelines have been proven. For other of those areas, coal-fired power plants are either not being built due to state law prohibitions 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.
Commenters 8966, 9597, and 10043 stated that the performance statistics of EPA-cited facilities indicates that CCS was installed on an extremely small scale, and that the technology itself is not effective at capturing carbon to levels necessary to comply with the proposed standard. Commenter 8966 then discussed NETL data on Warrior Run, indicating that CCS only resulted in a 7 percent reduction and was still in excess of the proposed emission limit. Commenter 8966 also discussed Shady Point and Barry Plant's excess emissions even after capture and the small scale of Mountaineer Plant's CCS, all of which indicate that CCS has not been demonstrated show adequate effectiveness and reliability to support a BSER determination. 
See preamble sections V.D and V.E.  Preamble section V. G.3 also explains why pilot scale performance of CCS can be scaled up, and further supports the EPA's determination that CCS is a demonstrated technology.
Similarly, Commenter 9666 stated that none of the material cited by EPA, most of which have utilized only portions of CCS technology, demonstrate that the emission levels can be met.
 See preamble sections V.D and E. as well as preamble sections V.G.1 and 2.
Commenter 9326 stated that the data that EPA relies upon is an insufficient sample size. The commenter also stated that EPA presumes all new coal fired EGUs will be IGCC and recommended that EPA use CCS performance data on PC fired units as opposed to IGCC.
 The final BSER determination in fact is based on SCPC utilizing partial CCS.
Commenter 9472 provided a list of reasons and references why CCS is not adequately demonstrated by discussing how EPA's cited projects do not demonstrate integration of all CCS components and are not economically viable, and by citing references listing the costs per kilowatt hour and overall cost increase of CCS. The commenter further added that without second generation CCS, the technology is unlikely to be economically viable or commercially available.
Similarly, Commenter 9194 stated that the pilot projects do not demonstrate that CCS is widely useable nor technically and economically feasible for all 50 states. 
Similarly, Commenter 8024 discussed the cost and energy penalties associated with the first generation captured technology, as reflected in the Carbon Sequestration Leadership Forum 2013 Roadmap.  Commenter 8027 stated that high purity CO2 capture may not be available for 5 to 10 years and have not been adopted and validated.
See preamble sections V.D and V.E.  Energy penalty issues are addressed in preamble section V.O.3.  Although the EPA is not relying principally on pilot scale performance to show that CCS is a demonstrated technology (comment 9194), that information is nonetheless probative and corroborative of the EPA's determination.  See preamble sections just cited.  Commenter 8027 is completely mistaken that high purity CO2 capture is not presently available.  Food-grade CO2 has been recovered and utilized for over a decade.  See preamble section V.D.2.b (at the 320 MW Shady Point Plant, a plant that burns a blend of bituminous and subbituminous coals, CO2 from an approximate 5 percent slip-stream (about 66,000 metric tons of CO2 per year) has been captured since 2001. The captured CO2 from the Shady Point Plant is also sold for use in the food processing industry.)
Commenters (2470, 2864, 3107, 3176, 3236, 4710, 4814, 8024, 8906, 8971, 9196, 9396, 9397, 9401, 9472, 9661, 9683, 9767, 9780, 10046, 10082, 10086, 10098, 10294, 10391, 10518, 10618, 10952, 11051 and 11052) stated that CCS has not been adequately demonstrated in EGUs and is cost-prohibitive. Commenter 10391 further stated that "even if it were an adequately demonstrated technology, CCS is not remotely feasible and sustainable for coal-fueled power plants in most of the states".
Commenters (1899, 9396, 9661, 9683, 9780, 10086, 10098, 10618, 10662 and 10952) also stated is underdeveloped with respect to legal and logistical aspects of capture, shipping, and storing CO2. Commenters 9683, 9666 and 10096 also provided several quotes stating that CCS is not adequately demonstrated. 
Commenters 3107, 8906, 9196, 9320, 9396, 9497, 9661, 10096, 10952, 11051 and 11052 asserted that the proposed rule is effectively a ban on new coal. Commenter 10046 stated that compulsory CCS will not work, and cited a 2012 UKERC report stating that mandating CCS now will likely shift investment to less risky power generation technologies, and that it will not be easy to identify when the time is right to mandate CCS. The report also states that "CCS should arguably apply to existing plants too as climate change targets begin to bite".
Commenter 9320 discussed Sierra Club v. Costle, which indicates that EPA may not establish standards that preclude the construction of new coal. 
 Recent assessments are at odds with these commenters' assertions.  See, e.g. Global CCS Institute, "The Costs of CCS and Other Low-Carbon Technologies 2015 Update" (July 2015) at p. 1: "CCS is a cost competitive power sector emissions reduction tool when considered among the range of available low and zero emissions technologies ....Significant cost reduction are also expected for CCS technologies with increased deployment".  This conclusion reflects studies of Lazard (2014); EIA 2014; IPCC 2014; Brookings 2014; EPRI 2013; IEA 2012; and NREL 2015.
Commenters 8923, 9780, 10095 and 10103 discussed the differences between the Synthetic Natural Gas commercial-scale Production Plant and an EGU (e.g., heating step, the catalysts and stream compositions). Commenters 9780 and 10095 stated that EPA has provided no data to indicate the facility could continuously achieve the proposed standards. Furthermore, Commenter 10095 asserted that EPA must ensure that the CO2 is subpart RR compliant. Commenter 10395 further noted that a Synfuels plant does not demonstrate the viability or cost effectiveness of IGCC.
See preamble section V.E.2.a.  High purity CO2 has been captured successfully using CCS.  See, e.g. preamble section V.D.2.b.
Commenter 9666 stated that EPA relies on a 2011 cost and performance report by NETL that merely assumes the performance of various CCS configurations and is not supported by any technical or statistical analysis of emissions data from units implementing CCS because no such data exist.
 Costs for post-combustion CCS reflect the most recent available vendor quotes for the Shell Cansolv compression and capture process  -  the process in use at the Boundary Dam facility.  
Commenter 10665 cited the 2011 NETL Carbon Sequestration Program Plan stating that CCS will not be commercially viable until 2020. The commenter then stated that that if CCS is not commercially viable it cannot be considered for BACT.
 This comment refers to a study evaluating full CCS, which is not BSER.  
Commenters 0588, 1902, 2864, 7977, 8024, 8925, 8949, 8966, 9033, 9034, 9191, 9197, 9326, 9381, 9382, 9425, 9426, 9596, 9602, 9666, 9648, 9683, 9734, 9780, 10036, 10043, 10046, 10050, 10083, 10085, 10087, 10098, 10100, 10137, 10239, 10618, 10660 and 10880 also discussed how the plants and projects assessed by EPA (e.g., TCEP, HECA, Kemper, NRG's project) are not operational yet or do not have operational data at the commercial scale for adequate demonstration. Commenter 8501 stated that the experimental and development projects underway do not support an adequate demonstration finding. However, Commenter 8925 stated that the individual processes of CCS have been demonstrated, some of which for significant time periods.
Commenter 10618 discussed CCPI's initiative to accelerate development and minimize the cost of CCS and noted that none of the CCPI projects have been completed, indicating that CCS is not yet adequately demonstrated. Commenter 9780 also discussed CCPI and concluded that if and when operational, these projects might demonstrate the technical feasibility of CCS, but would not address the commercial viability of the technology given the significant funding that they have received as a result of their participation in the CCPI program.  Similarly, Commenter 8024 stated that the few U.S. energy facilities that EPA uses to support its finding that CCS is adequately demonstrated are all in various stages of construction, and all rely on government financial support.  The commenter further stated that even the projects with federal aid are encountering difficulties with project financing and power sales. Commenter 10043 stated that EPA's cited projects are unique with respect to location and financial situation and do not demonstrate representativeness. 
Commenter 9427 stated that none of the four projects cited by EPA in the preamble as a basis for BSER for a coal-fired electric utility steam generating unit (Kemper County Energy Facility, Sask Power Boundary Dam Project, Texas Clean Energy Project, and Hydrogen Energy California) has produced any electricity, captured any carbon dioxide, or sequestered any carbon dioxide, therefore, none of the four projects has "adequately demonstrated" the ability to meet any lb CO2/MWh emissions standard such as proposed and cannot serve as a basis for BSER.  According to Commenter 9425, even if these units eventually become operational, several years of operating experience would be required to support any conclusions about CCS, and projections by several organizations and agencies do not expect CCS to be commercially available until about 2020. Commenters 8348, 9666, 9734, 9780 and 10137 also stated that years of operation and research will be required before technologies can be fairly evaluated on a technical and economic basis with regard to uncertainty, representativeness and risk. Commenter 9201 stated that evaluating the feasibility of CCS for applicability to the array of fuels and sites that typify dedicated power generation facilities in the U.S. will require at a minimum, operating data over several years from at least eight utility-scale projects, similar to the process in which FGD and SCR systems were developed over numerous years and demonstration projects.    
Commenters 8348, 8949, 8966, 9034, 9381, 9382, 9648, 9666, 9734, 9780, 10046, 10098, 10239, 10618 and 10662 also stated that the proposed rule provides no information as to how pilot-scale projects advanced the reliability, efficiency, cost, and commercialization of CCS and further, EPA has not taken the economic setbacks, cancellations or delays encountered by the projects into account. Similarly, Commenters 8971 and 9596 disagreed with extrapolating from pilot scale data to commercial scale regarding the use of CCS to a nationwide-applicable CO2 NSPS. Commenter 8024 cited CPS energy's press release on their decision to allow the TCEP power purchase agreement to expire as support for the economic realities of CCS.
Commenter 10662 stated that all of the projects in the Global CCS Institute's database cited by EPA have some element which eliminates it from consideration in the context of the proposed rule and discussed reasons for several of the projects. Commenter 9780 also added that many of EPA's cited projects separate CO2 from other gases as part of normal operations which decreases the implementation cost and technical difficulty.
 Commenter 10033 stated that while they do not believe the technology is not well understood at the scale required for commercial power plant implementation, the commenter does not wish to suggest that CCS cannot or should not go forward in an appropriate manner or that the process cannot be done safely. 
Commenters and 9596 and 9602 further added that no power plant currently utilizes geologic sequestration. Commenter 9596 stated that facilities which are not utility scale EGUs do not demonstrate CCS with geological sequestration.
Commenter 9033 remarked that CCS has yet to reach demonstration stages to reduce the cost and reduce the risk of scaling these technologies from pilot or validation scale to full scale. The commenter presents several integration issues that have not been assessed at full scale, such as how the capture process turns down with generation load, how compression is affected by reduced load, what the management practice for water and flue gas byproducts will be, and risk of shut down. Commenter 9033 further asserted that without full scale demonstration, the industry is not in a position to make proper commercial warranties and guarantees as required.  
For discussion of why partial CCS is a demonstrated technology, see preamble sections V.D. and E.  Commenter 10618 noted that many of these plants receive, or have received government subsidies.  The need for subsidies to support emerging energy systems and new control technologies is not unusual. Each of the major types of energy used to generate electricity has been or is currently being supported by some type of government subsidy such as tax benefits, loan guarantees, low-cost leases, or direct expenditures for some aspect of development and utilization, ranging from exploration to control installation. This is true for fossil fuel-fired, as well as nuclear-, geothermal-, wind-, and solar-generated electricity.  Moreover, this issue does not relate to whether the technology is technically feasible and demonstrated.  We further note that this same commenter publically stated that CCS represents a path forward to an energy future where coal continues to be a utilized fossil fuel ("AEP still believes the advancement of CCS is critical for the sustainability of coal-fired generation.").  
Issues relating to pilot plant performance are addressed in sections V.D. and V.E as well as V.G.3.

Commenter 9596 is mistaken that there has been no geologic sequestration of CO2 captured from an EGU.  Boundary Dam sequesters CO2 it fails to sell for EOR, and the EPA has issued permits for Class VI wells for the FutureGen EGU facility, premised on findings that the facility's CO2 emissions can be successfully captured, transported, and sequestered for geologic time frames.

Regarding commercial guarantees for CCS, see preamble section V.F.

Commenter 10662 states that international experience with CCS does not show that the technology is demonstrated.  The comment is mistaken both factually and legally.  Section 111 (a) does not restrict EPA to data from domestic facilities only. 
Boundary Dam, a full scale commercial facility operating full CCS successfully, thus is an appropriate facility to look to as showing that CCS is a demonstrated technology.  See Sierra Club v. Costle, 657 F. 2d at 364 (support for achievability of section 111 standard of performance comes, in part, from operation of Japanese sources using the BSER); Lignite Energy Council v. EPA, 198 F. 3d at 394 n. 3 (section 111 (b) standard of performance justified in part based on data from "foreign boilers burning lignite").  Additional international facilities discussed in preamble section V.E.2.b provide corroborative information with respect to pre-combustion CCS (not the BSER but a potential alternative compliance pathway), and further indicate world-wide interest in the technology, and willingness to invest in it.
Commenter 9666 remarked that EPA has failed to identify and assess the impacts of conditions that could affect a unit's CO2 emissions, such as differences in types of fuel combusted and load duty. 
 The EPA has carefully assessed both the performance of fossil-fired EGUs using different types of coal, and the cost and energy implications when different coal types are used.  See preamble section V.J.
Commenter 9201 asserted that the lack of actual data from facilities in commercial operation has caused EPA not to adopt numerical standards.
The final standard of performance is a numerical level, as was the proposed standard of performance.  
Commenters 9472, 9592 and 10952 asserted that the proposed BSER does not address the lack of available infrastructure needed to transport, sequester and monitor the CO2 captured by coal-fired EGUs, such as CO2 pipelines and deep well sequestration or EOR fields, and therefore CCS cannot be considered a best "system" of emission reduction. Similarly, Commenter 9596 stated that EPA has not adequately demonstrated the transportation and sequestration components of CCS.
Commenters 10952 and 10097 stated that it is unclear whether carbon sequestration or EOR is included as part of the system that defines BSER or whether carbon capture fully comprehends the system in BSER.
The transportation and storage of CO2 is adequately demonstrated. See preamble section V.M., which discusses the existing processes, technologies, and geologic conditions that enable successful geologic sequestration and section V.N., which discusses the comprehensive, in-place regulatory structure that is currently available to oversee GS projects and assure their safety and effectiveness. 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.
Commenter 8957 discussed the Boundary Dam project a FutureGen 2.0 and concluded that additional experience across a range of geologic formations and other site-specific conditions as well as additional information on cost is necessary to make a determination that CCS has been adequately demonstrated. Similarly, Commenter 10395 stated that Boundary Dam is not an IGCC project and does not support EPA's contention that IGCC with partial carbon capture is BSER for coal-fired units.
In the United States, the EPA has issued Class VI UIC permits for six wells for two projects. EPA considered, among other information, information on the regional geology and local geologic features at each site as part of its permitting process to determine that the wells were appropriately sited and met the Class VI requirements. Additionally, there are several large scale CO2 sequestration projects including the Illinois Basin Decatur Project and the Cranfield (Tuscaloosa) Project that demonstrate that storage of large amounts of CO2 can be achieved. In April 2015, DOE announced that CCS projects supported by the department have safely and permanently stored 10 million metric tons of CO2, which is the same order of magnitude expected for an EGU. Furthermore, existing commercial CCS facilities in other countries demonstrate the commercial storage of CO2, and the ability to inject large quantities over long period of time. The CO2 streams from these facilities have physical and chemical characteristics similar to pipeline grade CO2 that would be expected from an EGU so the source of the CO2 is not a factor in assessing the feasibility of long term secure storage. Commenters 9190, 9201, 9425, 9381, 9426, 9497, 9590, 9648, 9666, 9725, 9780, 10036, 10046, 10085, 10095, 10036, 10500, 10552 and 10680 stated that to adequately demonstrate the national feasibility of CCS technology, all components of EGUs with CCS must be demonstrated to work together at the commercial scale due to the complexity and scope of the processes. 
Commenter 9683 stated that CCS is not a BSER as there is not nearly enough experience with carbon capture at an appropriate scale and under the variety of circumstances necessary to reasonably determine that capture technology is adequately demonstrated.  Similarly, Commenters 8966, 9190, 9197, 9201, 9426, 9590, 9648, 9666, 9725, 9735, 9780, 10036, 10095 and 10036 stated that data from multiple integrated technology demonstrations using different conditions and configurations at commercial scale are needed (e.g., using different power systems, ranks of coal, different separation systems, locations and CO2 storage in a range of geologic formations). 
Commenters 10036, 10095 and 10500 further asserted that no projects referenced by the Agency are simultaneously producing electricity, capturing, cleaning, compressing, transporting, and storing large volumes of CO2 on a continuous basis, which is essential to the effective operations of a commercial plant and adequate demonstration. 
Commenters 1899, 8024, 8966, 9320, 9381, 9596, 9666, 9780, 10032, 10500 and 10082 also stated that EPA has not considered the unique technical issues or reliability obligations of EGUs when assessing the technical feasibility of CCS. For example, Commenter 9596 stated that non-EGU's are able to vent CO2 when it is not needed or accepted by EOR and are not subject to load shift response requirements or continuous operations. Commenter 9317 stated their concern that the rule will impede states' energy diversity and reliability.
Commenter 9190, 10032, 10552, and 10680 further stated that the proposed standard is not based on actual data and does not demonstrate that the proposed standard is consistently achievable.
 See preamble sections V.D. and V.E.  We repeat here the NETL (July 2015) recent assessment of the technology (p. 36): "The capture and CO2 compression technologies have commercial operating experience with demonstrated ability for high reliability."
Commenter 9666 further asserted that EPA has failed to engage in the necessary analysis to support a finding that a standard of 1,100 lb CO2/MWh is achievable for the industry as a whole under the full range of relevant conditions.
 Preamble section V.J. discusses why the standard is achievable under a range of variable operating conditions.
Commenter 10098 stated that the natural gas industry's experience with CO2 capture provides no basis for EPA's proposed conclusion in this rulemaking that partial CCS is BSER.
 The EPA's finding that partial CCS is part of the BSER (along with a highly efficient SCPC boiler) is based on operating experience involving combustion of coal, not NGCC.
Similarly, Commenters 9381, 9397, 9497, 9505, 10088, 10239, 10500 and 10662 stated that the unique characteristics that make Kemper the right choice for Mississippi cannot be consistently replicated on a national level and should not serve as a primary basis for new emissions standards impacting all new coal-fired power plants.  For example, Commenter 9497 noted that the gasifier technology used at Kemper does not work well for higher grade coals.
Commenter 1959 noted that another reason Kemper is not BSER because Kemper is only commercially viable because of a suite of financial incentives and public subsidies that are not available for new projects, including revenues from sales of CO2 at the plant for enhanced oil recovery which is not nationally available. 
Commenters 1959, 8349, 9381, 9382, 9396, 9505, 9734, 10239 and 10662 also discussed the cost increases, delays and regulatory issues that have affected Kemper, as well as EPA's other cited facilities in construction or planning phase, such as Boundary Dam, FutureGen and TCEP. Commenter 8949 discussed the similarities between process units in Kemper and Pinon Pine, which shut down in 2000 due to technical problems.  The commenter hypothesized that similar challenges may occur with Kemper because it is FOAK.
Commenter 10662 stated that questions remain regarding long term storage, venting CO2, and the source of the 65 percent capture target at Kemper. 
Commenters 9381 and 9396 also cited public statements from Alstom declaring that it does not consider CCS to be technically feasible at a commercial scale. Commenter 9396 also cited public statements from Mississippi Sierra Club opposing the Kemper plant.
Commenter 9382 also noted a mistake in the 2015 operations date listed by EPA for the NRG Energy CCS project. 
The EPA is not selecting IGCC as BSER, although IGCC with natural gas co-firing, or partial CCS, is an alternative compliance path.  See preamble section V.P.  Thus, Kemper is not directly part of EPA's primary support for the BSER determination.  The EPA has also explained that the cost overruns involved with the project are the result of management decisions which are very unlikely to be repeated elsewhere, since they involved decisions contrary to normal protocols.  
Regarding commenters' claims that CCS technology is likely to operate with poor reliability, Boundary Dam is operating "highly successfully" (in the words of the project developers, see preamble section V.D.2), Dakota Gasification has operated full CCS successfully for decades, and NETL (2015) characterizes the technology as having high reliability based on commercial operating experience.  Finally, in response to commenters 9381 and 9396, the EPA notes that Alstom has publically endorsed CCS as a reliable and available technology.  See preamble section V.F and V.I.2.c.  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.  But without clear policies in place outlining options for cost recovery, power generators are hard-pressed to invest in its continued refinement."  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."  
Commenter 9666 also discussed the Boundary Dam project and stated that it is located outside the country and cannot serve as an example of adequate demonstration for United States-based generators which face different operational and technical constraints because: it is not a project that a company would have taken in the normal course of commercial operations, it cannot be considered financially feasible, and it has encountered multiple delays.
Commenter 8024 discussed the total costs of the Boundary Dam project.  
Boundary Dam is operating highly successfully.  Section 111 (a) contains no bar on the source of information EPA can consider in assessing which systems of performance are adequately demonstrated.  Further, the project cost overruns related solely to the cost of the boiler, not the CCS system.  See Memorandum of conversation between Dr. Nick Hutson (EPA) and Mike Monea (SaskPower), part of the administrative record for this final rule.  
Commenter 8966 stated that a BSER determination must rely on some wholly independent grounds apart from any data gathered from a publicly supported facility under the Energy Policy Act. The commenter stated that in addition to Kemper County and Texas Clean Energy Project not demonstrating actual effectiveness or reliability with operational data, data from these facilities must be excluded from consideration in a BSER determination due to their public funding. 
Similarly, Commenters 9034, 9497, 9774, 10083, 10662, 10974 and 10975 stated that EPA should not have considered the federally funded facilities.
 EPA's determination is not solely, or mainly, premised on performance of facilities receiving funds under EPAct, and can be justified entirely without consideration of any such facility.  
Commenter 9515 stated that although the EPA's reading of the Energy Policy Act is reasonable, but will not insulate it from legal challenge.  Instead, the commenter suggested that EPA reference projects with individual components of CCS and state the partial CCS can be demonstrated even in the absence of projects funded by the Act through facilities such as Warrior Run, Shady Point, Searles Valley, Great Plains Synfuels and other international projects such as Sleipner and Schwarze.
See preamble sections V.D and V.E.
Commenter 10095 stated that they are optimistic that CCS may play a role in reducing GHGs in the future, but integrated CCS technology is still in the development and demonstration phase and much remains to be understood. Commenters 9326 and 10095 asserted that by prematurely requiring CCS, the proposed rule will hamper the technology's advancement. 
Commenters 9326 and 9497 asserted that the application of CCS to larger pulverized coal plants is not available or necessarily applicable with any reliability. Similarly, Commenter 8024 stated that four of the six projects cited by EPA utilize technologies not suited to pulverized coal. 
 See preamble section V.L. and V.I.4.  CCS is demonstrated for PC plants, notably at Boundary Dam #3.
Commenter 10095 also remarked that neither Kemper County Energy Facility or Boundary Dam CCS project will have completed even one full year of operation before EPA is statutorily required to finalize the rule, which will not provide the robust experience required for CCS technologies to be considered Adequately Demonstrated nor fully satisfy the requirements of this proposal regarding subpart RR.
The commenter (Southern Company) correctly states that Boundary Dam will not have completed a year of operation at the time of promulgation of the final standard.  Nonetheless, plant performance to date has been highly successful (in the words of the project developers), and CCS technology has operated reliably in many other applications (see preamble section V.D and V.E).  The EPA consequently believes it reasonable to rely on the operating performance of Boundary Dam as an example of demonstration of post-combustion CCS at commercial scale.
Commenters 8966, 10046, 10870, 10088 and 10952 stated that EPA and/or DOE have not found CCS to be viable on a commercial scale in recent statements and reports. Commenter 8966 also cited CRS' statement that there is no data supporting the effectiveness and reliability of CCS systems and therefore CCS does not meet the level of demonstration required by CAA Section 111. 
Commenters 8024, 9396, 10395 and 10952 further noted that EPA's Task Force recognized that up to ten full scale demonstration projects at EGU sites were needed to commercialize carbon capture technology and reduce costs from 80 percent, and endorsed a ten year timeline to complete needed commercialization. Commenters 9196, 9765 and 10662 cited the Task Force report and its conclusions that CCS is not ready for widespread implementation and is not demonstrated at the EGU scale.
Commenter 10395 questioned why EPA has departed from the Task Force milestones. Commenter 9396 further questioned how CCS can be NSPS if States have recently rejected it as BACT. Commenter 9774 provided examples of a State rejecting CCS as BACT and cited feasibility and cost as the reasons.
Commenter 8024 also cited the Task Force findings and the 2010 Guidance on BACT as evidence that CCS is not adequately demonstrated. 
 In response to commenter 8966 et al, DOE's latest published statement on CCS is that, based on commercial operating experience, it has "demonstrated ability for high reliability".  NETL (July 2015) p. 36.  
Commenter 9515 noted that the Task Force Report supports EPA's finding that there are no insurmountable technological barriers and provided support from a Pacific Northwest National Lab report that concluded that CCS is technically viable and deployed at large enough scales to support commercial development.
The EPA largely agrees with this comment.
However, Commenter 8024 cited the 2009 PNNL study's conclusions that CCS is technically viable, but stated that the study does not address cost or energy requirements, nor does it conclude that full scale CCS has been installed and integrated at an EGU. The Commenter also cited the BACT guidance white paper's statement that full scale CCS has not been installed and integrated at an EGU.
 See preamble section V.D.
Commenters 9197, 9596 and 10395 noted that because no full scale plants with CCS are operational, it is not possible to consider the technology adequately demonstrated or ensure that the technical configurations meet the duty cycle demands of base load EGUs, such as reliability and cost.
See preamble section V.D.
Commenter 9034 noted that although the SAB Work Group ultimately decided to withdraw its recommendation for further review, it encouraged EPA "to carefully monitor the post-rule reality to ensure that the technologies are feasible and available to newly constructed electricity generating units to meet the new standards." The commenter stated that the "post-rule reality," however, will show that CCS will remain infeasible and unavailable to coal-fired EGUs for the foreseeable future.
Commenter 9648 stated that their message is consistent with SAB's findings that the rulemaking would benefit from additional review. 
Commenter 9195 noted that the Science committee uncovered serious problems and unanswered questions with the scientific and technical assumptions supporting EPA's new power plant proposal when observing interactions between EPA and the SAB. 
 Commenter 9396 noted that the SAB has indicated that non-EOR sequestration has not been peer reviewed or adequately demonstrated and has requested an analysis.  The commenter stated that without an analysis of non-EOR sequestration, CCS cannot be designated as BSER. 
See response in chapter 2 addressing comments relating to the Information Quality Act.  The short of it is that these commenters are significantly misinformed.  First, the SAB was briefed in great detail on the Class VI rule as it was being developed.  Second, the SAB workgroup in its January 7, 2014 public letter stated that "while the scientific and technical basis for carbon storage provisions is new and emerging science, the agency is using the best available science and has conducted peer review at a level required by agency guidance."  Letter p. 3.  The full SAB endorsed this letter in their edits of Jan. 24, 2014.  (Commenter 9034 correctly notes that the SAB withdrew its recommendation for further review, but fails to note the Workgroup's finding of use of best available science and adequate and ample peer review.)
Commenters 8966, 9505, 9666, 9677, 10870 and 10088 also asserted that under the standard established in the case of Essex Chemical, CCS cannot be considered adequately demonstrated. Commenters 8966, 9497, 9666, 9677 and 9505 defined adequately demonstrated system as shown to be reasonably reliable, reasonably efficient, reasonably expected to serve the interests of pollution control without becoming exorbitantly costly in an economic or environmental way (see Essex Chemical), all of which CCS has not validated. Similarly, Commenters 10089 asserted that CCS is currently cost prohibitive and not demonstrated at the commercial scale EGUs. Commenter 10088 cited the cost issues with Kemper Plant as further evidence. Commenter 9677 stated that EPA does not cite any case law that supports deploying BSER in a source category that has never used the technology.
 A) The technology is demonstrated at full commercial scale, highly successfully.  See preamble sections V.D.2 and V.E.2.a;  B) In response to commenter 9677, performance of a control technology in another industry has long been recognized as a legitimate way to show that a technology is demonstrated.  See, e.g. Lignite Energy Council, 198 F. 3d at 934.  In any case, post-combustion CCS is demonstrated within the source category; C) the technology is not exorbitantly costly, and does not have collateral nonair quality environmental or health impacts.  See preamble section V.H and V.O.  The BSER determination here therefore satisfies the standard set forth in Essex and other opinions of the D.C. Circuit.
Commenters 9401, 9774, 10036, 10095, 10098, 10239 and 10952 stated that CCS cannot be NSPS if it has never been selected as BACT. Commenters 10239 and 10098 also discussed the BACT selection process which, the commenters asserted, accurately rejects CCS as BACT due to technical and economic feasibility considerations. 
Similarly, Commenters 7977, 9401, 9683, 10239, 10030 and 10662 noted that EPA's previously proposed rule on the same subject in 2012 did not consider CCS to be an "adequately demonstrated" and that there is not sufficient support to warrant a change. Commenters 9401, 9683 and 10239 technology therefore asserted that CCS as BSER is arbitrary and capricious. Commenter 9472 asserted that the current proposal is at odds with EPA's 2012 rulemaking proposal, which is still relevant because there are still no operating facilities or advancements in CCS.

Commenter 10083 discussed BACT limits and stated that since NSPS sets the floor for BACT and BACT has recently only required relatively inexpensive, small reductions in CO2, NSPS 'would be limited to requiring very modest emission limits not more stringent than previously adopted BACT'.
Commenter 9773 posited that if an NSPS more stringent than would be determined under BACT for the same source does not appear to be the intent of the CAA, why would there be a BACT program under the CAA?
Commenter 10662 also stated that the following EPA statement, 'this proposal does not have any direct applicability on the determination of Best Available Control Technology (BACT) for existing EGUs that require PSD permits to authorize a major modification of the EGU' directly contradicts EPA's determination that BACT can be no less stringent than NSPS. 
Comments regarding the relationship of individual BACT determinations and the standard of performance adopted in the final rule are at preamble section XII.C.  Commenter 10062 misconstrues EPA's statements:  a final standard of performance creates a BACT floor, but a proposal does not, as the EPA accurately stated.  Commenter 9773 that BACT determinations for the same source would be less stringent than the proposed NSPS, showing that an NSPS based on CCS is arbitrary.  There have been no such BACT determinations made by the EPA, or by states.  The closest example would be the (now discontinued) Wolverine project in Michigan, but the EAP proposed that this facility would not be subject to the proposed NSPS.
 With regard to the 2012 (withdrawn) proposal (commenter 7977 et al.), the EPA stated that "CCS is a feasible technology option for new coal-fired power plants because CCS is technically feasible and sufficiently available in light of the limited amount of new coal-fired construction expected in the foreseeable future."  77 FR at 22414.  Commenters 7977 et al. consequently do not accurately characterize that proposal, which in any case, has been overtaken by events, including the re-proposal, plus full scale successful operation of CCS at commercial scale. 
Commenters 9683, 10086, 10087 and 10391 cited Portland Cement Ass'n v. Ruckelshaus and stated that EPA has not demonstrated that CCS is available for installation or at a reasonable cost. Commenter 10391 also stated that the proposed rule oversteps the Congressional intent of the NSPS.
Similarly, Commenter 10870 cited Portland Cement Ass'n v. Ruckelshaus and Sierra Club v. Costle when stating that EPA must evaluate the "demonstration of commercial-scale systems". 
Commenters 9596 and 10046 cited the District of Columbia Circuit's Sierra Club decision that rejected dry scrubbing as an adequately demonstrated technology and noted that this proposed rule is similar (or less robust) due to the lack of commercial scale operating data. 
Commenter 10087 also cited National Lime Association v. EPA, finding that EPA must consider "the representativeness for the industry as a whole of the tested plants on which it relies.
Commenter 8024 cited Lignite Energy Council v. EPA in stating that EPA may not rely on unbuilt facilities or conjecture to document adequate demonstration.
 See preamble sections V.D (demonstration of post-combustion CCS), V.H and V.I (availability of BSER at reasonable cost), and V.G.1 and 2, noting how the standard of performance is consistent with applicable caselaw, including Portland Cement I, and Lignite Energy Council.
Commenters 9514, 9660, 9664 and 10108 provided projects (e.g., Warrior Run, Plant Barry, a North Dakota gasification facility, Coffeyville gasification, and a 200 mile pipeline for EOR in Canada), vendor statements, reports (e.g., DOE/NETL reports) and articles for the Agency as support for its final standards that EPA that integrated CCS is adequately demonstrated, that EPA amply established integrated CCS systems will be available for commercial application on coal-fired power plants, and that the component elements of these systems have been in long-standing use in other similar industrial applications in the U.S. and abroad. Commenter 10108 further stated that the evidence is considerable more extensive than past NSPS, such as the SO2 BSER and supports EPA's determination. Commenter 10869 also stated that the component elements are commercially in use.
Commenter 9660 cited the Global Carbon Capture and Storage Institute 2014 report as further support. Commenter 9664 further stated that CCS is necessary in order to control anthropogenic CO2 in a timely enough manner so as to avoid the worst climate impacts.
 The EPA largely agrees with this comment.  The EPA also notes that the Global CCS Inst report (2015, the successor to the version cited by the commenter) finds 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), and provides LCOE estimates using a common methodological framework which are consistent with those of other recognized expert entities with respect of cost of full CCS and cost of nuclear power.  The study also presents estimates for the various technologies, including nuclear, as a range, again consistent with the approach of other entities.  See preamble section V.I.2. b through e.
Commenter 9514 provided a list of CCS projects using pre-combustion and post-combustion technology at commercial scale for decades in other applications. Commenter 9660 discussed pre-combustion, post-combustion and oxyfuel combustion technologies that have been implemented and stated that EPA has correctly determined that CCS is a feasible compliance alternative with a 30 year averaging period. Commenter 9660 also cited literature and projects which demonstrate separation, capture and storage of CO2, such as Sleipner, In Salah, Weyburn, Illinois Industrial Capture and Lost Cabin projects.
 The EPA agrees with much of this comment, although noting that pre-combustion CCS is not part of the BSER and that the final standard of performance does not have a 30-year compliance averaging period.
Commenters 10048 and 10095 stated that the high cost of the CCS technology effectively precludes its deployment even if the outstanding technical limitations, such as a lack of integrated, commercial scale demonstration, could be addressed and the technology was ready for commercial deployment. Commenter 10048 noted that the 2013 NETL report acknowledged that CCS is not ready for implementation at coal-fired power plants. Commenter 10095 also stated that a CO2 emission limit based on this technology is not achievable as required under Section 111(b).
 See preamble V.H. and L.  See also statement of American Electric Power that CCS can be coal's means of perpetuation ("AEP still believes the advancement of CCS is critical for the sustainability of coal-fired generation").  The NETL (2013) report was not in the context of partial CCS, and in any case, NETL (2015) finds that CCS is highly reliable based on its record in commercial application.
Similarly, Commenters 9034, 9765 and 10396 cited a 2013 OMB comment questioning EPA's finding that CCS is adequately demonstrated based on projects yet to operate. Commenter 10294 stated that EPA's disregard for the OMB is troublesome.
The final standard of performance reflected interagency review pursuant to EO 12866.
Commenter 10039 asserted that EPA's proposal that the CCS BSER is undercut by the recent release of the Climate Change Report which describes CCS as not ready for widespread use.  Commenters 9196, 9396, 9472, 10087 and 10095 stated that the recent National Climate Assessment confirms that CCS is presently in the pilot/demonstration phases of operational hierarchy
 This report concerned full CCS, and also considered application to existing sources.  EPA has determined that full CCS is not the BSER for either new or existing sources.
Conversely, Commenters 9514 and 9664 stated that the public comments asserting that the NCA report questions whether CCS is ready to be deployed do not address or contradict anything on which EPA bases its BSER determination.
 The EPA agrees with these comments insofar as the reports concern full CCS and the BSER determination is based on partial CCS.
Commenter 10046 cited the 2012 IEA report entitled 'A Policy Strategy for Carbon Capture and Storage' to state that CCS is not currently cost effective or technically mature, and should be incentivized rather than mandated.
 NETL (2015) states (p. 36) that, based on commercial operating experience, CCS has "demonstrated ability for high reliability."  Global CCS Institute (2015), in a compilation of expert views and analyses, states 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).  See also preamble section V.F (vendor guarantees) and V.I.2 (reliability of NETL cost estimates).
Commenters 9514 and 9664 asserted that EPA is well within its authority to set standards that are technology-forcing, forward looking, and in the interests of long-term environmental benefit. The commenters stated that EPA is not constrained to establish new source emissions limits based on systems of emission reduction that are in "widespread use" (see Essex Chemical, 486 F.2d at 427-434 and Nat'l Asphalt Pavement Ass'n v. Train, 539 F.2d 775, 786.
 The EAP largely agrees with this comment.
Commenter 9660 cited Lignite Energy Council v. EPA, 198 F.3d 930, 933-34 (D.C. Cir. 1990)  and Weyerhaeuser Co. v. Costle, 590 F.2d 1011, 1054 n.70 (D.C. Cir. 1978) to support EPA's rule and state that EPA's reliance on the successful implementation of various components of CCS at a small scale is consistent with previous NSPS. The commenter also stated that adopting CCS as BSER encourages further development and implementation of the control technology as Section 111b intends.
 The EPA largely agrees with this comment.
Commenter 9514 stated that they support EPA's conclusion that geologic sequestration of CO2 is available and adequately demonstrated for the purpose of establishing CCS as BSER for coal-fired EGUs and agree that site characterization of each potential storage site is essential to ensure safe and permanent storage. Similarly, Commenter 10106 agreed with EPA's conclusion that CCS is BSER and technically proven. Commenter 9513 also agreed with EPA's conclusion and stated that technologies demonstrated in the oil and gas sector are transferable, as supported by the Joint Environmental Group comments.
The EAP largely agrees with this comment.
Commenters 9471 and 9666 stated that they do not believe CCS will become commercially available for full-scale application to EGUs in 7 years and therefore, the proposed BSER is incorrect. Similarly, Commenter 2864 stated that it will be five to ten years before the technology is commercially available and cost-effective. The commenter stated that once facilities are operational, cost and feasibility can be evaluated. Commenter 9196 cited a DOE report that stated that CCS is 20 years away from commercially availability.
Commenter 9666 also listed Alstom, Congressional Research Service, U.K. Ministry for Energy and Climate Change, International Energy Agency, and DOE as entities that have stated it will take until at least 2020 to determine if CCS is commercially proven and a technology deemed "best system of emission reduction" of CO2 is shared by other governmental and regulatory agencies.
 These commenters are referring to full CCS being available as a retrofit technology.  The BSER determination for new sources involves neither of these.  With regard to Alstom, the EPA notes Alstom's public statements that CCS works, that it is cost effective, and also notes that Alstom has provided public cost estimates for CCS consistent with those of NETL.  See preamble sections V.F.3 and V.I.2.c. 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.  But without clear policies in place outlining options for cost recovery, power generators are hard-pressed to invest in its continued refinement."  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."  
Commenter 10085 proposed that EPA rely on subsequent statutory reviews of the final rule to determine when CCS becomes adequately demonstrated and ready to incorporate into NSPS.
 The EPA has reasonably determined that partial CCS, with a highly efficient SCPC, is BSER now.
Commenter 9666 stated that a facility in the planning or construction stages provides no evidence that CCS can operate reliably or efficiently, no accurate evidence regarding the cost as costs may continue to rise substantially until construction is complete, and no guarantee that it will reach completion and become operational.
See preamble sections V.D and V.E explaining operating facilities show that CCS is a demonstrated, effective, and reliable technology.
Commenter 10095 stated that pre- and post-combustion CCS demonstration projects are technologically different, are not interchangeable, not demonstrated at the commercial scale, and thus, cannot be comingled to justify partial CCS as being Adequately Demonstrated. The commenter further asserted that EPA cannot claim an emission standard based on partial CCS provides equivalent levels of operational and design flexibility without properly analyzing the potential for pre- and post-combustion CCS applications because the flexibility, if any, will clearly be different.
The EPA is considering post- and pre-combustion CCS independently, and also assessing costs of each independently.  See preamble sections V.D. and E. and V.H.4., 5. And 7.
Commenter 9666 remarked that EPA's only achievability analysis is based on its estimates of CCS performance using pre-combustion CO2 separation technology, which can be implemented only at IGCC units. Therefore, the commenter stated that EPA has not demonstrated that the proposed NSPS is achievable for units firing PC.
Similarly, Commenter 9486 stated that EPA's examples only include coal gasification facilities, not standard coal fired plants. 
 See preamble section V.J.
Commenter 9666 discussed the difference between commercially availability and commercially proven, and stated that the evolution of a control technology from FOAK to NOAK is unchartered and includes significant economic and technological risks. Similarly, Commenter 9597 stated that because no one has experience designing, installing and operating an EGU with CCS, the risks will be too great to build a new coal plant. Commenter 9426 further commented that there are several types of capture systems, each of which must go through FOAK before reaching NOAK costs.
 Post-combustion CCS is successfully demonstrated at the Boundary Dam facility.  Vendors are actively promoting the technology, using cost estimates consistent with those estimated here.  See preamble sections V.F. and V.I.2.b.  
Commenter 9593 stated that EPA's proposal ignores the difference between showing that a control technology is adequately demonstrated and establishing an associated emission limit that is achievable. The commenter noted that EPA is proposing partial CCS as BSER despite the successful deployment on an EGU in a full scale operation, and EPA's reliance on case law to support this determination ignores that the cases that have reviewed past NSPS standards have not involved a BSER determination that had not been deployed at all on operating sources in the source category.   
CCS is deployed on operating facilities.  The commenter is mistaken as a matter of law that a BSER must be deployed on all operating sources, which would indeed defeat the whole purpose of a new source standard which is to reflect best system of emission reduction, not some type of least common denominator.Commenter 0775 noted that one of the five planned coal plants listed in the EIA database does include CCS, but that project, Medicine Bow Fuel & Power LLC, is not a power plant and may not need post-combustion CCS in order to capture and store its carbon emissions.
A source which is not a power plant is not an affected EGU, and so is not subject to the promulgated NSPS.
Commenter 9396 stated that EPA is imposing a requirement that dictates the combustion and control technology, which would generally be collaborative decided by State public utility commissions, municipal utility commissions, and cooperative boards and associated electric utilities, through the Integrated Resource Planning (IRP) process taking into account local conditions and multiple factors to make the critical choices of what type of plant to build and what fuel to use. 
The EPA is not requiring sources to use a particular technology, nor does the final standard of performance force use of a particular technology.  There are a variety of potential compliance alternatives available, including IGCC with natural gas co-firing, and SCPC with natural gas co-firing.
Commenter 9195 provided the following list of questions for EPA:
a. Are any of these 12 projects a full-scale, base-load electric power plant?
b. Do any of these 12 projects currently have a final Class VI well permit?
c. For each of these 12 projects, please provide:
A general description of the project, its location, and the electric generating capacity of the project, and the specific type of fuel the project uses; The approximate date any planning initially began for the project or a previous iteration of the project; The current status of the project, Estimated completion date of the project; Planned operating life of the project.; A technical description of the capture technologies, including detailed disclosure of any chemicals used in these systems; Documentation of any commercial guarantees for capture technologies used in conjunction with any projects receiving federal funding; Volume of C02 currently captured; the annual volume of C02 anticipated to be captured when fully operational; and the total volume of C02 anticipated to be captured over the lifetime of the project; Explain where, how, and under what regulatory and reporting systems the C02 will be stored; The total federal, state, or municipal financial assistance the project has received or anticipates obtaining. Please include any grants, tax incentives, loan grantees, or rate recovery mechanisms;  Explain the parasitic load factor of the entire carbon capture, compression, transport, and storage system. Explain how this impacts the efficiency of the project as compared to the project without CCS; Explain how the project foot print is impacted by the CCS system; Provide the percentage of the overall cost of the project that is predominately related to the CCS portion of the project; List any objections made to the project by any stakeholders, environmental groups, NGOs, or other individuals. Provide petitions for any challenges or objections that are currently pending. For any objections that have been resolved, provide concessions or alterations made that allowed the project to move forward. 
d. isn't there a difference between demonstrating the components of CCS and demonstrating CCS as a fully integrated system?
e. How does EPA explain these apparent inconsistencies between EPA's finding and EPA-cited and co-draft studies?
f. Please identify all: 
Post-combustion coal projects EPA has cited or is aware of; Post-combustion natural gas projects EPA has cited or is aware of; Pre-combustion CCS projects currently capturing and storing C02 at coal power plants that EPA has cited or is aware of; Pre-combustion CCS projects currently capturing and storing C02 at natural gas power plants that EPA has cited or is aware of; CCS power plant projects proposed or under construction that EPA has cited or is aware of; Other non-power generation CCS projects currently capturing and storing C02 at the same scale that would be required in the power generation context- at least 1,000,000 tons C02 per year. How long has any such project been continuously capturing, injecting, and monitoring at this scale? What legal and regulatory systems are any such projects operating under? 
 See preamble sections V.D. and V.E.  The EPA has issued six class VI permits to date, to Archer Daniels Midland and FutureGen.  Issues of parasitic load are addressed in preamble section V.O.3.
Commenter 8024 stated that, to date, Congress has not authorized programs to accelerate the large-scale commercial demonstration of CCS technologies beyond the relatively modest programs funded through the Office of Fossil Energy at the U.S. Department of Energy and as a result CCS has not adequately demonstrated.
 See preamble sections V.D. and V.E.
Commenter 9194 noted that every proposed NSPS,  except for this NSPS, had vendor performance guarantees at the time of the proposal.  Commenter 10046 also discussed the absence of vendor guarantees as an indication that CCS is not adequately demonstrated.
There are in fact vendor guarantees for CCS.  See preamble section V.F.
Promotion of Technological Development
Commenters 7977, 10098, 10618 stated that EPA mischaracterizes and overstates the technology-forcing nature of the NSPS provisions. According to commenters 10098, 10239, because CCS remains an emerging technology that cannot be effectively implemented today, EPA cannot require its use in coal-fired EGUs because the NSPS is effective upon proposal and not at some later undeterminable date when technological advances may occur. 
Commenter 7977 stated that the proposed rule sets a standard which forces the use of an experimental, currently infeasible technology, a factor that is not implicit in Section 111(b) of the CAA or explicit within the statute. The commenter stated that the proposed rule, which relies upon technology forcing to justify the proposed standard, exceeds relevant authority.
Commenter 10239 stated that nothing in section 111 or the EPA's implementing regulations mandates that the EPA must consider whether the system promotes the implementation and further development of technology.
See preamble section III.H.3.d and responses on this issue in chapter 2 of this RTC.
Commenters 1624, 9033, 9196, 9426, 9666, 9683, 9780, 10046, 10098, 10100, 10239, 10618, 10662 stated that the proposal will impede or stop CCS development. Commenters 9196, 9426, 9683, 10046, 10098 stated EPA's reliance on CCS in the proposed rule is likely to impede, rather than promote, the development of CCS technology because it will have the practical effect of preventing any new coal-fired EGUs from being built. 
According to commenters 9033, 9196, without new coal plants, it is unlikely technology developers will continue to invest in CCS development. The commenters noted that with decreased coal, there will be decreased R&D and investment into CCS technology. Commenter 9033 cites the slowing pace of private and public investment world-wide in CCS projects as shown in the annual survey of the Global Capture and Storage Institute. Commenters 9196, 10100 stated that increased costs associated with CCS for coal-fired EGUs and resulting increased electricity prices from such units would yield few, if any, merchant power companies or regulated electric utilities that are likely to invest in a new coal-fired power plant with CCS and as a result, CCS technology will not be developed, refined or improved so as to make it technologically or economically viable. Commenter 9780 stated that given current market realities, the key for driving CCS technology development at this point is not a regulatory requirement, but rather government financial assistance. The commenter concluded that without substantial federal financial assistance, no additional CCS projects on coal-based EGUs are expected to be built in the U.S., and, as a result, there will be no further CCS development. Commenter 9666 stated that EPA's proposed NSPS will have the opposite effect (to promoting technological development) by foreclosing further CCS demonstration projects at commercial power plants.  According to the commenter, a standard that requires all new coal-fired units to operate CCS cannot promote CCS if it simultaneously prevents the construction of any new coal-fired units, as EPA's proposed standard does. Commenters 9196, 9780 also stated that beyond the exorbitant costs of CCS, requiring new Subpart Da sources to use unproven technology to meet an unachievable emission limit with significant penalties for noncompliance will only discourage investment in these units. 
 See preamble section V.I.4.  We again note that AEP took exactly the opposite position in its earlier public statements on this issue, as did Alstom.
Commenter 10100 stated that the proposal will encourage the export of coal to China and other developing nations without creating incentives for commercialization of CCS to control coal-fired CO2 emissions.
 See preamble section V.I.4.
Commenter 9664 stated that the additional costs associated with moving the technology forward are justified and reasonable. The commenter cited the RIA noting that sequestration costs can be defrayed with the revenue of captured CO2 to EOR operations. According to the commenter, , it is relevant to the technology-forcing and forward looking aspects of section 111 standard-setting that the costs associated with CCS technology applications are expected to decrease over time.
 The EPA largely agrees with these comments, although we note that costs of the standard of performance are reasonable even if those costs are not defrayed by a facility utilizing EOR opportunities.
Commenters 9664 and 10108 cited Sierra Club v. Costle 657 F.2d at 341, 346-47 and S. Rep. No. 91-1196 (1970) at *16 noting that EPA can, and to be consistent with Congressional intent, must encourage emerging technologies through the form and structure of this standard. Commenter 10108 agrees with EPA's conclusion that the proposed NSPS will advance these goals by identifying CCS as BSER for coal-fired power plants, lowering the cost of the technology through learning-by-doing and encouraging further research and development by DOE/NETL, referencing SaskPower's investment in the Boundary Dam project that appears to be driven in part by Canadian carbon pollution standards for new and existing power plants. 
 See preamble section III.H.5.d.
Commenter 9514 stated that NSPS standards must be forward-looking and technology-forcing. Referencing Portland Cement Ass'n, 486 F.2d at 391 and  Essex Chem. Corp., 486 F.2d 427, the commenter stated that the "best system of emission reduction" need not be in actual commercial use in the regulated industry at the time the standards are initially set.  
 The EPA largely agrees with this comment.
Commenter 8925 stated that by requiring CCS, the proposed rule raises the hurdle substantially for companies interested in developing innovative coal technologies such as IGCC plants. The commenter noted that with significantly lower incremental costs of capture and lower heat rate penalties than pulverized coal plants, IGCC has been viewed as one key pathway forward on CCS, but there are only a few operating IGCC plants in the world so there is still much to learn about it. According to the commenter, experience-based cost and performance improvements for IGCC will not be possible under the proposed regulation without incurring the additional cost, time, effort and risk of deploying CCS.
 The standard of performance does not require use of CCS or any other technology.  We specifically note that IGCC with natural gas co-firing is a potential alternative compliance pathway.  The EPA consequently does not agree with this comment.
Commenters 9497, 10664 stated that the EPA's intention to promote CCS through the proposed rule goes counter to objectives and is a disincentive for the development of other technologies. Commenter 10664 stated that Congress did not seek to promote one technology over all others, and cited congressional testimony regarding the topic. 
Commenter 10239 stated that alternative control technologies are dismissed because they do not promote the development of CCS, which the commenter described as arbitrary, capricious, and unlawful for several reasons.
The final standard of performance can be met by any means of a source's choice, and there are alternative compliance pathways that do not involve use of CCS.
Commenters 9408, 9657 stated their concern that this rulemaking may become an insurmountable barrier to the prospective construction and operation of new coal-fired electric generation units, thereby compromising a desirable level of energy supply diversity in our nation and in our community. The commenters stated their lack of support for policies that mandate fuel switching, directly or indirectly, should be promulgated as a reasonable means of complying with an emission standard. 
Commenter 9426 stated that it is unlikely that electric generators would choose unproven CCS technology if a less risky alternative in NGCC is available. The commenter stated that it is difficult to understand how the proposal would somehow cause generators to pursue coal with CCS over NGCC
See preamble section V.I.4.
Commenter 9201 stated that EPA's rule does not incentivize technology and EPA's rationale is flawed. The commenter stated that there is no incentive to develop CCS, and additionally creates a disincentive by inducing construction of NGCC units that are not burdened with the costs and technological uncertainties associated with CCS. According to the commenter, the proposed rule does not induce better performance from NGCC and the standard is substantially higher than what can be achieved with the best existing technology. The commenter noted that they are not suggesting EPA mandate CCS for NGCC units, but simply pointing out inherent contradiction between the agency's reasoning for setting a standard for new coal plants based upon CCS and the standard for NGCC units. The commenter provided the analogy to DOE's incentive example for lightbulbs in which EPA would in effect be requiring certain manufacturers of light bulbs to become more efficient while exempting others. The commenter concluded that EPA's reasoning is an arbitrary decision and does not satisfy the legal requirements of CAA section 111. 
 See preamble section V.L. and V.I.4.
Commenters 9666, 10662 stated that any CCS-based standard unlawfully dictates the choice of technology that Subpart Da sources must use. 
According to commenter 9666, this violates section 111(b)(5) of the Act, which provides that nothing under section 111 shall be construed "to authorize the Administrator to require any new or modified source to install and operate any particular technological system of continuous emission reduction to comply with any new source standard of performance." The commenter noted that the proposed NSPS for Subpart Da sources could not be met with anything other than CCS.
Commenter 10662 stated that under CAA Section 111(b)(1)(B)(5), EPA cannot require any particular system of continuous emission reduction.
 The commenters are mistaken.  The final standard of performance is a numerical limit which can be met by any means a source chooses.  The EPA has further shown that there are alternative compliance pathways available which do not need to utilize CCS, which compliance pathways are also demonstrated, available at reasonable cost, and do not have collateral adverse environmental or energy utilization impacts.
Commenters 9666, 10662 stated that EPA cannot use section 111 to mandate the use of unproven control systems under the guise of "promoting technological development."   
Commenter 10046 stated that it is unlikely that Congress provided discretion in section 111(b) for EPA to impose a mandate that would retard development of the technology that EPA is trying to force. 
 See preamble section III.H.5.d. and other comment responses in RTC 2 on this issue.
Commenters 9666, 10046 stated EPA cannot select as BSER a technology that has not been adequately demonstrated based on an asserted interest in "promoting technological development." According to the commenters, requiring CCS will actually hinder its development by discouraging construction of new Subpart Da units. 
Commenter 10046 compared the EPA's FGD technology forcing NSPS with that for CCS, and noted that now, alternative fuels are available.
 The EPA has not selected a BSER solely to promote use of a technology, and its determination would be the same whether or not it considered this factor.  See preamble section III.H.5.d.
Commenter 9666 stated the effective way to encourage technological innovation is to provide developers with greater regulatory flexibility, as the D.C. Circuit recognized in Sierra Club by  allowing EPA to promulgate a less stringent flexible standard that could be met by units experimenting with promising (yet unproven) dry scrubber technology. 657 F.2d at 351.
 The final standard of performance in fact can be achieved a number of different ways of which the EPA is aware.
Commenter 9666 stated EPA provides no support for its assertion that "not identifying partial CCS as the BSER could potentially impede further utilization and development of CCS." 79 Fed. Reg. at 1480. According to the commenter, the Agency has identified several projects currently under construction or in development that plan to integrate CCS, despite the fact that those projects are not subject to any CO2 emission limit based on the use of CCS, and therefore it is unclear why EPA believes the current regulatory status quo that has led to these projects would impede other similar projects from being developed in the future. 
Commenter 9426 stated that the EPA contradicts itself by stating that few if any solid fossil-fuel EGUs will be built in the foreseeable future, and that a standard for new coal-fired EGUs based on partial capture "promotes deployment and further development of the technology."
Commenters 7977, 10662 stated that there is a distinction between technology forcing and encouraging technological innovation, and section 111(j) of the CAA specifically provides for the promotion, development, and deployment of innovative technological systems of continuous reduction for technologies like CCS that have not been adequately demonstrated. The commenter stated that, section 103(g) of the CAA provides EPA with the authority to conduct a basic engineering research and technology program to develop non-regulatory technologies and strategies.
Commenter 10046 stated that if the EPA's proposal will not promote the development of CCS technology, then EPA has no legitimate basis to proceed.
Commenter 10046 stated that the EPA should analyze whether the performance standard enhances or diminishes CCS technology or economic risk, or whether the addition of environmental compliance risk (requiring CCS) for one fuel (coal) but not the other (gas) does anything other than force companies to build gas units and avoid coal units. 
Commenter 10046 noted that the statue and applicable case law require EPA to set a different standard if in fact the standard it proposes to set would stymie CCS development. The commenter provided citations to support their statement.
The EPA's task is to identify a best system of emission reduction adequately demonstrated and to set a standard predicated on performance of that technology.  The EPA has done so here.  The final standard of performance will encourage new sources  -  indeed will compel them  -  to emit less CO2 than they would if doing business as usual.  Moreover, it is well documented that a regulatory requirement often brings a great influx of technological innovation.  See preamble section V.K. and L., and TSD documenting the history of technological innovation following the 1971 NSPS for this same industry.  We again note that AEP and Alstom, in prior public statements extolling CCS technology reliability and cost-effectiveness, indicated the importance of a firm regulatory framework to promote use of CCS.
Commenter 9201 stated EPA's assertions about the proposed rule's ability to incentivize technological innovation are not adequately explained in the face of the unavailability of CCS technology for commercial power generators. Thus, the commenter noted, EPA's decision to set CCS as BSER over other technologies that represent significant CO2 reductions and incentivize technological innovation of efficient coal generation is unreasoned and arbitrary.  
 CCS is an available technology.
Commenter 10048 stated that in the absence of environmental benefits, it appears that EPA's overriding reason for proposing the rule is to provide an incentive to promote adoption of CCS technology; however, as EPA is well aware, CCS is a complex, costly and legally challenging technology that will not be adopted when more cost-effective and less complicated generation alternatives are available.  
 As shown in RIA 4, new non-compliant coal technology is not being constructed, for reasons unrelated to this NSPS.  New coal capacity is a technology now being adopted as a means of preserving a diverse energy portfolio, or some other reason than lower cost.  The promulgated standard of performance preserves that alternative by leaving new coal priced competitively with other baseload dispatchable non-NGCC technologies. Moreover, should there be very significant increases in natural gas prices, there may be renewed interest in new coal plants. Issuing a standard that allows construction of new high-emitting coal plants without a CCS requirement therefore poses a nontrivial risk of increased emissions and further exacerbation to climate. Given their long lifetimes, construction of new high-emitting coal plants could lock in their higher emissions for many decades to come.  See preamble section V.K. 
Nationwide, Long-Term Perspective
Commenter 9735 stated that the proposed rule provides no graduated or realistic targets over the long-term, but rather immediately sets a low baseline emissions target that cannot currently be achieved on a large-scale or cost-effectively. The commenter further stated that it is necessary to encourage investment in advanced emissions reduction technologies while working toward CCS. 
 The EPA has reasonably determined that partial CCS, with highly efficient SCPC, is BSER now.  The EPA must therefore establish a standard of performance reflecting performance of that BSER.
Commenter 9664 discussed the authority of EPA to adopt standards and technologies without requiring a cost-benefit analysis at the plant level as long as the response to the problem and the pollution reduction benefits can be justified at the regional or national level through a broad assessment (see Sierra Club v. Costle, 657 F.2d. at 329-332, S. Rep. No. 95-127 (1977) and H. Rep. No.95-294 (1977)).
 The EAP largely agrees with this comment.
Conversely, Commenter 9666 stated that the Agency may not set an NSPS based on national-scale considerations if it would impose unreasonable costs, environmental impacts, or energy requirements at the individual plant level, rather that the CAA only permits EPA to consider long term effects once it has determined that source-level impacts are consistent with the statutory criteria for NSPS (also citing Sierra Club v. Costle, 657 F.2d at 330). The commenter suggested that EPA improperly focuses on the costs and effects of its CCS mandate on a nationwide, long-term scale at the expense of considering its effects on individual new sources.
 The EPA has considered both plant-level impacts and national impacts in its determinations here.
Commenter 9774 states that the NSPS for coal-fired power plants cannot be based on CCS at this time, and that EPA must correct the NSPS deficiencies and modify the rule to exclude sources that are inappropriately regulated in order to avoid significant issues within the utility sector, including possible delays in CO2 emission reductions.
 The EPA disagrees.  See preamble section V.
Commenter 9425 suggested that these regulations may force several power plants to shut down in a relatively short amount of time. The commenter remarked upon the need for states to have enough time to work with EPA to understand the impacts to fuel diversity and energy reliability in setting the standards, as well as the implementation and timing of the standards.
These standards apply to new sources exclusively, or to modified and reconstructed sources.  There is no question that such a source would be `shut down' when not yet in existence.
Similarly, Commenters 9201, 6429 and 9666 discussed the potential impact of CCS on diversity of fuel supply for the electric grid in terms of both reliability and affordability. Commenter 9666 also stated that although the EPA recognizes that protecting fuel diversity is important and that the costs of CCS will render construction of new coal-fired capacity infeasible under the proposed standard, EPA incorrectly assumes that the CCS mandate will not increase energy prices or change the structure of the energy sector.  Commenters 9201, 6429 and 9666 suggested that because coal will be uncompetitive with natural gas due to CCS, the grid will become less diverse, more susceptible to price spikes and disruptions, and it will be less certain that additional natural gas-fired capacity will reliably meet the basic demand for electricity. Commenter 9426 provided the price increases during the polar vortex as an example, and stated that the proposed standard will distort the true cost of natural gas. 
 Coal is already economically non-competitive with natural gas.  See RIA chapter 4.  See preamble section V.I.4. as to why basing a standard of performance on partial CCS will not discourage new coal capacity or use of CCS.  Again, AEP was of the considered public view that CCS represents a lifeline for the industry, not a millstone.
Commenter 10870 also stated its concern that the Proposed Rule will result in the elimination of coal from the nation's fuel portfolio rather than more fuel diversity, leading to less reliable and less affordable electricity as well as less effectively controlled sources of power generation needed for the economy. The commenter further asserted that uncertainty of additional requirements under Section 111(d) will effectively end development of coal-fired electric utility units unless the Proposed Rule is written to exclude any new requirements during the life of the plant.
The standard of performance adopted here does not apply to existing facilities.
Commenter 10048 stated that the majority of renewable energy options are not baseload resources. Additionally the commenter remarked that no significant new nuclear generation is planned, therefore fuel diversity can be expected to decrease.
Public announcements including IRPs confirm that utilities are interested in technologies that could provide or preserve fuel diversity within generating fleets. The Integrated Resource Plan TSD notes examples where the goal of fuel diversity was considered in IRPs; in many cases, these plans considered new generation that would not rely on natural gas. In particular, several utilities that considered fuel diversity in developing their IRPs included new nuclear generation as a potential future generation strategy. See also Global CCS Inst, "The Costs of CCS and Other Low-Carbon Technologies" (2015)p. 1 finding that "[n]uclear generation plant as well as hydro and geothermal platn can also be cost competitive ins ome markets fiven thei high utilisation rates (i.e. can be oeprated 80 to 90 per cent of the time)".
Commenter 9666 remarked that EPA incorrectly assumes in Section II that in the future, coal units without CCS will not be competitive with natural gas units not subject to CCS. The commenter further suggested that coal only becomes uncompetitive once a costly and undemonstrated CCS is imposed.
 See RIA chapter 4.
Commenter 9666 also stated that requiring CCS will not promote coal-fired generation by eliminating future obligatory controls uncertainty as EPA purports since this would be true of any final action EPA takes, regardless of the level of control chosen.  Furthermore, the commenter states that this rulemaking does not confer any advantage because any source that is subject to this proposed NSPS would not be subject to future NSPS controls or revised standards since the controls would apply only proactively, and sources could avoid falling under the revised standard by foregoing modification or reconstruction.
 See preamble section V.L and K. (documenting, among other things, the spurt in technological innovation after promulgation of NSPS based on FGC scrubber technology less well developed than CCS at a comparable point in the regulatory timeline), and see also statements of AEP that regulatory uncertainty was a factor in the decision not to proceed with the Mountaineer demonstration project.  
Commenter 9191 stated that each of the facilities cited by EPA involve unique circumstances that do not render CCS appropriate for nationwide application
The EPA disagrees.  See preamble section V.
Commenter 10052 stated that CCS is infeasible in much of the country due to pipeline capacity, site availability and demonstration projects. 
Similarly, Commenter 9408 stated that CCS will be particularly difficult to deploy in some geologic formations and implored EPA not to promulgate any standard that relies on CCS in those areas. For example, Florida has an artesian aquifer that underlies the entire State and is a source of potable water for every community in Florida. Because of the aquifer's relative importance, the commenter suggested that it is unlikely that subsurface CCS will ever be allowed in Florida, nor is the risk of potentially compromising the resource by injecting CO2 into it or through it acceptable. The commenter also suggested it is improbable that other State would accept Florida's CO2 emissions to be transported for permanent storage.
 See Section V.M. of the preamble and the technical support document on geographic availability. Potential GS formations are widely available in the United States. The EPA recognizes that geologic conditions to support CO2 storage may not exist in all regions of the country. Where such capacity is unavailable, electricity demand in those areas can be served by coal-fired power plants built in neighboring areas with geologic availability with generated electricity being supplied via transmission line, see Figure 1 of TSD on geographic availability, or the CO2 can be transported to available GS sites via pipeline. For other of those areas, coal-fired power plants are either not being built due to state law prohibition s against building such units, or other available compliance alternatives exist allowing a new coal-fired power plant meeting the promulgated NSPS to be sited. There are alternative means of complying with the final standards of performance which do not necessitate use of partial CCS, so any siting difficulties based on lack of a CO2 repository would be obviated.

The EPA notes that Figure 1 of the technical support document on geographic availability shows the areas of Florida that are within 100 kilometers of a potential GS formation; electricity demand may be served by coal-fired electricity generation built in areas that are proximate with geologic sequestration, and this electricity can be delivered through transmission lines.
Commenter 9426 stated that public education and communication between communities and potential storage project proponents is needed to move forward on a large scale so that landowners are comfortable with the process, monitoring and verification elements of CCS. The commenter provided fracking as an example of possible public reaction. 
 Public awareness and support have been widely recognized as critical components in the development of new energy infrastructure, including CCS deployment. Efforts have been made to design strategies for successful outreach to the public. For example, under the DOE Regional Carbon Sequestration Partnerships, DOE has been engaging with local communities to educate and inform them about planned pilot and demonstration projects in their areas. DOE's Best Practices for Public Outreach and Education for Carbon Storage Projects presents lessons learned through the planning and implementation of CCS projects, as well as best practices for community engagement. 
Commenter 10089 stated that given the currently sparse CCS market, the electric power sector would be compelled to work from ground zero to become compliant with NSPS. The commenter recommended that further analysis is necessary to ascertain whether CCS is indeed the best system of emission reduction for new power plants. 
 The EPA disagrees.  See preamble section V.
Commenter 0775 stated what while CCS may not meet desired cost and energy efficiency goals today, the regulation is a safeguard against coal as the dominant energy source and stimulates CCS technology.
 The EPA disagrees with this comment on every count.  Partial CCS is an adequately demonstrated technology within the meaning of section 111 (a) of the Act.  The objective of a standard of performance is to have new plants perform to a level achievable by the performance of the BSER.  It is not to be a safeguard against use of any particular technology, industrial process, or fuel source, and the EPA has no such objective here.
Energy and Nonair Quality Environmental Impacts
Commenters 9381, 9396, 9592, 9666, 9780 and 10100 stated that the subject has not been adequately assessed the as required by Section 111(a)(1). Commenter 9194 cited 1973 and 1999 court decisions requiring that EPA fully assess non-air and economic impacts.
Commenters 9194, 9381, 9592, 9780 and 10100 noted that additional consideration of environmental impacts of CCS, such as reduced energy efficiency, increased coal use, increased water withdrawal and consumption, increased water discharges, and increased emissions of criteria and toxic pollutants, is required by EPA to meet statutory obligations.
Commenter 9396 cited a 2013 NETL report discussing the significant energy, efficiency, water use, air emissions and cost impacts that could result from partial CCS. 
The EPA has carefully considered potential nonair impacts of the final standard of performance, as required by CAA section 111 (a)(1).  EPA has carefully considered the safety of transport and permanent sequestration of captured CO2 and has found reasonably that the regulatory structures of 49 CFR Part 195 (for CO2 pipelines), and Class VI and Class II injection wells (for geologic sequestration and EOR, respectively), with the further complementary monitoring and reporting standards of GHGRP subpart RR, assures safe transport and permanent sequestration.  EPA has also projected that, under a set of assumptions where new non-compliant coal-fired capacity is added,  there will be SO2 (and consequent secondary PM) reductions associated with use of partial CCS (due to the need for ultrahigh purity solvent).  See RIA chapter 5.3 and Table 5.1.   Issues of water use are addressed at preamble section V.O.2.
Commenter 9396 cited a NETL report to estimate that to meet EPA's proposed standard with an SCPC, it would require:
   *  a capture rate between 30 and 50%
   * an additional 180,000 to 300,000 tons of coal each year
   * a decrease in net fuel efficiency from 39% to 33-35% and heat rate from 8687 Btu/kWh to 9695-10379 Btu/kWh
   * an increase in water withdrawal of 16-30% and consumption by 14-26%
   * an increase of NOx, Hg, and PM by 2-7%
   * the capital cost by 26-39%
   * the operating cost by 30-43%
   * and cost between $79 and 102 per tonne of CO2 avoided.
The commenter asserted that these results indicate a full energy and environmental impact assessment is warranted and has not been conducted.
 These estimates reflect full CCS.  The final standard of performance has considerably reduced water use impacts, which the EPA has evaluated and found to be reasonable.  See preamble section V.O.2.
Commenter 9596 stated that EPA should withdraw the NPR in order to evaluate the potential impact of CCS on groundwater and other environmental factors because the current proposal is arbitrary and capricious, and not in accordance with the requirements of the statute. 
EPA has carefully evaluated the risks of injected CO2 to underground sources of drinking water (which can include groundwater) in its rules for Class VI and Class II injection wells.  Owners or operators of Class VI wells must develop and implement a comprehensive testing and monitoring plan for their projects that includes injectate analysis, mechanical integrity testing, corrosion monitoring, ground water and geochemical monitoring, pressure fall-off testing, CO2 plume and pressure front monitoring and tracking.  Groundwater and geochemical monitoring is explicitly required.  Owners and operators must periodically review the testing and monitoring plan to incorporate operational and monitoring data and the most recent area of review reevaluation. 
Commenter 10033 requested that EPA draw on lessons learned with MTBE to ensure that the benefits of CCS are carefully weighed against the costs and risks of geologic sequestration and CCS.
Storage of a chemical in in-ground, unregulated tanks is in no way comparable to the detailed and comprehensive regulatory requirements for CO2 geologic sequestration in Class VI wells, or the regulatory requirements for use of CO2 for EOR in regulated Class II injection wells.
Commenters 7977, 9648 and 10681 stated that EPA has not addressed parasitic loads.
Commenter 10681 further asserted that the final rule should allow parasitic loads on an IGCC system to be treated similarly to a utility boiler. Commenter 9648 stated that EPA must conduct a lifecycle energy consumption and emissions inventory evaluation and demonstrate that the 25 percent and 50 percent partial capture rate associated with BSER for IGCC and conventional coal-fired utility boilers, respectively, are based on actual performance levels, and the risks associated with implementing a complex technology that delivers the needed emission reductions. 
Similarly, Commenters 7977, 9196, and 9780 stated that EPA must investigate how the CCS energy penalty of approximately 30% may impact the technical feasibility of CCS integrated with electricity generation and must be addressed by EPA. Commenter 10039 stated that the energy penalty is at least 40%, requires upsizing of EGU equipment, and results in higher emissions of pollutants. Commenters 9003 and 9648 also noted that additional energy requirements can increase criteria air pollutants and toxic air pollutant emissions, as well as raise nonattainment concerns.
Commenters 10017, 10050, 10552 noted that it is inconsistent and wasteful for EPA to mandate a specific technology (CCS) that consumes a large power load in order to operate. Commenter 7977 also discussed the environmental impacts of increased coal use.
Commenter 10618 cited the DOE and GAO estimates, up to 30% and 32% respectively, for the energy penalty associated with CCS. Commenter 8966 provided a citation stating that the energy penalty may range from 12 to 28%. Commenter 9772 cited a 2013 CRS Report identifying energy penalties from 16 to 40%. Commenter 10680 cited a CRS report identifying energy penalties 19 to 30%, or 10 to 100 times other currently employed control systems.
Commenter 8957 estimated that if plant that sequesters and retains 40% of its own emissions, it will only result in a 12% reduction from the uncontrolled plant for an equivalent net electrical output. The Commenter concludes that therefore, CCS is not currently economically viable due to the significant energy penalty nor is it necessarily environmentally beneficial. 
Commenter 10048 stated that the additional power needed to offset the energy penalties, resulting in additional baseload units, carbon emissions and costs, should not be considered reasonable until the energy penalty is minimized.  
The EPA has carefully addressed the issue of parasitic loads and finds the potential energy impacts to be reasonable at a per plant level.  See preamble section V.O.3.
Conversely, Commenter 10108 suggested that the BSER determination has met the needs to assess the environmental impacts and notes that the energy penalty is anticipated to decrease as coal plants as efficiency and the availability of advanced technologies increase.
 The EPA largely agrees with this comment.
Commenters 9777 and 9780 also provided referenced estimates of some potential environmental impacts, including a 90%, 87% and 46% increase in water consumption for PC units, for SCPC units and for IGCC plants, respectively, as well as water requirements to compress and transport supercritical CO2.  Commenter 9777 also cited NETL water consumption requirements for EGUs with CCS and stated that EPA should reconsider whether CCS is BSER due to water demands.
See preamble section V.O.2.
Similarly, Commenters 9666 and 10039 stated that CCS will nearly double the amount of water required for energy generation at units subject to the proposed standard. Commenter 10039 stated that EPA must consider the impact on water supply and water quality. Commenter 9497 stated that the proposed rule does not address how water requirements may affect reliability, especially in areas with water shortages.
Commenter 9777 provided results from a study that indicate CCS would increase water withdrawal by 5-7% and consumption by 88-100% by 2030. The commenter stated that water increases raise concerns about CCS feasibility due to water availability, water rights, and costs of long term water purchases, especially in states with water shortages. Commenter 9777 recommended that operational data from a full scale plant would help address concerns regarding water consumption.
Commenter 9666 further stated that the placement of CCS needs to be balanced with water requirements and water availability, and EPA cannot adopt an NSPS that precludes construction of new sources at water-restricted areas in the U.S. in keeping with the CAA, relevant case law, and EPA's past practice (See Sierra Club, 657 F.2d at 330).
See section V.O.2 to the preamble to the final rule.
Commenter 9770 stated EPA's environmental assessments never looked at the water management issues that result from CCS. The commenter observed that the EPA and DOE have never inquired of states whether they would anticipate, given that more than half of the states in the U.S. are in their second year of drought, whether this brackish water might be needed to augment surface and other groundwater resources. The commenter stated there are questions about the threat that injection of CO2 underground would pose to deep saline aquifers. According to the commenter, our municipal utilities have an obligation to protect existing and future drinking water resources located in deep saline aquifers, in addition to providing reliable, affordable and environmentally responsible electricity. The commenter agreed with AWWA regarding the potential threats to future municipal and private drinking water resources from CCS and about how those threats are relevant to EPA's BSER determination
See preamble section V.O.2 for the EPA's consideration of the issue of water use.  Drinking water resources are the focus of protection under the Class VI and Class II UIC regulations.  Preamble section V.N. explains why those rigorous standards result in protection of underground sources of drinking water, and that the siting and monitoring regime which achieves that protection also prevents releases of sequestered CO2 to the ambient air.
Commenter 9666 also stated that EPA has incorrectly attributed a larger water consumption to CCS at gas-fired power plants than coal-fired power plants, thus ruling out CCS as BSER for gas and not for coal plants. However, water consumption would be expected to increase by 70% at gas-fired plants and 90% and 87% for PC and SCPS units. The commenter remarked that the BSER determination effectively bans new coal-fired EGUs, reducing nation's baseload energy diversity and almost exclusively promoting natural gas due to permitting burdens for nuclear and hydroelectric energy generation.
 Water use issues are addressed at preamble section V.O.2.  The final BSER determination does not ban new coal-fired EGUs, and (as expressed by AEP) may provide a means for continued use of coal in new facilities as part of the nation's energy portfolio.  
Commenter 9195 provided the following list of questions in relation to sole source aquifers:
   * How did EPA address the cross statutory issues related to the injection and sequestration of CO2 if the injection must go through a sole source aquifer?
   * Please explain how EPA's Office of Air and Radiation and EPA's Office of Water communicated and considered the impact of the proposal on EPA's own special program dedicated to protection of sole source aquifers.
See preamble section V.N.
Commenters 9648 and 9770 stated that EPA has not assessed the impacts of permanent storage of compressed gases. Commenter 9648 stated that the proposed rule transfers air pollution to other environmental media.  Commenter 9648 further stated that altering pressure gradients could cause numerous health and environmental impacts.
Commenter 9648 also cited the SAB's concerns on cross-media issues and recommended that EPA request that NRC conduct an assessment.
Commenter 9648 also stated that a commercial sized partial CCS may not be feasible with power plants with limited space. 
EPA has carefully assessed the issues of geologic sequestration, and strongly disagrees with the commenters' assertions that EPA has not studied the issue, and the cursory assertion in comment 9648 that geologic sequestration of captured CO2 could lead to numerous adverse health and environmental impacts.  In particular, the Class VI standards require very proscriptive site evaluation and on-going monitoring.  Owners or operators of Class VI wells must develop and implement a comprehensive testing and monitoring plan for their projects that includes injectate analysis, mechanical integrity testing, corrosion monitoring, ground water and geochemical monitoring, pressure fall-off testing, CO2 plume and pressure front monitoring and tracking, and, at the discretion of the Class VI director, surface air and/or soil gas monitoring. Owners and operators must periodically review the testing and monitoring plan to incorporate operational and monitoring data and the most recent area of review reevaluation. Robust monitoring of the CO2 stream, injection pressures, integrity of the injection well, ground water quality and geochemistry, and monitoring of the CO2 plume and position of the pressure front throughout injection will ensure protection of USDWs from endangerment, preserve water quality, and allow for timely detection of any leakage of CO2 or displaced formation fluids. 
Commenter 10661 stated that EPA must address will increase in ammonia emissions, coal ash and boiler slag from CCS deployment, which cannot be captured using control technologies.
The NETL cost estimates include costs for disposal of fly ash and bottom ash.  See NETL (July 2015) at p. 43.  Moreover, ash is generated as a result of coal combustion, not capture of the resulting CO2.  With respect to ammonia emissions, new steam generating EGUs that choose to comply with the final standard of performance by implementing partial post-combustion CCS are likely to use commercially-available amine-based capture systems. Some concern has been raised regarding emissions of amines and amine degradation of amines (e.g., ammonia, NH3) from the capture process. To reduce the amine emissions, MHI introduced the first optimized washing system within an absorber column in 1994, and developed a proprietary washing system in 2003. In that system, a proprietary reagent is added to the water washing section to capture amine impurities such as amine, degraded amine, ammonia, formaldehyde, acetaldehyde, carbonic acids and nitrosamines. MHI has continued to improve this technology for further reduction of amine emissions and established an "advanced amine emission reduction system".
Research performed by MHI at Alabama Power's Plant Barry indicated that an increasing SO3 content in flue gas caused a significant increase of amine emissions. During testing, at Plant Barry MHI applied its proprietary washing system and confirmed that the amine emission were drastically reduced. Others have also studied emissions and control strategies and have determined that a conventional multi-stage water wash and mist eliminator at the exit of the CO2 scrubber is effective at removal of gaseous amine and amine degradation products emissions. Additional research continues in this area 
Commenter 9201 asserted that EPA failed to examine the impacts of increased methane emissions from natural gas development needed to supply the power sector. Furthermore, the commenter suggested that the GHG reductions from new high performing SCPC or IGCC would be about 20 percent below the national average for the existing coal fleet. Commenter 9201 therefore remarked that if EPA adjusted the methane global warming potential used in assessment studies to the most recent factor, shale gas has a greater GHG footprint than coal used for electricity over the 20-year time horizon. 
The comment that the promulgated NSPS will lead to increase CH4 emissions due to increased use of natural gas has no basis.  New natural gas capacity is being added for reasons unrelated to this standard of performance.  See RIA chapter 4.  The commenter also evidently assumes CH4 emissions associated with natural gas production and transport are uncontrollable, which the EPA does not believe to be the case.
Commenter 10680 stated that upstream emissions from coal mining, processing and transport will be considerably higher because CCS plants will consume more coal.
Issues of parasitic load are addressed at preamble section V.O.3.  DOE/NETL estimates that a new SCPC unit would utilize about 4% more coal in order to meet the final 1,400 lb CO2/MWh standard (to provide the same net power output). However, since the EPA has specified that the BSER for new fossil fuel-fired steam generating units is "a highly efficient supercritical pulverized coal (SCPC) unit implementing partial CCS", a new unit meeting the final standard of performance will utilize less coal than a comparably-sized existing coal-fired plant that is less efficient.
Commenter 10693 stated their support for policies that require significant control technologies and the phasing out of conventional coal fired plants due to the health and air quality impacts associated with coal mining and use. Similarly, Commenter 8924 supported the EPA in addressing carbon pollution and requested that the final rule regulate coal fired plants to reduce emissions to the levels that they are capable of.
 The final standards of performance represent a level of emission reduction capable of being achieved using a best system of emission reduction adequately demonstrated.  That is all that the EPA is empowered to do under section 111 (b).  The standard has nothing to do with phasing out conventional coal fired plants, and, as AEP indicated in its public statements, may provide a means for new coal capacity in the future.
Commenter 6501 stated their support for the proposed CO2 limits due to the health and environmental impacts of air pollution and climate change.
 The EAP acknowledges the commenter's support.
Commenter 9516 stated that the proposed rule allows CCS sources to credit electricity from unregulated sources used to power the gasifier and compressor when determining compliance.
The EPA notes that steam generating unit means any furnace, boiler, or other device used for combusting fuel and producing steam (nuclear steam generators are not included) plus any integrated equipment that provides electricity or useful thermal output to the affected EGU(s) or auxiliary equipment.
Commenter 9682 stated that in the context of GHG regulation under the NSPS program, the energy-requirement and environmental-impact assessments prescribed by the statute are the same. The commenter noted that the whole reason for burning and thus emitting carbon dioxide is that fossil fuels are stores of energy. As a result, the commenter stated that what should be two distinct inquiries into "energy requirements" and "environmental impacts" impermissibly collapse, in the context of fossil-fuel burning, into one and the same assessment.
 The EPA has analyzed these two factors separately, and permissibly so.  Issues of water use and safety of sequestered CO2 are not the same issues as energy use due to energy required to operate CO2 control technology.  See preamble sections V.O.2. and 3.
Use of Purportedly Extra-Statutory "Purposes" to Justify Standard of Performance
Commenter 9514 stated EPA properly considered the costs of partial CCS in light of the benefits that will accrue from considering the social cost of carbon and the co-benefits from reduced emissions of other harmful pollutants, including SO2, NOx, and PM2.5.  The commenter also stated EPA also appropriately considered, in compliance with the CAA, the co-benefits of reduced emissions of SO2 and NOx that would result from the proposed rule's CO2 emission limits.   The commenter stated EPA's recognition of co-benefits is consistent with the methodology it applied in the MATS rulemaking, which also addressed the rule's positive impacts on emissions of related pollutants. According to the commenter, this methodology is also consistent with scientific studies linking policies to reduce greenhouse gases with shorter-term air quality co-benefits.
 EPA is finding that highly efficient SCPC and partial CCS is the BSER because it removes more emissions at reasonable cost (considering especially capital cost and LCOE, on a per plant basis), and does not have collateral adverse nonair health and environmental impacts, or impose undue energy burdens.  This determination does not rest on any consideration of monetized emission reductions, nor does section 111 (a) dictate any particular method (or metric) for considering costs.  The EPA has also found that if new coal capacity is added, there are net quantified benefits under a range of assumptions, in the form of both CO2 reductions and reductions in emissions of criteria pollutants controlled incidentally by the standard.  See RIA chapter 5.  This may be another reason to find the standard to be adequately demonstrated considering costs.  The EPA notes that SO2 is a criteria pollutant (and indeed, already regulated under NSPS for this industry), so no issue is raised regarding considering benefits of control of a pollutant not otherwise within the scope of section 111 standards.
Commenter 9514 stated that although EPA is not required to engage in a traditional cost-benefit analysis, the degree of the pollution reduction benefits that a proposed standard would achieve must be considered along with the costs of achieving it. The commenter referenced Sierra Club, 657 F.2d at 314, 327-28 (upholding costly SO2 standards that would provide significant pollution benefits); and Essex Chem. Corp., 486 F.2d at 437 (acid mist standards were reasoned and cost benefit analysis was not required).
EPA believes that its cost analysis, and its conclusions that the costs of the final standard are reasonable and not exorbitant, are in accord with both of these cited cases.
Commenter 9666 stated EPA does not separately measure the benefits associated with the control of CO2 emissions that would purportedly result from the proposed rule. Instead, the commenter noted, EPA estimates the combined benefits of reducing CO2, fine particulate matter, SO2, and NOx emissions. According to the commenter, if the purpose of the rule is to address CO2 emissions from EGUs, EPA cannot properly introduce its estimates of the purported benefits of controls of other emissions.
 The EPA disagrees with the commenter's statement that EPA cannot properly introduce estimates of benefits associated with reductions in emissions of pollutants other than CO2.  As a preliminary matter, the EPA notes that the determination that the costs of the rule are reasonable are based on the analysis in sections V.H. and I. of the preamble to the final rule.  However, the EPA has also found that if new coal capacity is added, there will be net quantified benefits under a range of assumptions, in the form of both CO2 reductions and reductions in emissions of criteria pollutants that will occur due to implementation of the standard.  See RIA chapter 5.  This may be another reason to find the standard to be adequately demonstrated considering costs.  The commenter's statement that a BSER determination is limited to a single pollutant and that the positive effects on emissions of another air pollutant cannot be considered when deciding what is "best" does not make sense. Suppose technology A removed 100 units of CO2 and no other pollutants (or had a negative impact on other pollutants, and technology B removed 99 units of CO2 and significant amounts of other air pollutants as well. The commenter suggests EPA would have to ignore the impact of technology B on air pollutants other than CO2 in deciding which one is the "best" system of emission reduction.  This approach would not be consistent with the requirement that EPA must consider collateral impacts in determining which technology is "best" under section 111.  See Essex Chemical Corp., 486 F. 2d at 439; Portland Cement. 486 F. 2d at 386. Moreover, the EPA notes that SO2 is a criteria pollutant (and indeed, already regulated under NSPS for this industry), so no issue is raised regarding considering benefits of control of a pollutant not otherwise within the scope of section 111 standards.
Commenter 9593 stated EPA cannot bolster its determination that partial CCS is adequately demonstrated with an extra-statutory assertion that it can choose a technology or set a related emission limitation in order to achieve "meaningful reductions." According to the commenter, the amount of reductions that may be achievable is unrelated to a determination that a technology has been adequately demonstrated. The commenter stated EPA must set an emission limit at the level that is achievable by the demonstrated technology, not a limit that would result in GHG reductions that EPA deems meaningful. Additionally, the commenter stated EPA's criterion related to attaining "meaningful" reductions also directly conflicts with EPA's analysis that the proposed GHG NSPS, if adopted, will not reduce GHGs in any event because of what EPA predicts power plant deployments are likely to be in the next several years.
The amount of emission reductions achieved is certainly a relevant factor in determining if a system of emission reduction is "best".  See. e.g., Sierra Club, 657 F. 2d at 326 ("we can think of no sensible interpretation of the statutory words `best technological system' which would not incorporate the amount of air pollution as a relevant factor to be weighed when determining the optimal standard for controlling ... emissions").   For the same reason, lowest emitting performers are best in determining the MACT floor under CAA section 112 (d) (3).  See NRDC v. EPA, 479 F. 3d 875, 880 (D.C. Cir. 2006.
Other BSER Options
Commenters (1377, 5853, 6118, 6644, 6871, 8024, 8032, 8348, 8957, 9001, 9194, 9201, 9381, 9428, 9666, 9767, 9780, 10052, 10098, 10100, 10238, 10387, 10500, 10501, 10618, 10929) stated that the EPA should consider other technologies rather than CCS as BSER. 
Commenters (2470, 8348, 8501, 8923, 8949, 8971, 9034, 9194, 9197, 9201, 9381, 9407, 9472, 9472, 9593, 9595, 9596, 9665, 10017, 10048, 10098, 10100, 10466, 10500, 10680) noted that  technologies such as SCPC, USCPC and IGCC generation have been adequately demonstrated and can serve as the basis for a BSER determination. Commenter (10618) stated that ultra-supercritical technologies are beginning to emerge as a cost-effective design preference, and have good prospects for growth. Commenters (9381, 9472, 10618) provided data showing CO2 reductions from SCPC and USCPC designs compared to typical existing coal-fired EGUs. 
Commenters (8348, 9197, 9665, 9666, 9772, 10388) recommended that EPA adopt a BSER determination for coal-fired boilers and IGCC units based on the emission rates achievable by IGCC, supercritical, and ultra-supercritical technologies without CCS.
Commenters (8024, 8957, 9001, 9428, 10048, 10238, 10387, 10501) suggested that EPA reconsider its proposal or withdraw and re-propose this rule to include these existing technologies.
 See preamble section V.P.1.
Commenter (10618) questioned the maturity and performance of the IGCC process, stating that while IGCC is technically feasible, it has not been adequately demonstrated. The commenter discussed the status of the Kemper and Edwardsport facilities, stating that both have experienced significant cost escalations throughout their design and construction and neither has been demonstrated to be equivalent or more efficient than other coal-based generation technologies. The commenter noted that a NETL database (cited in text) indicates at least 16 potential IGCC projects have been cancelled in the U.S. in recent years.
 The EPA is not selecting IGCC as BSER.  See preamble section V.P.1.
Commenters (6962, 9768, 9766, 10029, 10035, 10664) suggested biotech uses for captured CO2. The commenters provided information about reuse to develop biofuels and other products, and recommended that these technologies be considered as BSER for carbon storage. Commenters (9766, 10029, 10664) noted that by foreclosing the beneficial reuse of captured CO2 to produce algae-based fuel, EPA has failed to take advantage of the opportunity and has misapplied Section 111. 
Commenter (10029) provided cost benefits of biotech uses for CO2 compared to costs for carbon sequestration. The commenter asked that beneficial reuse technologies are not categorically excluded technologies and may be used by affected EGUs, alone or in combination with other technologies, to meet the proposed CO2 emission limit. 
The final rule provides that types of storage of captured CO2 other than sequestration at an entity reporting under the subpart RR rules may be utilized, provided that an applicant makes a case-by-case demonstration that the storage method is as effective as geologic sequestration.  See §60.5555(g) of the final rule.
Commenters (9107, 9497, 10035, 10106, 10237) discussed alternative technologies to reduce CO2 emissions from coal combustion. Commenters (9107, 9497) discussed a coal gasification processes. Commenter (10106) suggested co-firing of coal and natural gas as a form of emissions reduction. Commenter (10237) discussed concentrated solar power (CSP) as a means to achieve carbon reductions. 
Commenters (10664) suggested that an affected EGU should be allowed to use more than one technology to achieve the standard
The  final standard is a performance standard which can be met by whatever means the source chooses.  EPA has specifically noted that natural gas co-firing is a potential alternative means of compliance for both PC and IGCC facilities, so that EPA agrees with the suggestion in comment 10106.  
Commenters (7977, 10618, 10680) stated that a BSER determination based on highly efficient generation technologies alone would produce significant emission reductions and other advantages. Commenter (9772) stated that EPA should not take away options for improving the efficiency of replacement baseload generation plants.  
Commenter (10618) discussed the emission reductions possible with an NSPS based on the best performing existing units in the EPA's CAMD database. The commenter provided a table showing potential CO2 reductions in the case of replacement of existing units with ultra-supercritical units, and discussed other environmental benefits resulting from higher efficiency technologies. 
Commenter (9486) compared the energy requirements of CCS and those emitted by a well operated USCPC unit, and stated that the actual emissions of CO2 from a newer technology coal fired EGU on a unit of energy delivered to the grid basis are essentially the same as those from a unit utilizing CCS. Commenter 10680 stated the parasitic load that CCS requires will increase emissions. 
Commenter (10618) stated that efficiency-based improvements would be more readily transferred to existing units than CCS technologies.
Commenter (9665) stated that these technologies, particularly IGCC units, also can be constructed to be CCS ready, which would enable them to be retrofitted with CCS equipment in the future. Commenter (9772) noted that highly efficient technologies would also lower barriers to future implementation of CCS as that technology matures.
Commenter (10618) stated that an NSPS based on higher efficiency technologies would drive future innovation, increase operating flexibility, and reduce development risks.
Commenter (10618) stated that a BSER determination based on high efficient generation technologies would enable even more advanced generation and emission control systems, including CCS, to be developed, demonstrated, and commercialized.
Commenters (8024, 9033) stated that a new generation of supercritical, ultra-supercritical and IGCC units is needed to support the deployment of second-generation CCS technologies, which DOE projects may cost roughly 50 percent less than current first generation technologies. Commenter (9033) has estimated that using best efficient technology and then upgrading the existing fleet, the industry can combine to exceed proposed targets for reduction in CO2 prior to 2020 and the next NSPS review.
Commenters (7977, 10618) stated that given the predicted high parasitic load of a CCS, higher efficiency technologies would use less coal, water, and raw materials with less resulting emissions, wastewater, and combustion byproducts.
Commenter (10030) stated that an NSPS predicated upon efficiency could be defensible as BSER based upon technology and economics.
 Use of highly efficient boilers is part of the BSER, but partial CCS is as well.  See preamble section V.P.1.  However, if a developer chose to construct highly efficient SCPC using natural gas co-firing, the standard of performance is achievable, and such a unit can be designed to be CCS ready.
Commenters (8348, 8923, 8957, 9033, 9201, 9381, 9590, 9593, 9665, 9772, 10100, 10680) noted that selecting high efficiency boiler designs as BSER would provide the advantage of significant reductions of CO2 emissions over older plant designs. 
Commenter (9201) stated that because most of the current coal-fired EGU fleet is comprised of subcritical technology, a migration to new, higher efficiency SCPC technology as smaller and less efficient units are retired would produce real emissions benefits.  
Commenter (9665) noted that there would be no downside to that approach, because few coal-based units will be built in the near future.
Commenters (9381, 10100) stated that for the same power output, a higher efficiency coal plant will require less CO2 to be captured; this means a smaller, less costly capture plant; lower operating costs; and less CO2 to be transported and stored.
 The final standard of performance is based on performance of a highly efficient SCPC with partial CCS.  This BSER will result in even greater emission reductions than SCPC alone, no matter how efficient.  See preamble section V.K.
Commenter (10017) stated that the reduction levels using current technology are not only adequate, but necessary in order to ensure that the EPA develops a standard that is consistent with the approach used to develop the natural gas NSPS. The commenter noted that the emissions of new SCPC and IGCC units when compared to the average emissions from coal-fired power plants represent a reduction of 25 and 36 percent respectively. The commenter stated that these reductions are more than twice the reductions proposed for natural gas plants.
 There are persuasive reasons not to base BSER for NGCC plants on performance of CCS.  See preamble section IX.C.
Commenters (10098, 10618) stated that dismissal of other technologies is inappropriate. 
Commenter (10098) stated that basing the NSPS on energy efficiency technologies would spur innovations that would allow power plant operators and contractors to meet GHG emission limits in the most cost-effective manner. The commenter stated that the EPA failed to explore this possibility in the proposed rule, making its rejection of this option arbitrary and capricious.
Commenter (10618) stated that EPA's lack of evaluation of highly efficient generating technologies is inconsistent with Section 111(b)(3), which requires EPA to issue and take into account information on technologies that could be applied to the specific source category for which an NSPS is being developed.
Commenter (10017) stated that the NSPS is a technology-based standard, not an air quality standard driven program. The commenter stated that the EPA should not use the NSPS in an attempt to reach some predetermined reduction standard or issue standards that support only certain industries or technologies. The commenter recommended that the EPA should recognize existing operating technology to set the NSPS standard.
 The EPA agrees that section 111 (b) is a technology-based standard.  Nonetheless, in determining what system of emission reduction is "best", it is at the least reasonable to consider the extent of air pollution reduction.  Partial CCS is a demonstrated technology available for deployment now at reasonable cost without collateral adverse impacts on other environmental media or on energy requirements.  It achieves significantly more emission reductions than SCPC alone.  See preamble section V.K.  Partial CCS is therefore part of a best system.  Commenter 10618's reference to CAA section 111 (b)(3) is obscure.  That provision requires EPA, from time to time, "issue information on pollution control technologies for categories of new sources and air pollutants subject to the provisions of this section".  This provision is unrelated to the process of setting a standard of performance, and in any case, the EPA has shown that partial CCS is a pollution control technology amendable for use (and actually being used) by fossil fuel fired steam electric generating units.
Commenters (10085, 10618) suggested that the EPA revisit the application of BSER and review information available through BACT determinations, EPA reports, demonstrated performance of international efforts, and the CAMD database. 
Commenter (10618) discussed their review of CAMD data for coal-based EGUs, and the comparison of CO2 emissions between units grouped by decade and the AEP Turk Plant.
Commenter (10618) provided a table summarizing international efforts evaluating highly efficient generating technologies.
Commenter (10618) provided a list of three EPA reports that evaluate highly efficient generating technologies.
Commenters (9201, 10098, 10618) discuss EPA reports and guidance that found these technologies to be effective methods of reducing GHG emissions. Commenters (9201, 10618) stated that consideration of these reports and other related information would clearly indicate that highly efficient generation technologies are the BSER upon which a balanced NSPS could be based. 
Commenter (9201) provided information about emission rates for facilities using SCPC units from the EPA CAMD database.
 See preamble section V.P. 1 and earlier comment responses in this unit.  Please note in particular the analysis in section V.P.1 showing that new coal capacity would already reflect supercritical technology, so that a standard based on performance of that level of control would simply ratify a status quo, not result in emission reductions over baseline emission levels.
Commenters (10098, 10618) disagreed with the EPA's rationale to not promote highly efficient technologies because a standard using highly efficient technologies could impede the advancement of CCS technology. The commenters stated that basing the NSPS on energy efficiency technologies would spur innovations that would allow power plant operators and contractors to meet GHG emission limits in the most cost-effective manner. Commenter (10618) stated that further development of highly efficient technologies could actually benefit the development of CCS. Commenter (10618) asked if the EPA proposing an NSPS based on the use of the BSER, or is EPA proposing a CCS development rule.
 The final standard of performance is based on the section 111 (a) statutory criteria: a best system of emission reduction adequately demonstrated, and the level of performance achievable through use of that system of performance.  
Commenters (8032, 9201, 9590, 10092, 10097, 10098, 10395, 10618) stated that the EPA has ignored information about highly efficient generation technologies. 
Commenter (10618) stated that the EPA has not provided a serious, objective evaluation of the technology. The commenter stated that the EPA has not defined or identified highly efficient generation technologies, identified or assessed key variables that impact efficiency, assessed overall environmental benefits, or quantified the magnitude of emission reductions with the use of energy efficiency technologies, thus providing no basis for the Agency to compare these technologies with CCS. 
Commenter (10618) noted that the EPA referenced nine international projects and databases listing dozens of other international efforts related to various aspects of CCS development, but in the evaluation of highly efficient generating technologies as the BSER, EPA referenced zero projects.
Commenter (10098) stated that by failing to explore the use of energy efficiency technologies, EPA's rejection of this option is arbitrary and capricious.
 See preamble section V.P.1 and note that highly efficient supercritical PCs represent a baseline of performance for a new source here.
Commenters (9201, 10680) stated that the EPA dismisses emissions reductions from SCPC and IGCC as providing "little meaningful CO2 emissions reductions." Commenter (9201) noted that the 40 percent reduction required from new coal plants in contrast to the proposed standard for new natural gas-fired plants that are 25 percent higher than the performance of the ten best operating units. Commenter (10680) stated that the EPA's different approaches in setting the coal and natural gas standards cannot be reconciled and, as a result, are unreasoned and arbitrary.
 See preamble section IX.C.4.
Commenter (9665) noted that EPA would be better served to adopt a non-CCS BSER standard for new fossil fuel-fired utility boilers and Integrated Gasification Combined Cycle (IGCC) units. The commenter expressed concern that the partial CCS standard is legally vulnerable and could jeopardize the validity of the entire NSPS rule. 
Commenter (10085) stated that to avoid legal scrutiny, the EPA should look at coal-fired EGUs that have been constructed within the past ten years and look at what control technologies were determined to be best available control technologies (BACT) at the time of construction.
 The EPA believes it has made reasoned findings that partial CCS is part of the best system of emission reductions for this source category.
Commenter (9665) recommended an emission limit of 1,700 lb. CO2/MWh on a gross output basis for these high efficiency units. 
Commenter (9472) discussed the results of an attached report that analyzed CO2 emissions data for all coal-fueled units that have commenced operation since 2007. The commenter stated that the data was analyzed using EPA methodology to determine emissions rates that would be achievable over a ten-year period. The commenter stated that in the report, the following emissions rates are achievable for new coal-fueled power plants without CCS:
-1,915 lbs CO2/MWh for supercritical boilers burning bituminous and subbituminous coals;
-2,080 lbs CO2/MWh for subcritical boilers burning bituminous and subbituminous coals; and
-2,150 lbs CO2/MWh for all boilers burning lignite coals.
The commenter recommended that the EPA should adopt the emissions limits for the particular subcategories set forth above.
Commenter (9201) stated that emissions rates for conventional non-CCS coal units are still too low given operational realities, and should be set at a minimum between 1,800 and 2,000 lbs. CO2/MWh.
Commenter (10664) suggested that the proposed rulemaking be revised to be outcome based. The commenter recommended that the EPA set the standard, provide a mechanism to demonstrate that the standard has been met, and allow reuse technologies to be an option for affected EGUs, alone or in combination with other technologies to achieve the proposed CO2 emission limit.
Commenter (9194) stated that the CO2 emission rate achievable by a new SCPC unit should be adopted for the GHG NSPS for coal-fired EGUs.
Commenters (8024, 9201) suggested that the EPA propose an alternative NSPS limiting CO2 emissions to the emissions rate achieved by new supercritical, ultra-supercritical and IGCC coal technologies, which would be consistent with current EPA GHG BACT Guidance.
Commenter (10951) stated that EPA should be incenting the construction of a new generation of highly efficient super-critical and ultra-supercritical coal plants.
 See preamble section V.P.1.
Commenter (9593, 9780) stated that the EPA can best move forward with the proposed NSPS by adopting the emissions standards achievable by supercritical coal-fired boilers, which achieves significant reductions when compared to the subcritical boiler technology in the existing coal-fired fleet, and evaluating in the future whether CCS has become adequately demonstrated. 
Commenter (9033, 9320, 9426) recommended EPA set CCS aside until the eight year review of the NSPS to avoid conflict between EPA and DOE timelines for the commercialization of CCS technologies.
Commenter (8348) stated that as CCS technology develops, the EPA can then give consideration to a more aggressive CCUS performance standard that could be applied to each EGU classification at a level of performance proven achievable for each particular classification, whether coal or natural gas-fired.
Commenter (8957) stated that if and when CCS becomes commercially viable, it may be more efficient to set appropriate NSPS across all source categories, including NGCC. The commenter stated that until CCS is commercially available, EPA should not pursue it for this rulemaking. 
Commenter (3176) recommended further research and development for CCS without requiring CCS now.
 See preamble section V.P.1.
6.3.7 EIA Analysis
Commenter 8925 noted that based on EPA's reliance in the EIA upon the EIA Annual Energy Outlook 2013, no new conventional coal facilities are projected beyond what is currently under development through 2020 and because coal + CCS is more expensive than conventional coal and provides no additional economic value under current and proposed federal regulations, this implies no new coal with CCS would be built through 2040, in the absence of additional incentives (e.g., financial subsidies or emission limits). The commenter argued that no deployment of electric generating units with CCS for at least 8 and perhaps up to 26 or more years suggests little financial incentive for commercial research or vendor activity, and that combined with uncertain funding for government-funded research on CCS, this commercial slowdown suggests slowing progress on CCS.
This comment reflects analysis in RIA chapter 4, and is thus consistent with EPA's analysis that no new non-compliant coal would be built due to economic reasons.  However, commenters (including commenters to the 2012 proposal) indicated there are other reasons for adding capacity, including preserving fuel diversity, and as a hedge against rising natural gas prices.  The final standard of performance is structured to assure that coal remains cost competitive with other low-carbon baseload dispatchable non-NGCC technologies.  The on-going research into CCS, active vendor efforts in the field, and prior regulatory history indicate that a standard of performance can be a spur to development and deployment of the new pollution control technology which forms the basis of a standard of performance.  See preamble sections V.F, V.I.4, and V.L.
Commenter 9201 stated EPA's assessment on the impact of its proposal relies upon flawed modeling and assumptions that produce a static default assumption that no new coal-based power would be built even in the absence of this proposal. The commenter referenced that analysis used in the MATS rule and noted that only 50 MW of coal capacity had been retired as of February 2014 as compared to the higher EPA estimates. Citing multiple studies of natural gas demand, the commenter stated that EPA policies that force the retirement of coal base load power plants, such as EPA's proposed NSPS, pose a permanent structural barrier to assuring the electric grid remains diverse enough to minimize both reliability crisis and higher and more volatile prices that reverberate throughout the economy writ large. 
 The commenter is incorrect in stating that the standards set by this rule "force the retirement" of coal power plants or any generating capacity. The standards for new sources under 111(b) only impact newly constructed generating capacity and have no bearing on existing generating capacity.
6.3.8 Effect of the Proposed NSPS Rule on CCS Development, Demonstration and Deployment
Commenter 9033 asserted that requiring CCS for coal has the potential to distort the market because the extreme capital cost of the CCS equipment and additional operating cost, as documented by the NETL studies, making NGCC more competitive than coal with CCS.
 NGCC is already significantly more competitive than coal.  See RIA chapter 4.    Preamble section V.I.4 addresses the issue of whether the incremental cost of partial CCS could make new coal uncompetitive with NGCC, considering current and forseeable market conditions.
Commenters 9592, 9683 and 10095 stated that imposing a mandate before CCS is ready will result in project developers choosing a technology that is proven and has lower cost, which reduces the potential market for CCS technology developers and may result in an abandonment of the CCS technology.  Commenter 9592 also provided a reference that IEA's 2012 Technology Roadmap for High-Efficiency Low Emission Coal-Fired Generation stated that wide international deployment of ultra-supercritical and advanced ultra-supercritical units must precede the widespread deployment of CCS technology. 
Commenters 8032, 9196, 9426 suggested that the proposed rule will actually slow the development of CCS and other clean coal technologies.  The commenter insisted that creating a mandate will have the effect of forcing out investment and research into developing technologies and practices because they are not contemplated by the EPA rule.
Commenters 9505, 10031, 10088 suggested that instead of encouraging development, the requirement for the deployment of partial CCS will foreclose further demonstration projects of this technology at commercial power plants.  The commenter further noted that significant penalties for noncompliance discourages [practically prohibits] any future investment in such units.  At a minimum, the commenter believes the mandate will significantly delay deployment of a cost effective and commercially available CCS technology.
Commenter 10046 stated that the availability, or lack thereof, of alternatives to building coal units with CCS systems is a key consideration in determining whether a mandate will force, and thereby promote, the technology's development, or consign it to the dust bin.  The commenter further suggested that since EPA proposes to require that new coal plants add a technology that is decidedly immature, the inevitable response will be to build new gas units exclusively. 
Commenters 1959, 9407, 9471, 9194, 9596, 10500, 10952 stated that mandating CCS for new coal-fired power plants before the technology is commercially viable and adequately demonstrated could ultimately impede, rather than accelerate, its development.
Commenter 10500 stated that hindering development of CCS at home will increase worldwide emissions of CO2.  
 These comments are at odds with historic developments of a regulatory requirement spurring massive technological innovation and development.  See preamble section V.L.  The EPA notes that CCS technology is further developed than FGD scrubber technology was in 1971 when EPA based a standard of performance on that technology as BSER, and for this reason (among others) regards comments such as those of commenter 1959 as misplaced.
Commenters 9326, 9472 and 10095 listed several reasons why EPA should not base the standard for coal on CCS technology, including that the proposed NSPS will effectively ban new coal-fueled power plants and therefore a more efficient second generation CCS will likely never be demonstrated in the U.S. Commenter 9472 stated that overcoming challenges such as available space for CCS, proximity to pipeline infrastructure, suitable storage or EOR availability has limited and will likely continue to limit the opportunity to demonstrate second generation CCS on existing coal plants. Therefore, the commenter asserted that EPA is mistaken in stating that the standard serves as an incentive for future CCS technology development. Commenter 9326 also stated that the proposed rule eliminates the potential for modernizing the coal-fired power fleet with modern high-efficiency super- and ultra-critical pulverized coal boilers. 
Commenters 8024, 10046 stated that this regulation will essentially stop the development of CCS. The commenter noted that without new coal plants, it is unlikely technology developers will continue to invest in CCS development.  Commenters 8024, 10036 noted that since the proposed regulation provides a significantly lower cost alternative (NGCC without controls) to the application of CCS to coal, there is unlikely to be a market for at least 10 years, and most R&D cannot be sustained for that long. Commenter 10046 stated that the EPA should withdraw its proposal.
 See preamble section V.I.4.  Issues of siting availability are addressed in preamble section V.M. and the Geographic Availability TSD.
Commenters 8501, 9201, 9422, 9734, 10036, 10243 asserted that EPA is providing a disincentive and likely freezing any new investments in the development and deployment of CCS by offering the choice between CCS-controlled coal units and uncontrolled NGCC units. .  
Commenter 10243 stated that without a strong financial mechanism to support CCS, the proposed standard does not allow for R&D time that will provide confidence to investors. 
Commenters 9201, 9426 stated utilities are effectively barred from developing CCS projects by the combination of EPA's regulatory requirements, their need to respond to the fundamental economics and concerns of providing affordable power, the continued availability of the option to build NGCC units without any carbon constraints, and because utilities do not value fuel diversity simply for the sake of being diverse.  As a result, the commenter asserted that coal generation is not incentivized to achieve higher efficiency potential such as ultra-supercritical coal, and the deployment of CCS will vanish along with America's ability to be a leader in CCS development in the future.
Commenter 9033 noted that in today's market of moderate natural gas prices, it is very unlikely that any commission will allow the recovery of development costs on existing plants based on a new plant rule that allows uncontrolled natural gas alternatives that are obviously less expensive.
Commenters 9326, 10036, 10046, 10880 stated that the regulations do not reflect the current status of the proven economic viability of CCs technologies for deployment across the broad range of coal generating equipment.  The commenters noted that this creates a situation where it is highly unlikely that power producers will be able to justify the financial risks associated with building a high-efficiency power project without the assurance that the technology can meet the new standards.
Commenter 10046 stated that a CCS-based emission rate standard such as the one proposed by EPA will in fact lead to a delay in CCS investment, and consequently, will not promote the development of CCS, but retards it. The commenter further noted that since much of the US power industry operates in deregulated markets, the financial risk concerns identified with CCS will hinder development of the technology in these markets.
Commenter 10046 stated that a CCS mandate moves the CCS technology risk to cover the entire EGU, because the plant cannot be operated except in compliance with the CCS mandate.
Commenter 10036 noted that in light of existing, alternative, lower cost fuel options, lack of adequate government cost-share funding support to accelerated development and lower costs of CCS technology simply extends the time when technology commercialization is probable. The commenter stated that the proposed rule limits investment choices because the timeline for potential return on investments is unknown or significantly extended.
Commenter 8501 stated that the proposed rule will likely defer investment in energy efficient coal based generation.  
The final rule does not change the fundamentals of wholesale electricity markets. An independent power producer (IPP) developing an electric generation unit in a competitive wholesale electricity market bears the risk when considering whether to develop that resource. The IPP makes a decision to develop the generation based on its assessment of risk and its ability to recover costs through a bilateral contract or the spot market. A vertically integrated utility, whether operating in an RTOISO or more traditional market structures outside an RTO/ISO, would be subject to cost-of-service regulation by a state PUC or other jurisdictional regulator in order to obtain cost recovery. RTOs and ISOs have mechanisms in place to ensure adequate resources to meet demand and reliably operate the grid (e.g., capacity and energy market rules that ensure generators have the opportunity to recover their costs, including fixed costs).  Moreover, as shown in RIA chapter 4 and discussed in preamble section V.H.3, new non-compliant coal capacity is unlikely to be constructed in the foreseeable future for reasons unrelated to the present standard.  Commenters 9201 et al. indicate, for example, that even ultrasupercritical capacity is not currently financially viable.
Similarly, Commenter 8925 asserted their concern about the proposed rule's precedent, which could discourage companies from participating in future technology demonstration efforts by using only two partially constructed, government supported technology demonstration projects as a key part of its basis for establishing emission limits.   
Commenter 8348 stated that as written, the proposed rule will immediately eliminate coal as an option for new power plants with a resulting loss of interest by the industry in continued CCUS research and development.  The commenter goes on to stress the importance of investing in next generation carbon capture technology R&D.
Commenters 9426, 10046, 10395 stated that the proposed rule discourages the private sector's willingness to invest in CCS technology development, and without that investment, the technology may never be commercialized.
Commenters 9407, 10952 disagree with the EPA that that "the industry needs a stick" to demonstrate CCS to the point of availability and cost reasonableness. The commenters stated that the projects EPA cites in the proposal in attempt to justify CCS as BSER all originated without the "stick" that EPA now believes is necessary.
The AEP experience at the Mountaineer project suggests otherwise, when the company cited absence of a clear legal mandate for CO2 reduction as a chief reason for abandoning the project.  
Commenter 9780 stated that only coal-based units with CCS that receive government funding will be built in the future since the costs of CCS will prevent new coal-based units. Additionally, the commenter stated that current CCS projects will help DOE and private industry study how to trim retail costs and reduce costs for second-generation carbon capture technology, suggesting that the technology is not adequately demonstrated. 
Commenters 10086, 10870 stated that the EPA is not expecting new coal plants to be built until 2022. The commenters stated that with no new plants being built, there will be no demand, or research and development, for CCS technology. The commenter stated that the capital cost cannot come down if there is no wide spread deployment of the technology. 
Research into CCS is dynamic and on-going and the EPA does not expect it to cease.  See preamble section V.H.8.b.  
Commenter 10952 (NRECA pp. 5-6) maintains that a CCS mandate ultimately would perversely influence worldwide GHG emissions because of a chilling effect bringing about true CCS demonstration and commercialization.  The commenter posits a case whereby China will add large volumes of new coal capacity, no U.S. domestic coal capacity is added, net CO2 increases from Chinese coal combustion swamp U.S. reductions attributable to the difference between coal and gas-fired EGU emission rates, the result being "a missed opportunity to foster worldwide CCS application, minimal and inconsequential reductions in U.S. CO2 emissions, and an increase in worldwide CO3 emissions that without this proposal we could have been on tract (sic) to curb significantly going forward."
As it happens, the United States and China have signed a bilateral agreement whereby China has committed to significant reductions in CO2 emissions over the next decades.  To the extent potential international response to domestic actions is a relevant consideration under section 111 (a), this development is at direct odds with the commenter's hypothetical.
Commenter 7502 stated that it is evident that the proposed regulations would spur further innovation and investment in such technology [low carbon technologies] in the near future. 
Commenter 9035 stated that the combination of a regulatory driver and financial support is needed to spur investment in CCS projects. The commenter suggested potential funding mechanisms.
Commenter 9035 stated that Public Service Commissions have been reluctant to approve CCS construction, but should be more willing to approve ratepayer cost recovery for CCS projects if there is regulatory certainty. 
Commenters 9035, 10103 stated that in order to support a diverse set of affordable low-emitting sources of electricity, further research, development and demonstration of CCS is needed. Commenter 9035 stated that the proposed rule should be assessed on its effectiveness in supporting, and not inhibiting, the deployment of carbon capture, CO2-EOR, and other carbon-cutting technologies. Commenter 10103 asked that the EPA ensure the CCS technology is appropriately proven and available for use.
 The EPA largely agrees with these comments, which provide support for the proposition that a regulatory standard promotes development of the new technology on which it is based.    
Proposed Emission Limit of 1,100 lb CO2/MWh
Several commenters (0784; 1902, 2471, 3236; 8957, 9033, 9192, 9472, 9497, 9602, 9678, 9725, 10050, 10085, 10097, 10104,10395, 10504, 10552, 10680; 10974; 11062; 10975; 11063; 10963) stated that the proposed limit of 1,100 lb CO2/MWh for coal based EGU is not achievable. 
One commenter (9033) stated that based on heat rates projected for IGCC and USC on lower rank coals, the 1800 lb/MWh standard is unachievable. The commenter provided a table of expected CO2 emissions for selected US fuels for a modern PC power plant operating at full load conditions that shows that the 1800 lb/MWh limit may be achievable at full load conditions for bituminous coals, barely achievable for subbituminous coals, and unattainable for lignites. According to the commenter, the unavailability of CCS means no new units could even be considered. Two commenters (9497-5231; 10104-4644) stated that CCS has not yet been commercially proven and that setting the standard at the current proposed level of 1,100 lbs/MWH will effectively ensure that no new coal-fired plants are built, including promising high-efficiency technologies that would in themselves reduce CO2 output, such as ultra-supercritical power plants.
The commenter (9033) stated that EPA set the standard for theoretical best performing units in only two classes and fails to account for the change in heat rates of units that will occur and cause them to exceed the limit. According to the commenter, all combustion equipment incurs an increase in heat rate with time and operation and it is conceivable that units meeting the requirements when new will fail the standard over time. Commenters (9033, 9472) cite the following factors as impacting plant heat rate, and thus CO2 emissions, making the proposed EPA limit difficult to achieve:
Partial Load Operation. Net plant heat rate increases as the plant operating load is reduced, with a corresponding increase in the specific CO 2 emissions. 
Base load Operation. All power plants have load variation that impact a plant's heat rate and CO2 emissions. 
Cycling Operation. A typical PC cycling plant may operate 30% of the time at 100% load, 55% of the time between 50-75% load, with the balance at lower loads. The average capacity would be about 70% and the plant would have an average heat rate about 4-5% higher than at 100% load.
Degradation Due To Plant Age. Normal wear and tear is to be expected which has an impact on the plant heat rate.
Site Factors. Other factors can have a negative impact on plant heat rate and CO2 emissions. For example, areas with limited water resources could require an air-cooled condenser vs. water cooling. Local water temperature can also have an impact on condenser operating pressure and heat rate.
The commenter (9033) provided a table summarizes the impact of an increase in plant heat rate due to the above factors on the specific CO2 emissions for a state-of-the-art USC PC power plant. A plant that is required to cycle would likely have a heat rate 5% higher than its design 100% load heat rate. It is likely that the bituminous plant would also exceed the limit when site specific factors, impacts of startup, shutdown, and age deterioration are also factored in. The cycling impact could be more significant in the future as renewables assume a larger portion of total power generation. One commenter (10100-1182) stated that the use of cycling units is increasing and do not have the efficiency of baseload units.
According to the commenters (9033, 10085), the Clean Air Markets Database used by EPA to support the proposed 1800 lb CO2/MWh limit shows that while there were a limited number of plants that met this target, the bulk of the reporting plants exceeded it by a wide margin.
The commenter (9033) compares the 4 SCPC plants that the EPA cited in justifying the proposed 1800 lb CO2/MWh target. What stood out was the high capacity factor for these four plants. The commenter stated that they were clearly operating as base load plants, with capacity factors in the mid 80% for three of them and that none of them would have met the proposed target if they operated as typical cycling units.
The commenter (9033) notes that EPA states that marginal units can achieve the standard by applying improvements, such as double reheat, coal drying (for lignites), and cofiring with natural gas. These modifications all add additional equipment at the expense of increased capital/operating cost and potentially decreased availability and makes coal-fired technology less competitive.
Because permits are customarily permanent, the commenter (9033) stated that setting an output standard based on "as new" performance values for equipment that is known to lose efficiency over time will ensure that eventually no plant will meet its permit limits.
 One commenter (9472) stated that EPA should not base a standard for coal on CCS technology and should withdraw the proposed NSPS. The commenter provided information showing the projected CO2 emission rate that would result in one exceedance in 10 and 20 years for each boiler category (lignite, subcritical and supercritical). The commenter recommended the following emissions rates: -1,915 lbs CO2/MWh for supercritical boilers burning bituminous and subbituminous coals; -2,080 lbs CO2/MWh for subcritical boilers burning bituminous and subbituminous coals; and -2,150 lbs CO2/MWh for all boilers burning lignite coals. The commenter (9472) provided the following data:
-emissions data for subcritical and supercritical units firing PRB and eastern bituminous coal and at levels greater than 1,800 lbs/MWh. 
-the relationship between annual CO2 emitted and average heat throughput with the lowest emissions achieved at the highest heat throughput. The data for one unit show CO2 emissions increasing almost continuously as heat throughput decreases, with recent data exceeding 1,800 lbs/MWh for the least heat throughput.
-full, high and low loads showing that for most units CO2 emission rates increase when operating at less than maximum load and that CO2 emissions can increase by 100 lbs/MWh and in some instances by as much as 200 lbs/MWh. 
-the cumulative distribution of CO2 data at or below a given CO2 rate for three categories of EGU units: subcritical, supercritical and lignite-fired boilers, comparing fuel type (i.e. bituminous coal or subbituminous coal).
Several commenters (6870; 9190; 9192; 9497; 9590;  9725; 6649; 10097; 10104; 10395; 10501; 10552;  10680) stated that EPA has proposed for new coal EGU' s a standard (1,100 lb CO2/MWh) that no existing coal base load EGU can achieve-not even the newest demonstrated coal technologies such as supercritical pulverized coal (SCPC) and integrated gasification combined cycle (IGCC). The proposed emission standard is at least 40 percent lower than the performance level that is achievable by these demonstrated coal technologies. One commenter (9678-765) stated that EPA cannot promulgate a standard lower than 1,200 lb CO2/MWh if that standard cannot be achieved by adequately demonstrated technology. Commenter (10504-3606) stated that new IGCC generation has an estimated emission rate of 1,700 lbs CO2/MWh, which far exceeds the proposed standard of 1,100 lbs CO2/MWh for coal-fired units.
Several commenters (1902; 8349; 9602; 9774; 10043; 10083; 10555; 10665) stated that the new coal limits cannot be met with the latest generation technology including those new coal technologies in Europe. The commenter has provided EPA the last 7 years of new plant information that demonstrates that none of these coal-fired plants come close to meeting the 1,100 lb/MWh limit. EPA should withdraw and re-propose the NSPS rule and set the standard based upon a new coal plant of 1950 lb/MWh, which is achievable. A limit of 1,950 lbs. CO2/MWh would make the rule consistent with demonstrated supercritical and ultra-supercritical technology. No new coal plant could achieve a limit of 1,100 lbs CO2/MWh without the use of CCS and no full scale, commercial coal-fired power plants operate in the U.S. with this technology.
Several commenters (2471; 8974; 10024; 10393) suggested a 1950 lb/MWh emission standard. One commenter (2471-4198) stated that this would still be technology-forcing. EPA should consider allowing an EGU to meet part of the limit through financial carbon-reduction mechanisms or instruments, such as through the purchase of Renewable Energy Credits. 
One commenter (7977) stated that EPA consider 1,700 lbs CO2/MWh as the limit for coal-fired boilers. This emission limit would accomplish nearly 20 percent CO2 emission reductions compared to the national average of 2,100 lbs CO2/MWh for the current U.S. coal-fired fleet. This standard is being achieved by only the cleanest and most recently commissioned coal-fired units in the nation, setting an aggressive target for new generation and requiring technology advancement through the New Source Review program.
One commenter (9678) stated that EPA has not defined why reductions on the level of those that could be achieved by IGCC, supercritical, or ultra-supercritical units are not significant. EPA does not explain why a reduction of 700 lb CO2/MWh is significant, while a reduction of 400 to 500 lb CO2/MWh is not. Nor does EPA explain how this determination relates to the analysis contained in the RIA for the proposed rule (e.g., that, overall, the proposed standards will result in negligible reductions in CO2 emissions). Thus, EPA's decision to consider only technologies that can achieve an emissions standard of 1,200 lb CO2/MWh on a gross output basis does not appear legally defensible. One commenter (9592-732) stated that EPA should have compared SCPC emissions to the typical CO2 emissions rate of existing coal-fired generating units. The CO2 emission rates of a new SCPC unit are significantly lower than the typical existing coal-fired EGU and would meet EPA's desire for significant CO2 emission reductions as shown by the table below.
One commenter (10017; 10050) stated that EPA uses two distinct approaches for developing standards for fossil fueled EGUs. The standard for NGCC technology is based upon actual emission data while the standard for coal base load technology is based upon calculations for hypothetical coal units using unproven CCS technologies. Consistent methods should be used for determining the proposed standards. One commenter (10050) stated that EPA rejects basing a coal base load plant standard on SCPC and IGCC as not providing as much emission reductions as practicable. The reductions achieved are real, substantial and as much as practicable with adequately demonstrated technology. For NGCC technology, EPA does not attempt to seek as much reduction as practicable and instead allows emission levels 20 percent higher than the levels achieved by the best performing units. EPA's different approaches in setting the coal and natural gas standards cannot be reconciled and, as a result, are unreasoned and arbitrary.
One commenter (8937) stated that the proposal fails to establish a workable pathway for coal. Rather than restrict construction of coal fired EGUs to those that are fortunate enough to receive sufficient government assistance, EPA should set a standard that allows efficient coal based EGUs to be built while the CCS technology is being fully developed into a stand-alone economically viable technology. As EPA has indicated on its' Clean Energy Site, the average CO2 emission rate for coal fired EGUs in the U.S. is 2,249 lbs CO2/MWh. That figure should be the starting point for establishing an interim target for new coal fired units while CCS is being fully developed and deployed.
Two commenter (9736; 10876) stated that the proposed rules, when examined based on high heating value (HHV) heat rates - appear to favor one CT design over another, which seem to preclude at least the frame-design option from consideration for future capacity additions. This "disfavoring" of frame-design units is short-sighted as the optimum design for most NGCC units is based on use of both a frame-design CT and a heat recovery steam generating (HRSG) unit. As EPA is apparently favoring NGCCs for new generation, this presents a dilemma for smaller entities that need additional generation: a near-term solution to power supply needs - absent the aforementioned "disfavoring" - could be to install a frame-design CT, with the goal of "stepping up" that unit to an NGCC unit at a later date by adding a HRSG unit. In this fashion, the initial costs of installing new capacity would be lower, and power supply capacity could grow as the community's needs grew. A higher standard be established that would not preclude frame-design units.
One commenter (0784) stated that EPA inadequately considered the total amount of carbon currently being released into the atmosphere with the closing of older coal-fired electric generation units and the retrofitting of others.
One commenter (9497) stated they have lignite reserves that may be amenable to UCG with CCS and reinjection back into the coal seam or use in EOR. EPA's proposed rule would inhibit further research and development of this potential energy source by setting an initially insurmountable hurdle in the 1,100 lb/MWh CO2 emission standard. This is a clear example of the potential innovation-stifling impact of the proposed rule. UCG may represent a valuable technological path, but with a stringent CO2 limit in place, there may be no viable way to start on the path without violating the standard. The commenter requests that EPA modify its proposed rule to allow for RD&D and scale implementation of alternative coal based technologies, including UCG. One commenter (9723-6902) stated that a limit of not less than 2,200 lb/MWh should be considered by the EPA for lignite coal-fired EGUs.
One commenter (0784) encouraged EPA to phase in carbon emission standards for new coal-fired generation units based on the best available proven technologies and suggested that 1,800 lbs/MWh is an appropriate initial point.
 
 One commenter (10618) stated that the rates being considered by EPA (1,000 to 1,200 lb/MWh) have not been proven to be technically feasible and have certainly not been adequately demonstrated for coal-based electric generation technologies. The commenter recently completed construction of an ultra-supercritical unit, which is employing state-of-the-art advanced coal technology. Based on the subbituminous fuel used, the projections for load fluctuation and periodic unit startups, operations to date, and available information regarding equipment degradation over a units operational life, the commenter estimates that an annual gross CO2 emission rate of 1,900 lb/MWh would incent the development of more highly efficient generation technologies, while properly balancing the other factors (including costs) associated with the determination of the BSER. 
Commenters (9665; 10098) supports EPA's proposed compliance option under which utility boilers and IGCC units could average emissions on an 84-month rolling average basis. Any source choosing the 84-month alternative standard would be continuously mindful of the source's obligation to meet the standard over the long term. It would be highly unlikely that a source would intentionally operate a unit at less than the optimal level it could practically achieve since any "excess" emissions would need to be made up in later years of operation. A source that operated above the standard would be required to underrun the standard by at least the same amount over the same period of time that it operated above the standard. Therefore, EPA should not establish an 84-month alternative standard at a level lower than 1,100 lb. CO2/MWh. It is also unnecessary for EPA to establish an upper limit on CO2 emissions under the alternative standard, or to require compliance with the 12-month standard. Again, a source is ultimately penalized under the 84-month alternative standard if a unit exceeds the required standard by needing to offset the excess emissions with emission levels commensurately lower than the standard. This provides sufficient incentive for regulated sources to not exceed standards indiscriminately, but only where justified.
One commenter (8024) stated there is no rational basis in climate change policy for exempting CO2 emissions from natural gas generation while penalizing coal-based generation with uneconomic NSPS. Comprehensive global climate modeling analyses show that methane leakage from natural gas exploration, production, transport, and generation processes can offset all or more of the CO2 differential between coal and gas generation. The proposed rule is fundamentally unsound for this reason.
The premise of most of these comments is that SCPC or IGCC boilers, operating alone, cannot achieve the proposed standard of performance, and because CCS is not feasible, this means these units cannot achieve the standard.  CCS is in fact demonstrated and feasible, and the final standard of performance can also be achieved by alternative means not involving CCS.
This final standard of performance for newly constructed fossil fuel-fired steam generating units provides a clear and achievable path forward for the construction of such sources while addressing GHG emissions and supporting technological innovation. The standard of 1,400 lb CO2/MWh-g is achievable by fossil fuel-fired steam generating units for all fuel types, under a wide range of conditions, and throughout the United States.
Two commenters (1624; 9423) favor an efficiency based standard. One commenter (9423) stated that EPA did not appropriately consider an efficiency-based standard for PC and circulating fluidized bed (CFB) units but the standard for NGCC turbines is precisely a standard based solely upon efficiency. The heat recovery portion of a NGCC unit does not reduce emissions, but instead improves efficiency in producing electricity (or steam) by extracting heat from the exhaust gas. EPA has relied upon defining an efficiency level for NGCC units as BSER, yet rejects defining a standard based upon efficiency measures for coal- fired EGUs. The commenter also stated that EPA is applying an emission standard based on combined cycle turbines to a completely different source type of EGU. IGCC units, the basis for the 1100 lbCO2/MWh limit, should be either listed as a separate source category or the BSER standard for IGCC should be listed in Subpart KKKK, because the source of emissions is from the combined cycled turbine and not the gasifier. Combined cycle turbines generally produce more electrical output per the same amount of fuel burned in an EGU that utilizes a simple steam cycle to produce electricity, because the combined cycle uses the steam cycle and a mechanical cycle to produce electricity. The claim that NGCC is inherently lower-emitting is completely a function of the basis of the standard that EPA chose, which is an output based standard of lb C02/MWh. EPA is stacking both CCS and an "inherently lower emitting unit," a combined cycle turbine, to establish an output based emission standard that EPA is erroneously applying to a completely different source type of EGU (subcritical, supercritical pulverized coal boilers, and circulating fluidized bed units). 
One commenter (9426) stated that the EPA has proposed to apply to pulverized coal ("PC") units the 1,100 pounds of CO2 per megawatt hour ("lb CO2/MWh") standard, which is based on technology applicable only to IGCC units. Any standard that applies to PC units based on a finding that it is achievable with a technology that only IGCC units can use is also contrary to law.
Commenter 9426 states that the standard of performance can only be met using a technology suitable only for IGCC.  The commenter is incorrect.  Both pre- and post-combustion CCS are demonstrated technologies.     This final standard of performance for newly constructed fossil fuel-fired steam generating units provides a clear and achievable path forward for the construction of such sources while addressing GHG emissions and supporting technological innovation. The standard of 1,400 lb CO2/MWh-g is achievable by fossil fuel-fired steam generating units for all fuel types, under a wide range of conditions, and throughout the United States. Comments regarding there being "no requirement for emission reduction" have been addressed elsewhere.
One commenter (10100) stated that, assuming that EPA finalizes a standard for coal-fired EGUs based on partial CCS, they support a standard of 1,200 lb CO2/MWh for fossil fuel-fired utility boilers and IGCC units.  These standards are within the ranges proposed by EPA and more accurately account for unit cycling, performance degradation, and other factors.  If EPA does not adopt the higher performance standards, EPA should consider a sliding scale based on generation thresholds to determine the performance standard for EGUs on an individualized basis.  For example, the highest limit should apply to units operating at low capacity factors (i.e., in the 33 percent to 45 percent range).  The emissions limit could be reduced incrementally as the generation threshold increases.
The final standard of performance is less stringent than this commenter recommends, and so provides a greater degree of flexibility. This final standard of performance for newly constructed fossil fuel-fired steam generating units provides a clear and achievable path forward for the construction of such sources while addressing GHG emissions and supporting technological innovation. The standard of 1,400 lb CO2/MWh-g is achievable by fossil fuel-fired steam generating units for all fuel types, under a wide range of conditions, and throughout the United States.
One commenter (8957) stated separate emission limits must be established for each type of fossil fuel-fired units. Additionally, dual fuel capability should be more adequately addressed for boilers and turbines. The requirement for a turbine to burn at least 90% natural gas to be an affected source needs to be removed. Most turbines are capable of firing multiple fuels without major modifications, so a turbine can simply fire 11% petroleum or other fuel to completely avoid the regulation. EPA should set a performance standard of 1,000 lbs C02/MWh (gross) or 1,050 lbs C02/MWh (net) on a 12-month annual average basis for NGCC and 1,800 lbs C02/MWh (gross) or 1,925 lbs C02/MWh (net) on a 12-month annual average basis for coal-fired units. After it becomes an economically feasible control technology, CCS will become the BACT to reduce C02 emissions for both coal-fired and natural gas-fired power plants that are subject to the Tailoring Rule. The commenter agreed with EPA that NSPS should be the floor for determining BACT and when it becomes an economically feasible control technology, CCS will become the BACT for PSD permits. 
One commenter (10043) requested that EPA increase the emissions limit for new NGCC units from 1,000 to 1,250 lbs. CO2/MWh. While it is possible to purchase a new NGCC unit that meets the 1,000 lbs CO2/MWh threshold in the short term, it is unclear whether new NGCC units can sustain that high level when used to firm up delivery of wind and other intermittent generation sources
One commenter (10095-2618) stated that for NGCCs, EPA must set an emissions limit that is achievable and considers economic-, environmental-, and energy-related impacts. EPA must explain how the standard is achievable under the most adverse conditions which can reasonably be expected to occur. Historical operating data show that many units operate above the proposed standard when experiencing adverse conditions. Also, the proposed standard is constricting considering the wide operational variability NGCCs experience over the units' lifespan and does not represent the best balance of economic, environmental, and energy considerations. Finally, EPA has created unintended consequences by providing rolling three-year average applicability criteria.
 This final standard of performance for newly constructed fossil fuel-fired steam generating units provides a clear and achievable path forward for the construction of such sources while addressing GHG emissions and supporting technological innovation. The standard of 1,400 lb CO2/MWh-g is achievable by fossil fuel-fired steam generating units for all fuel types, under a wide range of conditions, and throughout the United States. See preamble section V.J and the `Achievability' TSD available in the rulemaking docket.
One commenter (7990) stated that EPA base the applicability requirements on the source's design and purpose prior to completion, because new EGUs must know what performance standards will apply to them during the licensing process. New EGUs undergoing New Source Review should be allowed to accept limits in operating permit conditions in order to remain below the Propose Rule's applicability provisions. This methodology is consistent with the current approach under the Title V program.
The commenter is mistaken.  The NSPS applies immediately. This final standard of performance for newly constructed fossil fuel-fired steam generating units provides a clear and achievable path forward for the construction of such sources while addressing GHG emissions and supporting technological innovation. The standard of 1,400 lb CO2/MWh-g is achievable by fossil fuel-fired steam generating units for all fuel types, under a wide range of conditions, and throughout the United States.
One commenter (10119) stated that EPA fails to establish that fossil fuel-fired boilers and IGCC facilities cannot achieve an emissions rate lower than 1,100 lbs CO2/MWh for coal-fired EGUs, which is based on a 25% CO2 capture rate at a new IGCC facility. According to the commenter, using the same technology necessary to capture 25% - a single-stage water-gas shift ("WGS") reactor and two-stage acid gas removal system - a facility would be expected to achieve a CO2 emission reduction of up to 75%, or an emissions rate of approximately 380 lb CO2/MWh-gross. The commenter stated that according to the proposed rule, an IGCC facility using this technology thus could dial in a far greater amount of CO2 capture and achieve a far lower CO2 emissions rate than EPA has proposed. EPA's proposed emissions standards do not reflect a minimal 25% CO2 capture rate and lack support.
One commenter (10394-1700) stated that their state has established emission performance standards (EPS) at 1,100 lbs CO2/MWh of electricity for local publicly owned electric utilities, which, unlike EPA's proposed limits, also applies to existing utilities, and in general includes emissions from boilers, combustion turbines, reciprocating or other engines and fuel cells. The commenter stated that the emission limit for large natural gas-fired units (those with a heat input threshold greater than 850 MMBtu/h) should be more stringent than EPA proposed. The commenter recommends an emission rate limit of 950 lbs CO2/MWh. According to the commenter, several permits recently issued for large natural gas-fired units have been for projects with lower emission rates and a recently permitted 1-on-1 combined cycle unit will meet the limit of 950 lbs CO2/MWh. The commenter stated that the limit for the smaller combined cycle units (heat input rating below or equal to 850 MMBtu/h) should be more stringent than proposed and be set at 1,050 lbs CO2/MWh. Based on the commenter's experience, the smaller combined cycle units can be less efficient than the larger turbines; however, their overall efficiency will still be higher than the simple cycle units. The commenter has recently permitted a 1-on-1 combined cycle unit that will meet the lower limit of 1,050 lbs CO2/MWh net (gross output), 12-month rolling average, inclusive with manufacturer turbine degradation.
 This final standard of performance for newly constructed fossil fuel-fired steam generating units provides a clear and achievable path forward for the construction of such sources while addressing GHG emissions and supporting technological innovation. The standard of 1,400 lb CO2/MWh-g is achievable by fossil fuel-fired steam generating units for all fuel types, under a wide range of conditions, and throughout the United States.
One commenter (9406) stated that although the proposed emission limit for coal-fired EGUs is based on the emissions reductions that can be achieved through CCS, EGUs are permitted to meet those standards using any combination of means. Although no new coal-fired EGUs are being planned, before the drop in natural gas prices, many states, including Pennsylvania, had informed developers that new coal-fired plants would need to be built to carbon capture ready standards. If a developer wanted to build a new coal-fired power plant for purposes of energy diversity, it could readily design it as a carbon capture ready plant and employ a wide variety of other means already described in GHG BACT determinations to achieve the proposed 1,100 lb CO2/MWh performance standard. For instance, many existing coal-fired plants can co-fire coal and natural gas to reduce emissions rates. Coal-fired plants can also use biomass fuels produced by sintering and other processes to reduce GHG emissions. At least one natural gas combined cycle plant combined solar power to reduce its overall GHG emissions produced per megawatt hour. A carbon capture ready supercritical coal-fired unit, coupled with a highly efficient NGCC unit, solar, or wind capacity and using partial biomass fuel could likely be designed to meet the proposed standard of performance. EPA could consider these alternative means of meeting its proposed standard.
The EPA largely agrees with this comment.  Co-firing with natural gas is an alternative compliance pathway for meeting the final standard for both SCPC and IGCC.  
One commenter (8020; 8939; 10103 ) supports allowing plant owners to choose either compliance option: 1,100 pounds of C02 per Megawatt-hour ("lb/Mwh") over a 12-operating month rolling average, or between 1,000 and 1,050 lb/Mwh over an 84-operating month rolling average. 
One commenter (1900) stated that while a 1,100 lb CO2/MWh-gross averaged over a 12-month operating period seems adequate, perhaps it could be extended to 24 months to give these companies more time to meet this demand. It may also be appropriate to set the limit for the rolling 7-year average to a stricter amount, perhaps closer to 950 lb CO2/MWh. This would cause EGU companies to take more immediate action so they don't have to meet such a strict limitation in the future. By setting a larger gap between the limitations, more action is likely to be taken in a shorter amount of time.
 The EPA is not finalizing the option of the 84-month compliance period.
One commenter (7977) stated that pursuant to Section 111(b) of the CAA, EPA must set an achievable standard for fossil fuel units that: is consistent with Congressional intent; encourages the use of local fuels; expands energy resources that could be burned in compliance with emission limits; and makes technology and fuel choices less restrictive.
The commenter states a number of factors which are not enumerated in section 111 (a), including encouraging the use of local fuels, and making technology choices and fuel choices less restrictive.  These factors are not part of a best system of emission reduction, as defined in section 111 (a).  
One commenter (9513) stated that EPA needs to pay attention to detail and cannot forego the opportunity to reduce hundreds of thousands or millions of tons of CO2 emissions simply because those opportunities don't generate reductions of hundreds of millions of tons by themselves. For example, the agency proposes to establish the new emission limitations to two significant digits where 1,000 lbs/MWh is represented as 1.0 x 103 lb/MWh and sources are allowed to round down to comply. This would relax the NSPS by an additional 1-5 percent (depending on whether EPA allows sources to apply the rounding to the test results expressed in Imperial (English) or metric units). To illustrate, an emission rate of 1049.99 would round down to 1000 and comply with the proposed limit if expressed in U.S. units. If the determination is in metric units the effect would be smaller.  The commenter anticipates that this issue will be highly controversial, and yet EPA has not analyzed the impact. 
This final standard of performance for newly constructed fossil fuel-fired steam generating units provides a clear and achievable path forward for the construction of such sources while addressing GHG emissions and supporting technological innovation. The standard of 1,400 lb CO2/MWh-g is achievable by fossil fuel-fired steam generating units for all fuel types, under a wide range of conditions, and throughout the United States.
One commenter (10047) recommended that EPA revise the proposed standard for coal-fired EGUs to a level equal to that met by the very latest and most efficient units permitted in the United States, and that it continue to monitor the progress of CCS or other CO2 control technologies, such that if a control technology is shown to be effective and economical in the future, EPA will be positioned to revise the NSPS as appropriate. Whereas coal-fired units were originally designed for an operating life of 35 years, recent history has shown that units can operate as long as 50 to 60 years through life-extension projects. Thus, there is the specter of half-century consequences of this NSPS. If EPA sets the CO2 standard at a level reflecting efficiency, it must be positioned to revise the standard quickly should CCS or some other control technology be shown to be economically viable in the future.
One commenter (10869) stated that the proposed optional limits (1100 or 1000-1050 lb CO2/MWh) could potentially allow a plant to implement CCS technology to reduce their emissions after the initial operation date. This approach recognizes the current state of CCS technology while providing an incentive to make it more widely available on a faster timeline than may have been the case without the carbon standard. The final standard should include firm timelines for power plants to demonstrate that they are using CCS and impose penalties if not implemented on time. The 40% rate of carbon capture implied by this standard is low. Note that installing CCS at a power plant will impose an efficiency penalty that would raise overall emissions. CCS capture rates will need to be 85% or more if this technology is to help contribute to U.S. power sector emissions reductions of 90%t or more by 2050. EPA will need to provide a pathway to a more ambitious level of carbon capture for coal-fired power plants; otherwise we risk locking in long-lived carbon-intensive energy sources.
Note that the EPA must review section 111 (b) no later than 8 years, and so will monitor on-going technical developments, as comment 10047 urges. 
One commenter (10606) stated that to provide an opportunity for new natural gas-fired steam boilers to be constructed, EPA should promulgate an appropriate CO2 emission limit for natural gas-fired boilers, taking into account the maximum thermal efficiency of such a boiler. Natural gas burning emits CO2 at a rate of approximately 53 kg/MMBtu, equivalent to 116.7 lb CO2/MMBtu heat input. Therefore, an appropriate optional standard, based on heat input, would be 120 lb CO2/MMBtu (12 month rolling average) and would account for variations in the heating value and methane content of natural gas. A standard based on gross output would be approximately 1,300 lb CO2 per MWh (12 month rolling average). This proposed standard would allow the development of natural gas-fired steam generation in the future, while limiting CO2 emissions to about one-half the amount that would be produced with coal-fired generation facilities. 
 This final standard of performance for newly constructed fossil fuel-fired steam generating units provides a clear and achievable path forward for the construction of such sources while addressing GHG emissions and supporting technological innovation. The standard of 1,400 lb CO2/MWh-g is achievable by fossil fuel-fired steam generating units for all fuel types, under a wide range of conditions, and throughout the United States. This standard is applicable to all new fossil-fuel fired steam generating EGUs  -  including those firing natural gas. 
One commenter (10606) stated that an auxiliary or backup EGU should be exempt from the CO2 emission standard. Backup EGUs will be package boilers in almost all cases, due to the relatively low cost of such units. However, a package boiler could not comply with the proposed limit of 1,100 lb CO2/MWh gross output.
 Applicability issues are addressed in the preamble sections III.C and III.D.
6.4.1 Achievability of Proposed Standard with CCS Technology
Several commenters (9666, 9472, 9650, 10039; 10618; 10552; 10240; 10050; 10052; 8937; 9034; 10100; 5731; 9780; 9194; 9592; 9197; 10023; 9397; 8906; 10870; 8974; 9422; 10520; 9471; 10051; 10048; 9003; 10952; 10466; 0587; 9192; 8032; 10392; 9780; 10662; 7977; 8971) disagreed with EPA that BSER for coal fired EGUs  is CCS. Industry, in parallel, the U.S. Department of Energy, along with other public and private efforts, have recognized that potential CO2 emission reduction technologies, including CCS for fossil fuel-based electric generation processes, must overcome significant development barriers if they are to have any chance of becoming a technically feasible and commercially viable control option. No CCS technologies have been demonstrated in a fully integrated end-to-end configuration at scale on a coal baseload EGU. There are no commercial ventures in the United States that capture, transport, and inject industrial-scale quantities of CO2 solely for the purposes of carbon sequestration. Currently, there are no commercially viable power plant projects that employ permanent carbon sequestration. Of the examples provided by EPA in the proposed NSPS, none of the projects are currently operating. 
One commenter (9780) stated that the only U.S. project already under construction, Southern Company's Kemper project, has seen significant cost overruns in the past 18 months. None of the other cited U.S. projects have achieved financial closure or broken ground, with the exception of the W.A. Parish facility, which chose to commence construction of the natural gas turbines early because it made economic sense to do so independent of the CCS project, which is still on hold. None of these projects is in operation. Kemper is not only a first-of-a-kind project, but also a one-of-a-kind project. Due to its many site-specific characteristics, the Kemper project cannot be consistently replicated on a national level. In its reliance on the Kemper project, EPA has ignored the unique nature of this project and has not explained how Kemper reasonably can serve as a model for other new EGUs in the rest of the country.
One commenter (9192) hosted a first-of-its-kind project at the Pleasant Prairie Power plant to test a chilled ammonia scrubber technology to separate and capture up to 90 percent of the CO2 emissions from a small portion of the flue gas from one of the boilers. The project did not include storage of any captured CO2. The project demonstrated that the process was capable of removing 90% of incoming CO2 from a slip stream of the host power plant's flue gas. The project operated at up to a flue gas flow equivalent of 1.7 MW electric power generation. This project represented an early step in developing a commercial-scale technology to capture CO2 emissions from existing coal-fired power plants. The pilot project confirmed the predicted performance of the chilled ammonia carbon capture system at an operating power plant. To date neither this technology nor any other has been retro-fitted at full scale at a commercially operating power plant. Therefore, the project did not demonstrate that carbon capture and storage is the best system of emission reduction.
One commenter (10618) operated the first integrated CCS project in the world on a coal- based generation plant. The commenter stated they provided comments on the 2012 proposal to alleviate misconceptions by EPA by placing into proper context the scope and outcome of its CCS program. The current proposed rule continues to misrepresent the scope, results, and lessons learned from the Mountaineer Plant CCS project. In their submittal, the commenter provided a number of qualifications regarding the results of that CCS project. While the project was successful, it is a far cry from being representative of what's required for full-scale deployment.
Commenter (10039) stated that EPA's finds CCS as BSER for coal fired EGUs in the absence of any operating data from any CO2 sources of the size of a pulverized coal EGU (above 3,000 mmBtu/hr heat input). US EPA does not present any data in the rule docket from the type and size of sources it proposes to require to meet the BSER limits of this proposed rule because neither carbon capture nor geological sequestration have ever been implemented at a coal fired EGU greater than 100 MW before.
One commenter (9666) stated that EPA's achievability determination is not supported by any technical or statistical analysis of emissions data from units implementing CCS because no such data exist. According to the commenter, EPA relies on a 2011 cost and performance report by DOE that assumes the performance of various CCS configurations and is not based on information gathered from actual operating experience. The commenter further stated that EPA's only achievability analysis is based on its estimates of CCS performance using pre-combustion CO2 separation technology, which can be implemented only at IGCC units and that EPA nowhere analyzes whether the proposed 1,100 lb/MWh limit is achievable for units firing PC.
One commenter (9472) stated that EPA is proposing to set a stringent CO2 performance standard which no new coal-fueled plant anywhere in the world has come close to meeting based on CCS technology that is not adequately demonstrated. The commenter stated that the EPA record shows that there are no coal-fueled power plants in the US -or even in the world - that are currently operating with a full-scale commercial application of CCS. According to the commenter, the flaw in the EPA proposal is concluding that CCS is adequately demonstrated based on the assumption that a few planned, but unbuilt, full-scale CCS project will successfully demonstrate in the future the effectiveness and reliability of this emerging, but unproven technology. The Agency is proposing to set a CO2 performance standard based on mere speculation or conjecture.
The commenter (9472) stated that EPA cannot base its BSER determination on small or experimental projects that seek to demonstrate CCS at pilot scale, for example, plants at Vattenfall, Germany; Southern Company's Plant Barry; and AEP sponsored Mountaineer Power Plant. The commenter stated that these pilot-scale slipstream projects have proven that CCS is a potentially viable technology but is insufficient to demonstrate that CCS can be implemented at full-scale utility applications. 
The commenter (9472) stated that EPA cannot base its BSER determination on a few industrial applications of CCS. According to the commenter, none of the industrial projects referenced by EPA involve the full-scale commercial application of a CCS technology on a power plant that sells electricity into the grid and therefore cannot constitute an "adequately demonstrated" technology that can be used to set performance standards for coal-fueled power plants under section 111(b) of the CAA. For several industrial CCS projects cited by EPA, the commenter described how such facilities differed from coal-fueled power plants.
One commenter (10952) stated that the proposed NSPS for coal-fired EGUs requiring carbon capture is not supported by the existing state of carbon capture technology as applied to EGUs, and EPA does not have the discretionary authority to impose it.
One commenter (9426) stated that because the various CCS processes have never been demonstrated together, and because even pilot scale operations have been done on only some of the various coal types and ranks, the industry has limited insight into the effects of combustion, unit operation, and load cycling on the capture plant, which in turn will affect the compression, which in turn will affect the pipeline and injection operation. The lack of operating experience and the impact of different types and ranks of coals are but a few of the unknowns and risks associated with CCS projects. According to the commenter, technologies are in the early stage of development or are conceptual and demonstration projects are expected to be initiated in the 2030 to 2035 time period. A demonstration project can take 7-10 years to be designed, built, and operated enough to be helpful in the design of commercially deployed replicants and  prove that commercializing CCS technology is significantly more involved than stringing together existing pieces of hardware and declaring victory. 
 
One commenter (9424) stated that CCS, particularly sequestration, is poorly understood and has known and unknown negative environmental effects. Opposition to enhanced oil recovery (EOR) and hydraulic fracturing would certainly increase were subsurface injection of carbon dioxide expanded to include storage and disposal. The small number and size of carbon dioxide storage projects in operation, often at preexisting oil and gas production sites, do not justify widespread implementation of the technology for sequestration. The commenter disagrees that this circular logic justifies selection of a BSER that is so poorly understood. We respectfully request that EPA increase the proposed emissions limit to 1,950 lbs CO2/MWh, while continuing carefully controlled and monitored demonstrations of CCS systems. 
 
One commenter (10395) stated that EPA should determine that, for pulverized coal facilities, it is not feasible at this time to set a standard of performance. Then, at a future time when CCS becomes an "achievable" and "adequately demonstrated" technology as defined by the definition of "standard of performance" at Section 111 (a)(1), the Administrator may make a change as set forth in Section 111(h)(4).
One commenter (9426) stated that even if CCS were demonstrated to be technically feasible, if the many implementation issues are not resolved satisfactorily, a CO2 emission standard based on CCS would not be achievable. 
One commenter (7977) stated that currently, there are no control technologies employed that allow any new commercial-scale coal-fired boilers and IGCC units to achieve the proposed standards. EPA fails to justify its determination and proposed limitations with any real test data that indicate whether a source is capable of achieving compliance.
The commenters are mistaken.  Partial post and pre-combustion CCS is demonstrated at full scale (preamble sections V.D. and E), as is sequestration of captured carbon in deep saline formations.  Preamble section V.N. 
One commenter (10039) stated that EPA has not accounted for performance degradation of emission units or control systems (CCS) in any of the performance standards proposed. The commenter stated that given EPA's position that projects that impact life extension or recapture degraded performance and/or load at EGUs are modifications, EPA must include expected degradation of these units and control devices over the life of the EGU in its calculation of the achievability of the standard. EPA needs to collect data on the achievability of the standards over the entire plant life cycle to determine the achievability of the proposed EGU standards. 
The final standard is achievable over a range of operating conditions.
One commenter (10555) estimated that transporting captured CO2 from Milwaukee, WI to Decatur, IL, the closest CO2 storage site, could cost as much as $405 million. A separate Wisconsin Public Service Commission report estimated that the total cost to construct a pipeline network dedicated to CO2 transportation could be between $550 million and $1 billion. Both key energy and environmental regulatory agencies concluded that the transportation component of CCS alone may hinder its commercial viability in Wisconsin. The WDNR notes that the EPA is not projecting the path of technological development for CCS in the reasonable way that is required by the Clean Air Act taking into account best available control technology determinations. Further, the commenter requests that the EPA amend the currently proposed 1,800 lb CO2/MWh threshold based on the assumption that a supercritical coal boiler can meet the limitation. Two Wisconsin supercritical coal boilers at We Energies are only achieving an average emission rate of approximately 1,950 lb CO2/MWh.
See preamble section V.I.5. The EPA's cost estimates do in fact include costs associated with transportation and storage of CO2.
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.
One commenter (9426) stated that the integration of CCS systems with coal-based generation technologies creates a number of practical development challenges, such as differences in operating philosophies between a steady-state chemical production process (like CCS) and a dynamic load-following process (like power generation). Parasitic energy consumption, physical space requirements, power plant integration, and flue gas compatibility all pose obstacles to the capture of CO2 at a power plant. The reliability of a CCS system could be affected by problems arising in each CCS process. Because full scale carbon capture, compression and transportation, and storage have not been integrated on a power plant, it is unknown how the three processes will interact. 
All of these operations are integrated at commercial scale at Boundary Dam, recently designated as POWER magazine's power plant of the year due to successful operation of CCS at full commercial scale. 
Other Subcategories
One commenter (9664) stated that while subpart Da applies to new liquid oil- and gas-fired units, EPA appropriately emphasizes coal- and petcoke-fired units because no new utility steam-generating units designed to be fired primarily with liquid oil or gas have been built for many years and none are expected to be built in the foreseeable future due to the significantly lower costs of building Subpart KKKK combustion turbines. 
There is no need to subcategorize by fuel. The standards are achievable across a wide range of operating conditions and fuel types.
One commenter (9321; 10618) stated that EPA must provide special consideration for coal refuse fired units and that the proposed GHG standards would discourage the development of new coal refuse fired units. According to the commenter, the quality of the coal refuse is highly variable with the heating value of coal refuse decreasing while the sulfur content has increased. EPA must provide new units with the operational flexibility to burn the wide range of coal refuse and encourage the development of new units. Because of their environmental benefits of coal refuse fired EGU's, EPA should adopt a subcategory for coal refuse fired EGUs. The combustion of coal refuse stock piles results in uncontrolled emissions and abandoned mine sites release methane. The commenter hopes that EPA will continue to see the value of eliminating these uncontrolled emissions by allowing the use of coal refuse as a fuel in EGUs. The commenter recommends that EPA support removing coal refuse piles by either exempting or sub-categorizing waste coal fired EGUs.  An environmental benefit of exempting CFB coal refuse units from the rule would encourage new construction. For economic reasons, such as fuel considerations and plant size, coal refuse EGU's using CFB technology cannot apply capital intensive carbon sequestration or advanced efficiency (heat rate) technologies to reduce the greenhouse gaseous at the plant sites and should be excluded from the proposed rule. The commenter stated that capture percentages will be extremely difficult to achieve in a CFB boiler burning coal refuse that also injects limestone into the boiler to control SO2 emissions. The commenter stated that EPA should extend special consideration for coal refuse-fired EGUs as they did in the NSPS for SO2, PM and NOx. The carbon sequestration that occurs as a result of the carbonation/mineralization of ash from coal refuse fired units is another example of the multimedia environmental benefits provided by coal refuse fired plants.
One commenter (8957) supports an exemption for waste coal facilities given the environmental benefits. If an exemption cannot be granted to waste coal-fired facilities, the commenter recommends a separate subcategory for this technology. Coal refuse piles naturally combust and burn slowly emitting C02 and other air pollutants The commenter hs been mitigating this environmental impact by combusting coal refuse in circulating fluidized bed (CFB) boilers. Since coal refuse piles produce C02 naturally, the CFBs generate electric power and steam for use while providing benefits to the economy without increasing the net C02 emissions and the ash generated through this process is alkali in nature, and is often sought for use in reclaiming abandoned mines and mine lands. Due to the multiple environmental benefits of remediating coal refuse piles, EPA should establish an exemption for EGU s that burn over 75% coal refuse on an annual basis. The advantages in using coal refuse to create electricity is that a mining waste facility would produce no net GHG emissions in the long term and emissions would be no greater than the short-term emissions of a combined cycle gas plant. Remediation would stop current and future C02 emissions resulting from the uncontrolled combustion of waste piles. Should an exemption not be granted to waste coal-fired facilities, the commenter recommends setting limits for bituminous gob and anthracite culm at 2,200 lb C02/MWh (gross) or 2,350 lb C02/MWh (net).
The rationale for not exempting coal refuse-fired EGUs is in the preamble to this final rule.
One commenter (10554) stated they see no legitimate basis for coal refuse to be subcategorized and they should be treated in the same manner as all other coal-fired EGUs.
One commenter (3862) stated that since industrial units are more likely to experience load fluctuations and more startup and shutdowns, a review should be made of the available data to determine whether these operational factors for industrial units dictate an exemption or sub-categorization with different limits based on more potential variability.
 There is no need to subcategorize by fuel. The standards are achievable across a wide range of operating conditions and fuel types. The rationale for not exempting coal refuse-fired EGUs is in the preamble to this final rule. This final rule only covers EGUs, not industrial units.
Two commenters (9471, 9780) stated that in determining the appropriate BSER and resulting emissions standards for new fossil-based steam EGUs, EPA should consider fundamental design and process differences between the different units subject to subpart Da. The commenters stated that significant differences in design and operations between IGCC and pulverized coal boilers should be recognized, as should the differences among coal types. The commenters stated that subcategorizing based on boiler and fuel type would ensure that any resulting standards are achievable. Further, the commenters suggested that any resulting standards could not be deemed to be achievable unless EPA could demonstrate that all operating periods, including periods of startup and shutdown, were considered when setting the standards.
Several commenter (9777; 10388; 10606; 10618; 10965) stated that EPA should establish separate standards for coal-fired and gas-fired units. EPA should establish an NSPS subcategory that is specific to IGCC as these processes are fundamentally different from other coal generation technologies. The commenter describes why a separate subcategory is needed and the issues to be considered in establishing a separate subcategory. 
 The final standard of performance is achievable and adequately demonstrated considering operation with different types of coal.  See preamble section V.J. and Achievability TSD.  The final standard is also achievable with an SCPC with partial CCS or co-firing, and an IGCC with co-firing of natural gas (or CCS, if the source chooses).
Two commenters (10088, 10667) stated that if EPA does not provide a lignite subcategory, operators of these power plants would be forced to forgo maximizing use of this domestic, plentiful, and affordable resource. This will signal the end of such co-located mine mouth plants as well as the ability to recover potentially sizable investments in their mines because of the limitations placed on an operator's ability to maintain, expand or add capacity to use these local, domestic, and sizeable fuel supplies. This would be incredibly burdensome on Texas units, which rely heavily on their lignite reserves.
One commenter (9777) citing  a study by Cichanowicz and Hein found that coal composition, load factors, boiler design and coal moisture all affect C02 emissions and recommends that coal types should be further subcategorized.
The EPA does not agree with this comment. The EPA examines the issue of alternative coal types in section V.J. and finds that the standard of performance is achievable using any coal type, and has accounted for the increased capture rate (and additional cost0 if other-than-bituminous coal is used.  With regard to use of lignite, lignite drying is a normal technology which allows efficient combustion of lignite coal.
6.5.1 Coal-Fired Projects Under Development
One commenter (9403) stated that for plants that have proceeded in their development beyond the point when CCS could be incorporated into the plant design (assuming it could be incorporated at all), imposition of a CO2 standard that depends on CCS technology would effectively prevent construction of the facility. This would result in significant costs to the project investors, both in terms of lost sunk costs and lost opportunity costs. Given that EPA has identified at most three projects that are presently under development, any reductions in CO2 emissions achieved would be minimal. This is especially true given that any plant that is constructed will be subject to existing source standards EPA promulgates under Section 111(d). The commenter stated that they executed binding contracts for the purchase and erection of the Plant Washington boiler prior to publication of the proposed rule and believes these contractual obligations are more than sufficient to constitute commencement of construction for purposes of the NSPS program. The commenter anticipates that Plant Washington will be an existing source subject to any existing-source standard EPA may promulgate under Section 111(d) of the Clean Air Act. The commenter stated that they addressed their permit status in comments (an attachment to these comments) on the previous proposed rule and unlike the previous proposed rule, the current proposed rule would allow Plant Washington to obtain the pollution-control guarantees necessary to move forward. The commenter recently sought and received an extension of the construction deadline in its PSD permit, which is currently undergoing public comment. EPA should adopt its proposal and create a sub-category for the three projects identified in the Proposed Rule, which would allow for development of a site-specific CO2 standard based on BSER for each facility.
Regarding EPA's proposal to consider a subcategory for three coal-fired projects currently under development with construction permits, including the proposed Wolverine EGU project in Rogers City, Michigan, the proposed Washington County EGU project in Georgia, and the proposed Holcomb EGU project in Kansas, one commenter (9666) stated that it is rational for the Agency to exercise its section 111 discretion by subcategorizing this category and excluding the three coal-fired power plants that are so far along in the permitting process that this proposal would make it impossible for them to be completed. 
One commenter (8909) agreed with EPA's proposal [not proposing standards for "transitional units", i.e. fossil fuel-fired EGU projects presently under development that were fully permitted but had not yet commenced construction at the time of the proposal], especially given the sparse universe of potential "transitional" sources.  In the unlikely event that any transitional EGU commences construction, EPA should develop a GHG NSPS specifically for that source.
One commenter (10394) stated that EPA's proposed approach will create uncertainty in projects which may have already undergone full permitting, but are undergoing financing prior to commencement of construction. The commenter recommends that EPA propose a deadline similar to the GHG Title V Tailoring Rule, so that it provides a future date for an EGU which has been fully permitted, but has not yet commenced construction to become subject to the new standard. Otherwise, the EGU be subject to any GHG standards that EPA develops for existing EGUs.
 One commenter (9599) supports EPA's decision not to subject the Holcomb 2 project in Kansas to the proposed GHG NSPS. The commenter submitted background information including actions taken to date, timelines, sunken costs incurred, PSD permitting activities, and contractual activities.
 See preamble section III.J.
Two commenters (9514; 10119; 2983) did not support the exemption of transitional sources.
Commenter 9514 supported EPA's decision to "discard the transitional source classification, to abandon its approach of using sunk costs to determine BSER for these sources, and to apply the proposed standard to plants that are designed to meet it, such as the Texas Clean Energy Project." There is no legal justification for creating a separate subcategory based solely on "the stage of a source's development." Commenter 9514 noted that "Section 111 does not provide EPA with discretion to establish a special standard for a particular source that cannot be distinguished by type, size, or class." The commenter does not share EPA's apparent concern regarding the extent that [its]own actions related to the MATS rule may have hampered developers' efforts to commence construction provide a basis for special treatment of these sources. As shown above, EPA's actions were not the cause of the developers' delay. Rather, the projects were mired in legal issues and/or have been lacking in investor interest for years - issues entirely unrelated to the MATS rule. In any case, this is not a relevant factor to EPA when making a BSER determination or setting a performance standard.
 
Commenter 9514 stated, "To rely on a forthcoming 111(d) standard as an excuse for exempting certain new sources from a 111(b) standard also creates bad precedent that could be applied beyond the context of this particular rulemaking." 
 
Commenter 10119 stated that there is no factual basis for exemption of transitional sources and results in a lack of notice to the public. Any attempt by EPA to exempt these transitional sources based on the relative size of its projected investment loss would be perpetually behind and constantly require, as it does here, to rule blindly and without factual basis for some sources. EPA's lack of facts also, by necessity, translates into lack of notice to the public and the inability to comment, automatically invalidating the action for that reason alone. The commenter stated that EPA is not, and should never be, in the business of carving out one-off exemptions from NSPS standards based on a concept as nebulous as lost business opportunities. Moreover, EPA should not create incentives for the most powerful individual facility owners to seek to exert undue influence over its decisions. Congress has drawn a bright line about who is covered by proposed new performance standards, and EPA is required to enforce it.
 
Commenter 9514 asked that EPA define the timeframe and process for determining the status of the transitional sources and offered support for the classification of the transitional sources as new sources. The commenter stated that in the final rule, EPA should make clear the process by which it will make this determination, including the time frame for this decision and the opportunity for public participation. As a number of the Joint Environmental Commenters explained in their 2012 comments on the initial NSPS proposal, state environmental agencies have not been reliable in enforcing EPA's guidance or other authorities interpreting this definition. Indeed, the state of Kansas recently enacted into law a provision that purportedly gives the state permitting agency authority to regulate greenhouse gas emissions from sources under development and requires the state agency to base its regulation on a variety of factors not permitted under the CAA. Given the history of state backing of these plants, including issuance of decisions later struck down by state courts, it is especially inappropriate to rely on the states to enforce the definition here. EPA must therefore make clear both the timeline and process for EPA to determine the final status of these plants.
 
Commenter 9514 offered support that each of the three transitional sources should not be considered existing sources. 
Overall:
-significant evidence shows that none of these three sources is poised to begin construction at any time in the near future
 
Two Elk:
-Has a permit that has now lapsed due to lack of construction activity for many years
-Two Elk's 2003 PSD permit has expired due to lack of construction since 2007
-EPA's intention is ambiguous: not mentioned in Federal Register as a transitional source but was mentioned in the September 2013 PUD TSD
 
Plant Washington:
-Plant had not commenced construction by April 13, 2012: "the PSD permit authorizing construction of Plant Washington was not final or legally effective until June 15, 2012"
-The record lacks any evidence that P4G has retained an EPC contractor, a necessary first step in designed and building an electric generating unit.
-It has not secured contracts to construct the balance of the plant
-Nor has it sought or obtained an NSPS applicability determination form EPA.
-The plant has requested an extension from the Georgia Environmental Protection Division of the commence construction deadline for its preconstruction air permit under the closely analogous provision of the PSD program, acknowledging in September 2013 that:
1.      it had not obtained vendor guarantees
2.     it had not secured necessary construction financing
3.      it had not completed designs for the plant
4.      it had not finalized construction arrangements
 
Holcomb 2:
-Developers assert in February 13, 2013 letter that its sunk costs are sufficient to have 'commence[d] construction but the commenter noted that EPA's regulations defining commencement of construction do not include a developer's sunk cost amount the factors relevant to such a determination
-Plant has not begun a continuous program of physical construction.
-The Holcomb developers have not received necessary approval from the Rural Utilities Service.
-The Holcomb Project may not commence construction without a valid PSD permit."
-Tri-State submitted a resource plan update to state regulators in 2012 representing that no new coal-fired generating capacity - not the Holcomb project nor any other coal-fired Facility - is either needed or expected to be added to Tri-State's portfolio within the next 20 years.
 
Wolverine:
-Mentioned in Federal Register but has been cancelled [Reference: 79 FR 1461-62]
See section III.J.
One commenter (10098) stated that because of the unique impact of Section 111(a)(2) on new sources, which are subject to the rule at the time of proposal, this proposed rule is causing harm now. Upon proposal, any new facilities must commit resources to meet the stringency of the proposed standard.
 This effect is created by statute, which fixes an NSPS trigger date, and is not a consequence of anything specific to the present action.
Commenter 10119 pointed out  that "transitional relief" from the proposed rule will create many negative incentives, such as discouraging industry from anticipating changes in legal rules, affording exempted facilities relief from regulations with which others must comply, creating an unequal competitive playing field; depriving the public of the regulation's benefits while bestowing a windfall on the exempted facilities, discouraging early adoption of improved and advanced technology, shielding exempted sources from market pressures that would otherwise promote technological advances and environmental benefits more quickly and broadly, creating expectations that laws will change or can be avoided; creating disincentives for voluntary and early compliance; and rewarding lobbying.
 See section III.J.
Commenter 10119 stated that while EPA has the authority under section 111(b)(2) to create a new subcategory for Wolverine, Washington County and Holcomb, doing so would create a category because these three projects might suffer opportunity costs arising solely as the result of the specific timing of proposal of the instant new standard. Therefore, the commenter asserted that no other future project could ever qualify, creating an exemption rather than a subcategory and retarding rather than encouraging the development of improved technology.
 See section III.J.  The EPA does not see that exempting plants that may never operate, but if they do may be unable to meet the standard of performance based on previously approved designs, would not otherwise compromise the national standard.  As noted in the preamble to the final rule, the EPA would carefully examine whether these plants (should they oeprate0 can achieve the standard of 1400 lb CO2/MWh.
