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.