6
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## 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 L iterature on CCS
................................ ................................ ................................ .............. 6 6.3.2 Similarity

to Controls Required in Previous NSPS Rulemakings
................................ ... 13 6.3.3 The Range of Emission L imits EPA I s Considering Cannot Be Ac hieved by a Coal
- Fired EGU without the Use of CCS
................................ ................................ ................................ ... 17 6.3.4 CCS Technical I ssues ................................ ................................ ................................ ...... 19 Post
- combustion CO 2 Capture
................................ ................................ .............................. 30 Ox y- combustion
................................ ................................ ................................ .................... 32 Pre
- Combustion CO 2 Removal
................................ ................................ ............................. 32 CO 2 Transport
................................ ................................ ................................ ....................... 33 Geologic Sequestration
................................ ................................ ................................ ......... 46 Enhanc ed Oil Recovery

and CO 2 Utilization
................................ ................................ ........ 71 6.3.5 CO 2 Transport and Geologic Sequestration Legal and Regulatory Issues
...................... 93 Geologic Sequestration Property Rights
................................ ................................ ............... 93 CO 2 Transport Legal and Regulatory Issues
................................ ................................ ......... 96 Safe Drinking Water Act’s Underground Injection Control (UI C) Program and Resource Conservation and Recovery Act
................................ ................................ ......................... 109 Greenhouse Gas Reporting Program
................................ ................................ .................. 120 Liability
................................ ................................ ................................ ............................... 130 Other CO 2 Transport and Geologic Sequestration Legal and Regulatory I ssues ............... 135 6.3.6 CCS I s/Is Not BSER
................................ ................................ ................................ ...... 140 Cost
................................ ................................ ................................ ................................ ..... 147 Adequate Demonstration
................................ ................................ ................................ .... 204 Promotion of Technological Development
................................ ................................ ......... 227 Nationwide, Long
- Term Perspective
................................ ................................ .................. 2336
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Energy and Nonair Quality

Environmental Impacts
................................ ........................... 236 Use of Purportedl y Extra
- Statutory "Purposes" to Justify

Standard of Performance
......... 243 Other BSER Options
................................ ................................ ................................ ........... 245 6.3.7 EIA Anal ys is
................................ ................................ ................................ .................. 252 6.3.8 Effect of the Proposed NSPS Rule on CCS Development, Demonstrati on and Deploy ment ................................ ................................ ................................ ............................. 253 6.4 Proposed Emission L imit of 1,100 lb CO 2 /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
................................ ................................ ....... 2746
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### 6.1 **GENERAL Comment 6.1**  **- 1:**  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. **Response 6.1 -**  **1:** Th e 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 s ection 111(b) New Source Performance Standards (NSPS) are intended to be applicable nationwide. 

### 6.2 **PROPOSED NSPS FOR NE W FOSSIL FUEL**  **- FIRED UTILITY**  **BOILERS AND IGCC UNI TS IS**  **N OT AN NSPS**  **Comment 6.2 -**  **1:** 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 C O 2 a source would release from the stack, yet the total CO 2 generated b y the source does not change as the remainder of the CO 2 generated b y the source is separated and sent somewhere with the expectation that it will be sequestered. Therefore, the comment er argued it would not violate the proposed NSPS if 100 percent of the CO 2 separated b y the capture technology subsequentl y was released to the atmosphere. According to the commenter, a standard defining "new source performance" must be based on a s ys tem o f emission reduction incorporated into the new source itself and the underground "sequestration" of separated CO 2 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 seques tration, 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 CO 2 generated by a source: instead, it merel y requires that new sources separate some percentage of the CO 2 from its flue gas stream, without imposing any requirements regarding the CO 2 's ultimate fate. The commenter stated that the proposal is a "carbon separation" s ys tem, not a "carbon capture and sequestration" s ys tem, 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 "s ys tem of emission reduction" as it does not contain any limitation requiring on
- site disposal of captured CO 2 through sequestration or any limitation requiring off
- site s equestration. **Response 6.2 -**  **1:** 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 ba ghouse 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 under6
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section 111 (a) (1) to consider non
- air quality health and environmental impacts and other collateral consequences of this rulemaking, the EPA has carefull y assessed the integrity and safety of the transport and sequestration of captured CO 2 . It is EPA’s considered and reasonable belief that the plenary

regulatory

standards for CO 2 pipelines assure pipeline safety, and the comprehensive regulatory standards for Class VI and Class II injection wells (and the long history of safel y- conducted use of CO 2 for EOR), in combination with the reporting re quirements of the subpart RR GHG reporting rule (including the comprehensive monitoring, reporting and verification plan required under those rules) assures that captured CO 2 will be safel y tracked to a sequestration repository , and that CO 2 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 s ub
- surface monitoring regime, would assure containment within a well’s injection zone, and thereby also prevent any release of sequestered CO 2 to the atmosphere . The monitoring would also be sufficient detect any potential escape from the injection zone before there could be any release of CO 2 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 overl y stringent (e.g. the 50
- ye ar post - closure care requirement). In short, section 111 (a)(1) standards of performanc e 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 reasonabl y done so here
. **Comment 6.2 -**  **2:** Commenter 9774 stated that EPA is applying the NSPS to a range of sizes and ty pes of generation technology that were not evaluated in EPA's anal ys is of CCS. The commenter stated that EPA only evaluated the cost of CCS based on applying the technolog y to a 550 MW supercritical boiler and therefore the proposed NSPS should not apply to other typ es of coal generating units. According to the commenter, EPA must acknowledge that generating units employ

varying technologies serving specific needs and a NSP S analy sis and limit must be developed specificall y 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 ox y- f iring, which has the potential to significantly increase the efficiency of boilers and decrease CO 2 emissions as compared to the super
- critical coal
- fired boiler assumed in the analy sis. However, the commenter stated that ox y- 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 effectivel y prohibit the use of this and other emerging boiler technologies, even if they provide a better overall outcome. **Response 6.2 -**  **2:** The final standard of performance is based on the performance of a highl y efficient SCPC implementing partial CCS

– at a reasonable cost. The final standard of 1,400 lb CO 2 /MWh
- g can be achieved b y a highl y efficient SCPC burning bituminous coal b y implementing about 16% CC S 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 (L COE)

–6
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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 es timate provided b y 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 deve lopers 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 ox yfu el combustion system to implement CCS. The system inherentl y produces a high concentration CO 2 stream. In fact, such a sy stem would be able to achieve a much more stringent emission rate than is required b y the final standard. The E PA did not consider oxyfuel combustion as a BSER technology because of the relativel y few demonstration projects (esp ecially in the U.S.

– no large
- scale demonstration projects) and the lack of cost information. However, if a project developer chooses to c onstruct a new ox yf uel combustion EGU in the future, the final NSPS will not hinder the feasibility to pursue the project in any way . **Comment 6.2 -**  **3:** Commenter 9513 stated that the exemption for IG CC less than 50% sy ngas 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. **Response 6.2 -**  **3:** Some I GCC 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 CO 2 /MWh
- g. However, as we note in the preamble, many new IGCC units wi ll be able to meet this standard b y co - firing only a small amount of natural gas and would be unlikely to install a CCS sy stem 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 sy stem

– such as the co
- production of chemicals. **Comment 6.2 -**  **4:** 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 onl y on - site separation of CO 2 , 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. **Response 6.2 -**  **4:** The standard of performance does ensure that there is a reduction in the emission of CO 2 from the affected facility. The comment sug gests that the EPAs proposed performance standards should have included some additional requirements to ensure that6
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captured CO 2 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. 

### 6.3 **CCS Comment 6.3**  **- 1:**  Commenter 0775 stated that they are pleased that the allowable CO 2 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 emi ssions. 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. **Response 6.3 -**  **1:** 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 CO 2 per megawatt - hour
- gross ) f rom a new fossil fuel
- fired steam generating EGU (utility boiler or IGCC unit). Although the EPA conservativel y costed the rule based on the use of 16 % partial CCS (for new SC PC plants burning bituminous coal ), the EPA also noted that there are other compl iance paths available for both of these ty pes of sources. 

### 6. **3 .1 Literature on CCS**  **Comment 6.3 -**  **2:** 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. **Response 6.3 -**  **2:** 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. **Comment 6.3 -**  **3:** Commenter 2471 stated that EPA may not have conducted a proper peer review, including cross
- media impacts to water and soil. **Response 6.3 -**  **3:** The EPA disagrees
. In fact, the SAB Workgroup stated by letter endorsed by the full Co mmittee 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 L iaisons, p. 3. The same Workgroup likewise found that the NETLmaterials had been fully peer reviewed, and that the Department of Energy peer review procedures also satisfied the EPA Peer Review Guidelines. Id. **Comment 6.3 -**  **4:** Commenters 8966 and 9396 stated that EPA ha s violated the Data Quality Act because the supporting literature cited b y the proposed rule constitutes a highl y influential scientific assessment (HISA) that requires its own peer review under the OMB Peer Review6
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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 HI SA. **Response 6.3 -**  **4:** These comments are addressed in Chapter 2 in the unit discussing issues related to the Data Quality Act. **Comment 6.3 -**  **5:** 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 comm ercial 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. **Response 6.3 -**  **5:** 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 sy stem of emission reduction adequatel y demonstrated. As stated in section V.D of the preamble to the fi nal 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 ( s ee generally in section V .G.3 ), and variable operating conditions, and use of different fuel ty pes (see sections V.J.1 and V.J.2). **Comment 6.3 -**  **6:** The commenters then discussed the EPA cited studies, noti ng that the Task Force report is not a final report of research and development results, the 2009 PNNLreport cites CCS for coal
- fired EGUs as a future technology requiring vigorous ongoing research, development and demonstration, and NETL's Cost and Perfo rmance 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 no ted 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. **Response 6.3 -**  **6:** 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 deploy ment of CCS within 10 years ...” Much of what is written in technology readiness assessments and oth er 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 technolo gy 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 s ources and ultimatel y 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 CO 2 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 that6
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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 ent ail 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 bas is. For these reasons, although some individual facilities may find implementation of CCS to be a viable CO 2 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 ex isting EGUs in this rulemaking. Nevertheless, CCS would be available to states and sources as a compliance option. **Comment 6.3 -**  **7:** 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 s cale power plants. **Response 6.3 -**  **7:** The EPA stands by its determination that implementation of partial CCS is adequatel y 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+% ca pture) can be economically deplo ye d 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 CO 2 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 utili zation of full
- or partial
- CCS. **Comment 6.3 -**  **8:** 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 CO 2 separation equipment are based6
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on an equipment list that was not peer reviewed and not based on actual operating experience under a range of relevant co nditions. The commenter concluded that the report cannot therefore be relied upon to support a finding that the CO 2 separation rates are actually "achievable" within the meaning of section 111. **Response 6.3 -**  **8:** First, the NETL cost estimates were adequatel y peer reviewed, and the SAB Workgroup so found. The study report(s) the DOE/NETLexplained 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/NETLreport, pages 44
- 45). The EPA un derstands 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 wi thout 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

expensi ve – 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/NETLnoted in the updated (2015 report) that “[T] his revision reflects va rying degrees of technology vendor input for updates to the pollution control equipment for PC plants, and the CO 2 capture, CO 2 compression, and steam turbine technology for PC and NGCC plants ...” **Comment 6.3 -**  **9:** Commenter 10044 stated that the NETL data on which EPA relie s 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 **Response 6.3 -**  **9:** 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 ve rsion 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 clearl y that the cost estimates represent the next commercial offering costs, consistent wi th their presentation in the NETLreports. It6
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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 NETLmaterials in a manner inconsistent with the authors’ intent. However, partl y 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 B oundary Dam Unit #3 facility
. **Comment 6.3 -**  **10:** 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. C ommenter 10618 recommended that EPA anal yz e 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. **Response 6.3 -**  **10:** 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 reasonabl y be projected to be available to new sources at the time they

are constructed that will allow them to meet the standard. Specificall y, 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 an d 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 NETLreports. The ‘Objective’ of the NETL studies was given (report in ‘NETLViewpoint’) 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 and6
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without carbon dioxide (

CO 2 ) capture and sequestrati on 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 d esigns are necessarily conceptual, they

represent fossil fuel fired plants that “use technology

available today”. We also note that, while we did rel y 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 ty

pes is discussed in the preamble section V.J.1 and V.J.2 and also in a Technical Su

pport Document (TSD)

– “Achievability of the Standard for Newl y Constructed Steam Generating EGUs” available in the rulemaking docket. **Comment 6.3 -**  **11:** 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 directl y address carbon storage, the SAB questioned the adequacy of the peer reviewed studies in a November 2013 memo. **Response 6.3 -**  **11:** This comment reflects a significant misstatement or misimpre ssion. 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/NETLstudies and noted that the peer review of the NETL studies, conducted b y DOE, met the requirements of EPA's Peer Review Handbook. The Workgroup, in a letter endorsed by the full Co mmittee, then found that “while the scientific and technical basis for carbon storage provisions is new and emerging science, the agency is us ing the best available science ... ”
. (See Letter of Jan. 7, 2014 from SAB Workgroup Chair to Members of the Chartered SAB and SAB L iaisons, 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 CO 2 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. **Comment 6.3 -**  **12:** Commenter 10098 provided literature which estimates that CCS can increase water consumption b y 30
- 100 percent. **Response 6.3 -**  **12:** The EPA is aware that the use of CCS can increase water usage/consumption at a new facility
. The EPA has carefull y evaluated this issue in preamble section V.O.2 and finds the water use impacts of the final standard of performance to be reasonable
.6
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**Comment 6.3 -**  **13:** Commenter 8925 stated that CCS is likely to play a key role in any efforts to significantl y reduce carbon emissions, as evidenced by the Internation al 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 A ssessment Report, Working Group III Summary

for Policy

Makers. **Response 6.3 -**  **13:** The EPA agrees that numerous assessments have concluded that ultimate widespread use of CCS is likely necessary

to significantly

reduce global anthropogenic CO 2 emissions. **Comment 6.3 -**  **14:** Commenter 10108 provi ded 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 technicall y feasible, adequ ately demonstrated, and ready for broader deplo yment. **Response 6.3 -**  **14:** The EPA appreciates that the commenter has provided the list of these studies. **Comment 6.3 -**  **15:** 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. **Response 6.3 -**  **15:** 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 C CS. **Comment 6.3 -**  **16:** 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 recentl y concluded that "c apture 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 det ermine the status of CCS development for fossil fuel
- fired boilers and IGCC units. Commenters 9666 and 10239 asserted that CCS is not adequatel y demonstrated and cites the recent Climate Change Impacts in the United States study as stating that CCS demons tration 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 CO 2 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 b y the examples provided because they do not provide relevant, or authentic, experience for dedicated power generation, remain in construction or design phase, or onl y address post
- combustion, pre
- combustion and oxy
- combustion as i f the experience from one6
- 13

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
- fir ed power plants. Commenter 10618 argued that EPA ignored available information on CCS, providing references to and citations from numerous assessments b y public and private organizations that recognize that CCS has not been proven to be technically feasib le or adequatel y demonstrated for coal
based generation and that significant development barriers remain. **Response 6.3 -**  **16:** The EPA stands by its determination that implementation of partial CCS is adequatel y demonstrated. See preamble sections V.D. and E. The EPA also un derstands 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 pr esented in this rulemaking. The reports evaluated the technology readiness or feasibility of “full capture” (90+% capture) can be economicall y deplo yed on a wide
- scale and concluded such widespread implementation was not ye t feasible. EPA is not basing the promulgated standard of performance on full capture

– regarding it as unreasonably costl y. 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 techno logy

to existing sources. In none of the CAA 111 GHG proposals does the EPA suggest a requirement for widespread deplo ym ent of CCS across the existing fleet or for implementation of full
- capture CCS. . 

### 6. **3 .2 Similarity to Controls Required in Previous N**  **SPS Rulemakings Comment 6.3**  **- 17:**  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 e xtensive 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 on ly 45 MW of generating capacity has ever been equipped with a full y integrated CCS system. Commenters 8024, 9396, 9666, 10031, 10046, 10618 stated that adequate demonstration requires successful commercial scale demonstration, the ability to generalize si ngle 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.6
- 14

**Response 6.3 -**  **17:** 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 deploy ment of the technology , and spurred innovation as well. Se e 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 negati ve assertions “cannot be seriousl y 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 tec hnologies to remove NOx and Hg. Each of these claims has been proven wrong. **Comment 6.3 -**  **18:** Commenter 9666 discussed how the Great Plains Sy nfuels 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. **Response 6.3 -**  **18:** 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 Gasific ation 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 capture d CO 2 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. **Comment 6.3 -**  **19:** 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 sy stem of emission reduction." **Response 6.3 -**  **19:** 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 entirel y appropriate if the Administrator had justified the stan dard, 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. 2 d 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 full y- integrated CCS at 90% capture.6
- 15

**Comment 6.3 -**  **20:** Commenters 9666, 10618 stated that the development and demonstration history of controls for conventional pollutants like SO2 and NOx cannot accuratel y reflect the experience n eeded to demonstrate CCS, which is more complex and technically challenging than any sy stem of emission control applied to date. **Response 6.3 -**  **20:** There is no question that post
- combustion CCS is adequatel y 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”. Se e also preamble section V.D. **Comment 6.3 -**  **21:** 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 CO 2 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. **Response 6.3 -**  **21:** The same h ypothetical 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 SO 2 control infeasible. The amount of CO 2 that would need to be captured for a new 500 MW unit firing bituminous coal would be approximately 600,000 tons of CO 2 per year, which is only

about 6 times higher than the amount of SO 2 that would be required to be captured from a high sulfur bituminous coal (or nearl y 100 times the captured SO 2 when burning low sulfur PRB coal). However, in order to keep things in pers pective

– the h ypothetical 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. **Comment 6.3 -**  **22:** Commenter 9666 noted that unlike with FGD and SCR, the by product of CCS

- captured CO 2 requires specialized processing because it is unstable under normal atmosp heric conditions; captured CO 2 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 reacti ons secure the CO 2 over time. **Response 6.3 -**  **22:** The particulate matter (PM, ash) that is captured from a coal
- fired power plant must be carefully

handled and properl y stored as it contains toxic metals. So must spent activated carbon used to capture mercury . The CO 2 that is captured must be compressed and transported (potentiall y l ong 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 adequatel y demonstrated. See 76 FR 48082
- 83 (Aug. 8, 2011) (plenary regulatory

requirements for CO 2 pipelines). EOR operations using captured CO 2 transported in subcritical state via pipeline have been conducted successfully for decades. Class VI standards for Deepwell injection assure se cure storage of captured CO 2 for geologic timeframes. See preamble section V.N. **Comment 6.3 -**  **23:** 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 adequatel y6
- 16

d emonstrated 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 utiliti es; (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 ty pes of coals. Without data showing that dry scrubbing would actually allow coal
- fired EGUs of various ty pes to achieve the NSPS, it could not be considered to be adequatel y 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 "adequatel y demonstrated." **Response 6.3 -**  **23:** EPA’s final BSER determination is entirely consistent with the D.C. Circuit’s anal ys is 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 “adequatel y 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 b y 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 pe rformance 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 just ify that a technology is adequatel y 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 p artial CCS at full scale co mmercial 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

reasonabl y 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 agenc y need onl y 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."). Fo r example, the NETLreports provide a detailed description of the following sy stems projected to be needed for a supercritical PC to capture CO 2 : coal and sorbent receiving and storage, steam generator and ancillaries, NOx control sy stem, particulate control, flue gas desulfurization, flue gas s ys tem, CO 2 re covery facility , steam turbine generator sy stem, balance of plant, and accessory electric plant, and instrumentation and control sy stems. 1 Moreover, the AEP Front
1 NETL, pp. 54
- 74 (2013). There are comparably detailed description s for full
- scale pre
- com bustion capture system for an IGCC. Id. pp. 192
- 222 (describing coal receiving and storage, coal grinding and slurry preparation, air separation unit choice and integration, gasification, raw gas cooling/particulate removal, syngas scrubber/sour water stripper, water gas shift reactors, mercury removal, acid gas removal, CO 2 com pression and dehydration, sulfur recovery/tail gas cleanup process selection, slag handling, power island, steam generation island, accessory electric plant, and instrumentation and control).6
- 17

End Engineering and Design (FEED) Report, prepared after conclusion of the development study, describes in detail precisel y 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 CO 2 capture], ty picall y 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
... CO 2 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, CO 2 absorption, water wash and CO 2 /NH 3 stripping, refri geration sy stem, 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**  **Comment 6.3 -**  **24:** 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 f

urther 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). **Response 6.3 -**  **24:** 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 an y m eans of a source’s choosing. EPA specifically notes that there are alternative compliance paths to achieve the promulgated standard of 1 , 400 lb CO 2 /MWh
- gross for both PC units and I GCC units, including co
- firing with natural gas without using CCS. **Comment 6.3 -**  **25:** 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 commerciall y deployed. Additionally , Commenter 9471 noted that CCS has not been demonstrated as the best s ystem 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 costl y. **Response 6.3 -**  **25:** As previous stated, the EPA has shown that partial CCS has been adequately demonstrated and is commerciall y available for deployment at new coal
- fired utility boilers and IGCC EGUs. As just described above, the standards do not require utilization of partial CCS6
- 18

technology . Responses to comments related to cost of the technology are in unit below; see also preamble section V.I. **Comment 6.3 -**  **26:** Likewise, Commenter 10239 stated that EPA has not identified a single commercial
- scale EGU that c an meet the proposed emission limit using CCS or any other technology

nor is CCS adequatel y demonstrated, as determined b y past BACT determinations and EPA's own guidance. **Response 6.3 -**  **26:** The EPA has identified a commercial
- scale EGU that can meet

– and currently is meeti ng – the emission limit using CCS technology . The SaskPower Boundary Dam facility

is capturing 90% of the unit’s CO 2 emissions using commercially available carbon capture technology

(from Shell Cansolv; http://www.shell.com/global/products
- services/soluti ons - for
businesses/globalsolutions/shell
- cansolv/shell
- cansolv
- solutions/ CO 2 - capture.html ). The facility ’s emissions are well below the 1,400 lb CO 2 /MWh
- gross standard. Actually the emissions at the Boundary Dam facility must be below 1,400 lb CO 2 /MWh as Canada’s emission standard is 0.42 tonnes CO 2 /MWh, which is roughly equivalent to about 925 lb CO 2 /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). **Comment 6.3 -**  **27:** Commenter 9666 stated that EPA normally invites discussion regarding achievable emission limits, however they have not allowed outside anal ys is because no full
- scale EGUs have deployed CCS. **Response 6.3 -**  **27:** The EPA has engaged with a diverse set of stakeholders and specifi call y 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 deployingfull CCS. **Comment 6.3 -**  **28:** Commenter 9666 asser ted 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 lim it that may be met with ultra
- supercritical boiler designs. **Response 6.3 -**  **28:** The EPA stands by its determination that partial CCS is adequately demonstrated, that it is technicall y feasible, and that it can be implemented at a cost that is not exorbitant. See preamble section V. **Comment 6.3 -**  **29:** Similarly, Commenter 10952 asserted that BSER is arbitrary and otherwise not supported by

law, fact or adequate demonstration. **Response 6.3 -**  **29:** The EPA stands by its determination that partial CCS is adequately demonstrated, that it is technicall y 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. **Comment 6.3 -**  **30:** Commenter 9664 asserted that the NSPS emission limits must reflect those achievable through application of the best emission reduction s ys tem which the Administrator6
- 19

determines has been adequately demonstrated, however the demonstration may be based on rea sonable 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 th e time of the rulemaking as long as appropriate lead time is provided ( Portland Cement I

, 486 F.2d at 391). **Response 6.3 -**  **30:** The EPA agrees with this interpretation. 

### 6. **3 .4 CCS Technical Issues**  **Comment 6.3 -**  **31:** Commenter 10239 noted that permit writers have uniformly rejected CCS after conc luding that it is technologicall y 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 anal ys es 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. **Response 6.3 -**  **31:** The commenter cites to individual permit determinations reflecting perfor mance 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 adequatel y 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 pre amble section XII.C. **Comment 6.3 -**  **32:** 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 CO 2 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 historicall y separated CO 2 from natural gas streams, the processes are significantly different than the ones that are needed to capture CO 2 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 ty pes of contaminants in the gas stream characteristics, and  the tolerance needs of the catal ys t (e.g., amines must be active at a very low CO 2 partial pressure, must also be capable of tolerating nitrogen oxide and oxygen contamination) Commenter 10618 stated that EPA incorrectl y 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 CO 2 from industrial gas streams has occurred since the 1930's using a variety of approaches." For EPA to suggest that capture technologies should be readil y transferable to coal
- based el ectric generating units because of a long history of use in other6
- 20

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 s ignificant difference in the quantities and end use of the captured CO 2 , 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 CO 2 will be geol ogic sequestration or enhanced oil recovery processes, which pose much different challenges than capture from industrial gas streams "to produce food and chemical
- grade CO 2 ." Therefore, Commenters 9426 , 10098, and 10618 asserted that EPA must adequatel y de monstrate the use CCS technologies in power plants rather than a different, irrelevant industry
. **Response 6.3 -**  **32:** The EPA agrees that the separation and capture of CO 2 from natural gas process is not the same as separation and capture of CO 2 from the flue gas stream of a f ossil 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) CO 2 capture s ys tems. The EPA has not used those s ys tems as the prin cipal basis for its “adequatel y demonstrated” determination. Rather, it has used the accumulated experience of CO 2 capture in various industrial sectors

– especiall y those experiences at fossil fuel fired EGUs such as the Boundary Dam facility

in Saskatch ewan, Canada. **Comment 6.3 -**  **33:** Similarly, Commenter 9780 stated that even in cases where the CO 2 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 volum e and the added responsibility

of EGUs to reliabl y supply power to the grid. **Response 6.3 -**  **33:** The EPA agrees that the separation and capture of CO 2 from non - EGU industrial facilities can differ from separation and capture of CO 2 from the flue gas stream of a fossil fuel f

ired 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) CO 2 capture sy stems. The EPA has not used those sy stems as the principal basis for its “adequatel y demonstrated” determination. Rather, it has used the accumulated experience of CO 2 capture in various industrial sectors

– especially those experiences at fossil fuel fired EGUs such as the Boundary

Dam facility

in Saskatchewan, Canada
. **Comment 6.3 -**  **34:** 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 c ourt decisions regarding the need for demonstration of commercial scale s ys tems. Commenter 9661 stated that CCS integrated with electricity generation is not commerciall y available or technicall y 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 deploy ment during the CAA mandated review of the proposed NSPS in eight ye ars .6
- 21

**Response 6.3 -**  **34:** The EPA notes that while the commenters claims that “CCS integrated with electricity generation is not commerciall y available or technically feasible”, the facts show that it clearl y is both technically feasible and commercially available. The SaskPower Boundary Dam facility is currentl y using commerciall y available Shell Cansolv technology to capture CO 2 at full
- scale. The captured CO 2 is being transported for use in EOR operations or for long term sequestration
. Boundary

Dam Unit 3 (BD3) was recentl y 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 actuall y 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 MacNau ghton was extolling CCS technology after successfull y installing it at the existing AEP Mountaineer coal
- fired EGU: “The technology works” and “findings from a recentl y - conducted cost anal ys is 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.” 2 **Comment 6.3 -**  **35:** 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. **Response 6.3 -**  **35:** These statements were in a different context: deploy ment 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 deploy ment of CCS technology
. **Comment 6.3 -**  **36:** Commenter 9505 stated that rather than follow the statutory text, EPA effectivel y 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 'adequatel y demonstrated' standard, and rather than assessing whether CCS technology is reasonably

reliable, reasonabl y 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 t echnicall y 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. **Response 6.3 -**  **36:** Many

of these issues are addressed in chapter 2 of th is RTC. In brief, EPA’s anal ys is 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. technicall y feasible under the range o f operating conditions under which it would operate), reasonabl y efficient, and capable of performance at commercial scale without exorbitant costs.
2 www.alstom.com/Global/US/Resources/Documents/Press%20Releases/PR_JMacN_CCSbriefing_FINAL.pdf (August 4, 2011).6
- 22

Boundary Dam and Dakota Gasification are both full scale operations where CCS is operating successfull y . A lthough Dakota Gasification does not generate electricity , the process b y which sy ngas is generated is equally usable b y IGCC or chemical g asification (see section V.E.2 of the preamble to the final rule). **Comment 6.3 -**  **37:** Commenter 10036 stated that more research on CO 2 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. **Response 6.3 -**  **37:** Standards for C O 2 pipelines under 49 CFR Part 195 are well established and assure safety of transported CO 2 of whatever origin. **Comment 6.3 -**  **38:** Commenter 9770 stated that EPA would need to demonstrate that existing infrastructure
- pipelines and CO 2 storage exists to safel y sequester large amounts of CO 2 across the country

before the technology

is considered achievable. **Response 6.3 -**  **38:** EPA has already made (unchallenged) findings that the existing regulatory structure for CO 2 pipelines assures safety of transported CO 2 . 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 VIrules for geologic sequestration of CO 2 , in concert with the GHGRP subpart RR reporting provisions, provide assurance th at CO 2 will remain sequestered for long
- term storage without endangering underground sources of drinking water and without release to the atmosphere
. **Comment 6.3 -**  **39:** Commenter 10095 stated that carbon capture has not been "adequatel y demonstrated" in a pre or post
- combus tion 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 prop osal and noted that none of these projects is commercial
- scale and none has been proven to deliver the reliable, continuous CO 2 removal needed for compliance with this proposal. Commenter 10618 stated that while pre
- combustion, post
- combustion and oxy
- comb ustion capture s ys tems are technically feasible, they

have not been adequatel y demonstrated at a coal
based power plant on a commercial scale. The commenter continues that this has certainl y not been demonstrated as an integrated process with CO 2 utilizati on or storage. Commenter 10039 stated that EPA did not consider the stack conditions differences when a CCS sy stem 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, wh ich effects the concentrations of other pollutants in the flue gas stream. These pollutants are regulated b y 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 anal y sis under PSD. Commenter saw no indication that EPA made an analy sis of this effect in the docket.6
- 23

Commenter 2471 stated that EPA's support for CCS makes false assumptions, including the ability of CCS to separate, inject and hold or store CO 2 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. **Response 6.3 -**  **39:** Comme nter 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 adsorpt ion (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 EP A 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 sy stem for reduction of CO 2 emissions from fossil fuel
- fired EGUs. A more in
- depth discussion of carbon capture technologies is provided in a Technical Support Document (TSD)

– “L iterature Survey of Carbon Capture Technology”

– available in the rulemaking docket

– EPA
- HQ
- OAR
- 2013
- 0495. Regarding Commenter 10039’s as sertions 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 onl y require a CCS system that treats a small portion of the bulk flue gas (~ 20%). Further, the use of post
- combustion chemisorption
- based capture s ystems (primarily amine
- based) will require added heat to desorb the captured CO 2 and regenerate the solvent. The EPA also notes in the final preamble that ... “[ M ] any post - combustion solvents will also selectivel y remove other acidic gases such as sulfur dioxide (SO 2 ) and hydrochloric acid (HCl), which can result in degradation of the solvent. For that reason, the CO 2 scrubber s ys tems 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 CO 2 capture sy stem. See also RIA chapter 5 (quantifying SO 2 redu ctions 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 s ources 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 VIprogram. It would not have done so, and under the regulations could not have done so, without d emonstrations that CO 2 would be securel y confined to prevent the movement of fluids into or between USDWs or into any unauthorized zones
. One of these projects was for a steam6
- 24

generating EGU. Furthermore, international experience with large scale commercial GS projects has demonstrated through extensive monitoring programs that large volumes of CO 2 can be safel y 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 s ys tems 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 b y 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 facil ity in a location that ensures adequate space for the carbon capture s ys tem. **Comment 6.3 -**  **40:** 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

th at 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 C CS was rejected as too expensive in addition to other rejection factors. **Response 6.3 -**  **40:** 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 specifi cally , 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 generall y considers CCS to be an ‘available’ add
on pollution control technology for facilities emitting CO 2 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 analy ses, 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. **Comment 6.3 -**  **41:** Commenter 9666 pro vided discussion about each of the three methods of CO 2 capture, noting that none has been adequatel y demonstrated. **Response 6.3 -**  **41:** See preamble sections V.D. and E. **Comment 6.3 -**  **42:** Commenter 9202 encouraged EPA to tighten the rule with regard to CCS technology

and supported the use of captured CO 2 for enhanced oil and gas recovery6
- 25

**Response 6.3 -**  **42:** The EPA is not predicating its cost anal ys is on EOR revenue opportunities, but of course such opportunities exist. See preamble section V.H.8. **Comment 6.3 -**  **43:** Commenter 9666 provided a figure titled Schedule of Pilot and Dem onstration 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 CO 2 capture design lessons, and additional issues separate from CO 2 capture will require at least an additional 2
- 4 years of observation beyond first CO 2 injection. **Response 6.3 -**  **43:** 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, full y 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

develope rs, 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 te chnology

developers with an opportunity

to test new and emerging carbon capture s ys tems 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 Souther n Company ’s Plant Gaston in Wilsonville, AL

– provides first
- class facilities to test new capture technologies for extended periods under commerciall y representative conditions with coal
- derived flue gas and s yn gas. The EPA has provided much discussion reg arding the status of CO 2 injection in preamble section V.M and elsewhere throughout this Chapter of the RTC. **Comment 6.3 -**  **44:** 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 CO 2 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 sy stem 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 l oad 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 operati ons 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 EGU6
- 26

dy namic operation. In addition, some capture s ys tems may have a capture sy stem design specifications requiring other treatment and equipment. In addition, the capture sy stems 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 es t ate for capturing just 20%, as demonstrated b y 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 sy stems' demands for CO 2 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 injecti on rate or demonstrated this level of capacity
. The commenter also noted that the increased auxiliary load for CO 2 capture equipment is likely to result in an overall decline in plant efficiency , thus increasing the real CO 2 emission rate. **Response 6.3 -**  **44:** 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 b y 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 previousl y proposed Trailblazer Energy Center, a 760 MW SCPC EGU that was proposed to include 85 t o 90 percent CO 2 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 ultimatel y 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 (computatio nal fluid dy namics) analy sis, (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 utilizin g 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 sy stems may require additional control equipment to be installed upstream to remove flue gas components that may degrade the capture solvents (especiall y amine
- based solvents). These considerations have been included the cost estimates developed b y DOE/NETLand used by EPA in this final rulemaking. The EPA has specificall y addressed energy demands (and increase d 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 CO 2 from a fossil
- fired EGU can go to both EOR, and the excess to a deep saline formation , while still meeting customer demand
.6
- 27

Ge ologic 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 VIprogram. The Archer Daniels Midland Class VI permit is for injection and sequestration of an estimated 5 .5 million tons of CO 2 . The FutureGen Class VI permit s are for 22.5 million tons of injected CO 2 . 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 safel y sequestering the injected CO 2 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 CO 2 to the atmosphere. Additionally , there are several large scale CO 2 sequestration projects including the Illinois Basin Decatur Project an d the Cranfield (Tuscaloosa) Project that demonstrate that storage of large amounts of CO 2 can be achieved. In April 2015, DOE announced that CCS projects supported b y the department have safel y and permanentl y stored 10 million metric tons of CO 2 , which i s 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 CO 2 can be safel y injected and securel y sequestere d for long periods of time at volumes and rates consistent with those expected under this rule. **Comment 6.3 -**  **45:** Commenter 9666 stated that recognizing the limited experience with ox ycombustion capture technology , EPA noted in its Technical Support Document addressing EPA ct that the proposed rule relies onl y on post - and pre
- combustion capture as the basis for its BSER determination for Subpart Da units **Response 6.3 -**  **45:** Yes, that is correct. **Comment 6.3 -**  **46:** Commenter 966 discussed that one additional aspect of CCS is the implication for increased water us e, which escalates significantly for CO 2 - control power stations. The commenter discussed a DOE study on water use patterns for different ty pes 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 suppl y. Currentl y, Kemper has a 90 acre reservoir, which is a 50 day suppl y. **Response 6.3 -**  **46:** See preamble section V.O.2. **Comment 6.3 -**  **47:** Commenter 10097 stated the proposed BSER of partial carbon capture is not available over reasonabl y wide geographic areas and is therefore not adequately demonstrated. According to the commenter, although the proposed BSER does not include necessary infras tructure availability such as CO 2 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 availabili ty of infrastructure needed to transport and sequester the CO 2 captured by coal
- fired EGUs with the proposed BSER, because there is little infrastructure available to support this requirement.6
- 28

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 currentl y not available or even considered. It is simply not feasible given the unique circumstances in Alaska. Commenter 10052 stated EPA's assessment that CO 2 has been safely transported via pipelines in the U.S. for nearl y 40 ye ars and that 95 percent of the 500 largest CO 2 point sources are within 50 miles of a possible geologic sequestration site is broadly con clusory

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 Wisc onsin 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 evenl y 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 sy stem for pollution control must not be dependent on geographical distinctions, such as EOR, geological formations for storage capability , and feasibility of installing pipelines for CO 2 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 enco urage the use of local fuels. The commenter also stated EPA must also consider increased fuel transportation costs and increased electricity transmission costs incurred b y locating an EGU facility proximate to geologic formations favorable to CO 2 sequestration. **Response 6.3 -**  **47:** The commenter’s (commenter 7977) citation to the WEPCO decision is obscure. The case (decided, incidentall y b y the 7 th Circuit, not the D.C. Circuit) deals primaril y with the issue of what activities constitute a modification. To the extent the cas e 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 BS ER 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 se questration 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
. Th ere are also alternative compliance pathway s for both PC and I GCC sources which would not involve CO 2 capture and sequestration at all, and for which there would be no issues of geographic availability
. With respect to the commenter’s assertion about Alas ka, the EPA disagrees that geologic sequestration is not feasible in Alaska. NETLhas noted GS potential in hydrocarbon reservoirs of the North Slope and Cook Inlet because of their proximity to large stationary CO 2 sources and the potential6
- 29

for CO 2 - EOR. 3 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. 4 The development of pipeline infrastructure is proven and, a s described in preamble section V. M
. 5 , the operational experience of the oil and gas industry provides confidence that CO 2 transportation and storage can be undertaken in a safe and effective way
. The EPA agrees that pipelines of longer or shorter distanc es than 50 miles may be constructed for compliance with the NSPS
. Inestimating 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 8 0 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 CO 2 pipelines operating in the United States. This represents a seven percent increase in CO 2 pipeline miles over the previous year and a 38 percent increase in CO 2 pipeline miles since 2004. T he design, construction, operation, and safety requirements for CO 2 pipelines have been proven , and the costs of CO 2 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 highl y site
- specific circumstances. A monitoring program and its associated infrastructure (e.g., monitoring wells) and costs will be depen dent on site
- specific characteristics, such as CO 2 injection rate and volume, geology , the presence of artificial penetrations, among other factors. Itis thus not appropriate to generalize from AEP’s experience, and thus not appropriate to assume that oth er 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 VIwells 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. **Comment 6.3 -**  **48:** Commenter 8957 provided the following: "In the EPA's discussion on the technic al 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 mill ion metric tons of CO 2 from 1972 to 2005 in the Permian basin, which equates to approximately 3.1 million short tons injected per ye ar. Itis also stated that 3 8 million metric tons of CO 2 were re - emitted from the same project, meaning that only 1.8 milli on short tons per year of the injected CO 2 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 CO 2 while operating at a 100% capacity factor."

3 The United States 2012 Carbon Utilization and Storage Atlas, Fourth Edition, U.S Department of Energy, Office of Fossil Energy, National Energy Technology Laboratory (NETL), p. 94. 4 Id. at 95 and 122.6
- 30

**Response 6.3 -**  **48:** The EPA does not agree with the commenter’s asserti on. In the EOR process some of the CO 2 is recovered with the oil and the recovered CO 2 is separated from the oil and recycled so that it can be re
- injected into the reservoir. Large amounts of CO 2 can be stored via residual trapping, solubility trapping an d stratigraphic trapping. In the example cited by the commenter, 55 million tons of CO 2 were stored in the SACROC Unit in the Permian Basin over 25 years. No evidence of leakage was detected
. **Post -**  **combustion CO**  **2 Capture**  **Comment 6.3 -**  **49:** Commenter 9201 stated given the lack of full scale, commercialized, constantly

operating post
- combustion CCS capture facilities, broad commercial deploy ment 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 principall y of small coal
- fired boilers with a very small slip
- stream capture of CO 2 with the CO 2 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 CO 2 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 construc tion or at the preliminary engineering study

stage. **Response 6.3 -**  **49:** 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 successfull y and reliabl y (the projec t 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. **Comment 6.3 -**  **50:** Commenter 9201 stated that the large amount of energy required in regenerating CO 2 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 CO 2 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 sy stem, post - c ombustion CO 2 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). **Response 6.3 -**  **50:** The EPA has specificall y 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 w ill expect higher amounts of parasitic power demand
.6
- 31

**Comment 6.3 -**  **51:** Commenter 9666 summarized demonstrated instances of post
- combustion CO 2 capture and concluded that the sole relevant experience with post
- combustion CO 2 control is with Plant Barry's 25 MW
- equivalent pil ot 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 o r sequester CO 2 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. **Response 6.3 -**  **51:** The Boundary Dam facility is in fact now op erating successfull y – See preamble section V.D.2.a
. Itis selling much of the captured CO 2 and sequestering the remainder. Thus, the facility not onl y demonstrates feasibility of post
- combustion CO 2 capture, but successful sequestration of CO 2 as well, along with successful transport and use of captured CO 2 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. **Comment 6.3 -**  **52:** Commenter 2741 suggested EPA include a provision in the final rule enabling fossil fuel
- fired power plants to comp ly with the carbon dioxide emission standard b y 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 techn ology platform offers a unique means of permanently sequestering and utilizing CO 2 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 CO 2 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 CO 2 is being sequestered as solid calcium carbonate material (CaCO3), and the other equivalent of CO 2 is evolved as a pure stream, which can be sold for use in EOR, or re
- cycled in the L CP process. According to the commenter, Blue Planet's L CP process can cap ture 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

an d 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. **Response 6.3 -**  **52:** The final standard is a performanc e standard, and so does not compel a source to adopt any

particular control ty

pe. **Comment 6.3 -**  **53:** 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
.6
- 32

**Response 6.3 -**  **53:** 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 Comment 6.3**  **- 54:**  Commenter 9201 states technical concerns with ox y- combustion technology, including the increased potential for corrosion due to increased SO 2 concentrations in CO 2 gas streams and long
- term research and development needs that are unlikel y 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 ox ycombustion based on conventional cryogenic processes are scale
- up and reliability , and the auxiliary power penalty. T he commenter states that the auxiliary power penalty

negates any cost advantage of ox y- combustion over post
- combustion CO 2 removal. As a result, the commenter believes that this CCS technology is an unavailable commercial application at this time. **Response 6.3 -**  **54:** The EPA did not consider ox y- 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 s y stems have. Further, importantly , oxy- combustion is not applicable as a partial capture option as it inherently resul ts in a highly enriched flue gas stream
. Thus the opportunity to reduce compliance costs b y adjusting the capture rate is not available to oxy- combustion systems. **Comment 6.3 -**  **55:** 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. **Response 6.3 -**  **55:** See response to previous comments on oxy- combustion. **Pre -**  **Combustion CO**  **2 Removal**  **Comment 6.3 -**  **56:** Commenters 9201 and 9666 stated that IGCC equipped with CO 2 removal has ye t to operate in an integrated s ys tem for power production and although several chemical plants in the U.S. use gasification with CO 2 recov ery, none are primaril y designed for or representative of power generation as base load operations. The commenters discussed the demonstrated instances of pre
- combustion CO 2 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 CO 2 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 deplo ym ent with carbon capture cannot be reasonably anticipated to be a demonstrated option until 2020 at the earliest. **Response 6.3 -**  **56:** The EPA notes in the final preamble that a new IGCC unit will be able to meet the final standard of performance b y 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.6
- 33

**CO 2**  **Transport Comment 6.3**  **- 57:**  Commenter 10095 noted that fossil fuel
- fired EGUs cannot control actions of a downstream, third party CO 2 off
- taker
. The commenter further asserted that a robust network of CO 2 pipelines, offering power plants multiple CO 2 off
- taker options is needed to mi nimize 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 rel y on third
- party CO 2 pipeline and sequestration service providers. The need to overbuild will clearl y raise costs even further than the EPA estimates. **Response 6.3 -**  **57:** The EPA’s cost estimates do in fact include costs associated with transportation and storage of CO 2 . See preamble section V.I.5
. The United States ha s a robust pipeline network and the EPA dis agrees that the rule will necessitate “o verbuilding” of CO 2 pipeline sy stems . The CO 2 pipeline network in the United States has almost doubled in the past ten years in order to meet growing demands for CO 2 for EOR
. CO 2 transport companies have recentl y proposed initiatives to expand the CO 2 pipeline network. Several hundred miles of dedicated CO 2 pipeline are under construction, planned, or proposed, including projects in Colorado, L ouisiana, Montana, New Mexico, Texas, and Wyoming. **Comment 6.3 -**  **58:** Commenters 10039 and 10095 stated that the EPA cannot rationall y conclude that the U.S. CO 2 pipeline network is adeq uate 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 ye ars away . Commenter 10087 also noted that for many locations for coal
- fired power plants, such as in the Midwest, there are no existing CO 2 pipelines and none proposed. Commenter 8966 noted that the vast majority of the country

lacks any sort of dedicated CO 2 pipeline network altogether, including virtually the entire U.S. Midwest, Appalachian, and Eastern Seaboard regions. Commenter 10010 noted that CO 2 pipelines and storage capacity are not available in Florida
. Commenter 9657 notes that the EPA’s own analy sis notes that northern Georgia has no EOR operations, oil and gas reserves, saline formations, unmineable coal areas, existing or planned CO 2 pipelines, or natural CO 2 sources, and notes that there are dozens of coal electric generating units in the reg ion 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 CO 2 by

simply stating that 95 percent of the 500 largest CO 2 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 format ions regardless of other considerations, or to build miles of CO 2 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 Enhanced6
- 34

Oil Recovery

(EOR) is a potential option, there remain technical, legal, and cost challenges to siting and constructing pipelines from EGUs to EOR fields. **Response 6.3 -**  **58:** The EPA does not agree that th e transport of CO 2 through pipelines is an impediment to compliance with the NSPS. There is a robust regulatory framework in place already that addresses CO 2 pipe l ines. CO 2 pipeline specifications of the U.S. Department of Transportation Pipeline Hazardou s Materials Safety Administration found at 49 CFR part 195 (Transportation of Hazardous L iquids by Pipeline) apply

regardless of the source of the CO 2 and take into account CO 2 composition, impurities, and phase behavior
. These rules contain (among other p rovisions) detailed requirements related to reporting, pipeline design (temperature, pressure variation both internal and external, loads, ty pes of pipes, valves and fittings, connections, closure, and leak detection), construction, pressure testing, and c orrosion control
. CO 2 - specific provisions require special design for CO 2 at low temperatures
. 49 CFR section 195.102 (b)
. These requirements have applied for years, successfull y, to compressed, supercritical CO 2 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 CO 2 fro m Donaldsonville, L ouisiana, 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 CO 2 pipeline from fertilizer plant in Coffey ville, Kansas, to an oil field in Oklahoma. These large CO 2 pipeline projects demonstrate that long CO 2 pipelines can be sited effectivel y under the current regulatory system
. The commenters do not address whether new sources could site a source advantageousl y to account f or 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. **Comment 6.3 -**  **59:** 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 CO 2 for EOR operations or pipeline delivery capability

of the CO 2 to the oil fields
. Commenter 9236 noted that many oil fields are not able to utilize CO 2 flooding as an enhanced production method and in most cases the oil fields that are amenable to CO 2 use are located in remote areas far from electricity load centers, where larg e power plants would need to be sited in order to meet electric demands. This results in either long pipelines to deliver CO 2 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
.6
- 35

**Response 6.3 -**  **59:** The EPA does not agree that the rule would preclude the development of new EGUs in states that do not have current CO 2 - EOR operations
. New c oal
- fired EGUs in states or areas in which EOR operations are not availabl e could locate in the proximity of non - EOR sequestration formation s such as deep saline formations and transport the captured CO 2 by pipeline, or could locate near a sequestration site and transport the electricity generated to customers b y electric transmission lines. Additionally , the re are alternative compliance paths available to meet the promulgated standard of performance which do not involve sequestration
. **Comment 6.3 -**  **60:** 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 CO 2 pipelines in urban areas . Commenter 9201 also noted that existing CO 2 pipelines are rare near most population centers, and states with little or no storage capacity would have to construct costly, length y and expensive CO 2 pipeline systems. **Response 6.3 -**  **60:** The rule would not affect the abili ty of existing power plants to operate and would not require or necessitate construction of CO 2 pipelines to existing power plants. **Comment 6.3 -**  **61:** Commenter 10786 noted that no federal agency has given a favorable assessment to associated storage via CO 2 - EOR as an alter native in an Environmental Impact Analy sis (“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 CO 2 pipeline (which, in turn, supplied EOR projects) was a mere twenty miles away . FERC also concluded that while closer CO 2 pipelines appeared to be available, that CO 2 pipeline network “appears to be fully subscribed with CO 2 ” thereb y frustrating the ability of the Cameron LNG export terminal to engage in associated storage via CO 2 - EOR. FERC’s anal ys is of the potential for associated storage via CO 2 - EOR accuratel y reflects some of the complexities of the ty pical EOR situation

– to wit, even siting one’s project within a short twenty miles of an EOR
- supplying CO 2 pipeline failed to enable the use of CO 2 - EOR as a control technology
. **Response 6.3 -**  **61:** The rule applies on ly 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 CO 2 pipelines, has been adequatel y demonstrated for transporti ng large volumes of CO 2 safely
. See Preamble section V.N. **Comment 6.3 -**  **62:** Commenter 8966 stated that if the proposed rule is enacted, it is highl y unlikely that any new coal power plant operator would be able to transport captured CO 2 from its facility to a storage site for at least several ye ars. 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 cou ld develop. Therefore, Commenter 8966 concludes that the EPA must abstain from issuing any CCS
- based emissions standards until development of a nationwide CO 2 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 CO 2 pipeline facilities required to augment the6
- 36

proposal ’ s identified BSER, without which the rule would allow new sources to capture CO 2 emissions and subsequently em it 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 CO 2 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 b y lack of c ondemnation 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 onl y transport captured CO 2 a distance of twenty miles from the source. In addition, the commenter has learned, through a recentl y concluded DOE
- funded research project, that local basal geography and hydrology preclude the long
- term sequestration of CO 2 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 c an 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 gasificati on 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 CO 2 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 CO 2 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 CO 2 captured b y coal
- fired EGUs with the proposed BSER, because there is little CO 2 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 CO 2 pipeline infrastructure needed to transport the captured CO 2 must be availa ble immediately

in order for a facility to capable of achieving the proposed NSPS. Commenters 9407, 10097, and 10952 assert that the CO 2 pipeline transportation infrastructure needed to comply with the NSPS does not exist and will not exist within the fore seeable future. **Response 6.3 -**  **62:** The EPA does not agree that a nationwide CO 2 pipeline network must be developed in order for the EPA to issue this rule or that there needs to be changes in how CO 2 pipelines are operated
. At least one study estimated that of the 500 larges t point sources of CO 2 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 geol ogic formations for GS
. Th e design, construction, operation,6
- 37

and safety requirements for CO 2 pipelines have been proven, and the U.S. CO 2 pipeline network has been safel y used and expanded. Moreover, PHMSA data show that in 2013 there were 5,195 miles of C O 2 pipelines operating in the United States. This represents a seven percent increase in CO 2 pipeline miles over the previous ye ar and a 38 percent increase in CO 2 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 b y coal
- fired power p lants 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. **Comment 6.3 -**  **63:** Commenter 10660 stated that siting of CO 2 pipelines raises technical considerations that have yet to be resolved at scale and in all geographies. Commenter 10662 stated that the EPA simply dismisses CO 2 transportation and storage concerns and assumes that effective seque stration will occur. The transportation component of CCS is well
- established as technicall y feasible and is not a significant component of the cost of CCS. However, the EPA dismisses concerns over CO 2 pipelines and does not take into account the scale of transportation infrastructure and investment required to enable large
- scale deploy ment of CCS
. **Response 6.3 -**  **63:** The EPA’s cost estimates include reasonable cost estimates for CO 2 pipelines
. See section V.I.5 of the final rule preamble for the NSPS
. Moreover, there are alte rnative compliance pathway s for new sources that do not involve geologic sequestration or other CO 2 storage . Finally , the EPA is not “assuming that effective sequestration will occur”
. The EPA is reasonabl y rel yi ng on the robust and rigorous Class VIregulatory program to assure long
- term storage . **Comment 6.3 -**  **64:** 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 CO 2 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 constru ction 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 pip eline infrastructure to sell CO 2 into an EOR facility
. **Response 6.3 -**  **64:** 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.6
- 38

**Comment 6.3 -**  **65:** Commenter 9683 noted that the CO 2 generated b y facilities in several large western states, e.g., Arizona, Idaho, and Nevada, would need to be piped somewhere through CO 2 pipelines due to limitations on storage capacity. The EPA has not factored into its rulemaking the unavailability of a CO 2 pipeline network throughout the vast majority of the country , nor the fact that a substantial portion of existing CO 2 pipelines are not "common carrier" lines open to anyone ’ s use, but rathe r, are dedicated pipelines. **Response 6.3 -**  **65:** The EPA has considered the existing CO 2 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 CO 2 pipeline network in the United States ha s almost doubled in the past ten years in order to meet growing demands for CO 2 for EOR. CO 2 transport companies have recentl y proposed initiatives to expand the CO 2 pipeline network. Several hundred miles of dedicated CO 2 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 CO 2 pipelines that transport captured CO 2 as an impediment to the NSPS. Moreover, there are alternative compliance pathway s for meeting the promulgated standard of performance that do not involve geologic sequestration. **Comment 6.3 -**  **66:** 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 CO 2 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 reasonabl y close to an EOR site. **Response 6.3 -**  **66:** In the final rule the EPA has provided multiple compliance pathway s 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 CO 2 injection
. Potential se questration 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 s ome 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 unlikel y 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. **Comment 6.3 -**  **67:** Commenter 10108 suggested it would be reasonable for the EPA to conclude that future coal
- fired EGUs and EOR operators would dev elop new long
- distance pipelines to transport CO 2 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 CO 2 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 onl y about 50 miles of pipeline per plant. Commenter 10108 also noted that there are existing CO 2 pipelines that are 200 to 500 miles long, illustrating that such pipelines are feasible to construct
.6
- 39

**Response 6.3 -**  **67:** The EPA agrees that transport of CO 2 is feasible and that CO 2 pipelines of various lengths and capacities have already been sited and constructed and are feasible to construct . **Comment 6.3 -**  **68:** Commenter 10662 stated that the EPA references the existence of 3,600 miles of CO 2 pipeline in the U.S., the location of which are identified in Appendix H of the Global CCS Institute 2012 rep ort cited by Commenter 10662. Commenter 10662 noted that only 11 states have operating CO 2 pipelines, and 54 percent of the total CO 2 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 CO 2 annually , and Commenter 10662 provided a map of the existing CO 2 pipeline network and asserted that the limited CO 2 pipeline network will effectivel y 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 CO 2 pipelines are not addressed b y the EPA; the EPA dismisses the volume of gas that would need to be transported by simply stating that 50 million metric tons of CO 2 are currentl y transported annuall y b y pipeline
. The Commenter provided an estimate indicating that the entire existing CO 2 pipeline transport capacity is 188.3 million tons CO 2 per year, as compared to the 70 million tons per year of CO 2 emitted by

West V irginia alone
. **Response 6.3 -**  **68:** CO 2 pipelines are the most economical and efficient method of transporting large quantities of CO 2 . CO 2 has been transported via pipelines in the United States for nearl y 40 ye ars. Over this time, the design, construction, operation, and sa fety requirements for CO 2 pipelines have been proven, and the U.S. CO 2 pipeline network has been safel y used and expanded. The Pipeline and Hazardous Materials Safety Administration (PHMSA) reported that in 2013 there were 5,195 miles of CO 2 pipelines operating in the United States. This represents a seven percent increase in CO 2 pipeline miles over the previous year and a 38 percent increase in CO 2 pipeline miles since 2004
. The expansion of the CO 2 pipeline network in recent ye ars provides assurance that if needed, CO 2 pipelines can be permitted and constructed, and overall U.S. capacity for transporting CO 2 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. **Comment 6.3 -**  **69:** Commenter 10095 asserted that CO 2 compression and transportation is extremely energy intensive and expensive, and has not been adequatel y demonstrated at the commercial
- scale. The commenter stated that more experience is needed to understand how pipeline transportation specifications to maintain CO 2 quality (e.g., deh ydration, CO 2 polishing) may impact the overall reliability of the CCS system, and therefore the operation of the EGU. Commenter 9597 stated that CCS is challenged b y safety issues associated with long distance transport of CO 2 , a super - critical fluid
. Commuter 96 66 stated that the by product of CCS

—captured CO 2— requires specialized processing because it is unstable under normal atmospheric conditions. Captured CO 2 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 CO 2 over time.6
- 40

Commenter 10095 also stated that CO 2 transportation operations could also be affected b y the unsteady flow of CO 2 generated b y EGUs during load changes and planned and forced outages, and it is unknown how these fluctuations and suspensions will impact tr ansportation and injection operations. Commenter 10036 noted that a fter CO 2 is captured, it must be compressed “from near atmospheric pressure to a pressure between 1,500 and 2,200 psia (pounds per square inch absolute ) in order to be transported via pipe line and then injected into an underground storage site” and noted that compressing CO 2 is energy intensive and expensive. Commenter 10036 also noted that the CO 2 transported for use in EOR operations has historically been from the steady state productio n of natural geologic deposits and not from CO 2 captured at power plants
. Compression and transportation operations, similar to storage operations, could be affected b y the unsteady flow of CO 2 sourced b y power plants. **Response 6.3 -**  **69:** The EPA does not agree with the comm enters’ assertions. CO 2 has been safely compressed and transported via dedicated pipelines in the U.S. for nearl y 40 years. P ipelines can indeed convey

captured CO 2 to sequestration sites with certainty and provide full protection of human health and the environment. Existing and new CO 2 pipelines are comprehensivel y regulated b y the Department of Transportation’s Pipeline Hazardous Material Safety Administration. Th e regulations govern pipeline design, construction, operation and maintenance, and emergency response planning. See generall y 49 CFR 195.2. Additional regulations address pipeline integrity management by

requiring heightened scrutiny to assure the quality of pipeline integrity in areas with a higher potential for adverse consequences. See 49 CFR 195.450 and 195.452. On
- site pipelines are not subject to the Department of Transportation standards, but rather adhere to the Pressure Piping standards of the American Society of Mechanical Engineers (ASME B31) which the EPA has found would ensure that piping and associated equipment meet certain quality and safety

criteria sufficient to prevent releases of CO 2 such that certain additional requirements were not nece ssary . See 79 FR 358
- 59 (Jan. 3, 2014). These existing controls over CO 2 pipelines assure protective management, guard against releases, and assure that captured CO 2 will be securely conveyed to a sequestration site
. CO 2 used for EOR may come from anthrop ogenic or natural sources. The source of the CO 2 does not impact the effectiveness of the EOR operation. CO 2 capture, treatment and processing steps (including compression, as commenter 9666 states) provide a concentrated stream of CO 2 in order to meet the needs of the intended end use. CO 2 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) appl y regardless of the sourc e of the CO 2 and take into account CO 2 composition, impurities, and phase behavior. Additionally , EOR operators and transport companies have specifications to ensure related to the composition of CO 2 . These requirements and specifications ensure EOR operat ors receive a known and consistent CO 2 stream. Lastl y, the EPA acknowledges that generation of captured CO 2 from natural gas treatment plants and industrial sources may be more steady- state than the generation of captured CO 2 from EGUs. However, the EPA does not agree that the technical and economic feasibility of operation of CO 2 pipelines depends upon steady- state generation of CO 2 from capture sources
. There are6
- 41

technicall y and economically feasible technologies (e.g., looping, pressure maintenance, an d diversion to/from other pipelines) that EGUs and CO 2 pipeline can apply to manage pipeline pressure and flow fluctuations associated with EGU load fluctuations and EGU planned or unplanned outages to avoid detrimental effects on CO 2 pipeline operations
. **Comment 6.3 -**  **70:** Commenter 9472 and commenter 9033 stated that the EPA has ignored the technical challenges of CO 2 storage. Commenter 9472 notes that f ull scale application of CCS on a power plant requires that CO 2 transportation and long
- term subsurface storage is avai lable at all times, and that CO 2 removed from an emissions stream b y CO 2 capture equipment are in a gaseous form and cannot be stored onsite; the captured CO 2 must be transported for long
- term storage . Commenter 9033 inquired about the risk associated with shutting down electricity generation when the capture or subsequent processes fail. Commenter 9033 also questioned what would happen to EGU CO 2 compression sy stems when load on the CO 2 capture plant is reduced, and would that situation subsequently impact CO 2 transportation or injection given the instantaneous load drop and increase
. **Response 6.3 -**  **70:** The EPA does not anticipate that the CO 2 transportation network will need to be available “at all time s” in order for EGUs to achieve compliance with the proposed rule
. Moreover, a new fossil fuel
- fired steam generating EGU

– if constructed

– would, mostly likel y, be built to serve base load power demand and would not be expected to routinely start - up or s hutdown or ramp its capacity factor in order to follow load demand. Thus , planned start
- up and shutdown events would only be expected to occur a few times during the course of a 12
- operating
- month compliance period
. Post
- combustion partial and full CCS hav e also proven highl y reliable in actual operation (e.g. at Boundary Dam, and AEP Mountaineer). **Comment 6.3 -**  **71:** Commenter 10786 noted that the Class VIregulatory approach is inconsistent with the legal and regulatory framework governing CO 2 - EOR operations. For example, E OR industry ’s standards and requirements for CO 2 pressure, allowed co
- constituents and the like are by and large focused on what is needed and acceptable for the pipeline infrastructure, surface handling facilities, and target oil & gas reservoir(s). The E OR industry is not in the generic CO 2 offtake business. The EOR industry

instead acquires CO 2 that is suitable for meeting both its pipeline and its mineral extractive needs. Commenter 10786 also stated that EOR operators and CO 2 pipeline companies are unl ikel y to allow CO 2 intended for use in EOR to be commingled with CO 2 from other sources. **Response 6.3 -**  **71:** CO 2 used for EOR may come from anthropogenic or natural sources. The source of the CO 2 does not impact the effectiveness of the EOR operation. CO 2 capture, treatment and processing steps provide a concentrated stream of CO 2 in order to meet the needs of the intended end use. CO 2 pipeline specifications of the U.S. Department of Transportation Pipeline Hazardous Materials Safety Administration found at 49 CFR part 195 (Transportation of Hazardous L iquids by

Pipeline) appl y regardless of the source of the CO 2 and take into account CO 2 composition, impurities, and phase behavior. There is thus no a priori restriction on commingling CO 2 from different so urces . Additionally , EOR operators and transport companies have specifications to ensure related to the composition of CO 2 . These requirements and specifications ensure EOR operators receive a known and consistent CO 2 stream.6
- 42

**Comment 6.3 -**  **72:** Commenter 7977 noted that the proposed regulation relies on the expected ty pical pipeline CO 2 distance to be 50 miles to possible geologic sequestration sites, but that this distance underestimates the actual distances that may be necessary

for the transmission of CO 2 . Commenter 9648 n oted that even if 95 percent of the sources are located within 50 miles, it is unclear if the pipelines that would be needed in their state to transport CO 2 could receive the necessary permits to allow construction. Commenter 9426 cited a study of CO 2 pipe line options that concluded that sequestration is not economically or technicall y feasible in North Carolina, and asserted that based on these studies it would not even be possible to develop a new coal
- fired EGU if CCS were required. Commenter 9774 noted that coal
- fired power plants in Wisconsin are between 200 and 500 miles from the nearest sequestration formation and that there are no CO 2 pipelines in Wisconsin, and that the cost of building such a pipeline would exceed the cost of installing CO 2 capture technology

on the coal
- fired plants
. Comment 10106 however, noted that although there are no identified sequestration sites in Wisconsin, as there are existing locations where sequestration geology has been demonstrated, and since the transport of CO 2 through pipelines is a well
established practice throughout the nation, the presence of sequestration geology within state lines does not dictate the availability or feasibility

of CCS. Commenter 9666 cited the studies conducted of CO 2 pipeline feasibility for North Carolina and Wisconsin that concluded that CCS would only be viable if multi
- state CO 2 pipelines were constructed, and that suggested that the 50
- mile CO 2 pipeline transport distance presumed in cost studies is inadequate in many cases. **Response 6.3 -**  **72:** The EPA does not agree that technical or permitting feasibility would limit the development of CO 2 pipelines (see also previous responses). In estimating impacts of the rul e, the EPA relied on NETL studies referenced in Section V.I .2 of the preamble and based transport costs on a generic 100 km (62 mi) pipeline and a generic 80 kilometer pipeline
. At least one study estimated that of the 500 largest point sources of CO 2 in the United States, 95 percent are within 50 miles of a potential storage reservoir
. For new sources, pipeline distance and costs can be factored into siting and, as discussed in section V. M , there is widespread availability of geologic formations for geolog ic sequestration (GS). Moreover, data from the Pipeline and Hazardous Materials Safety Administration show that in 2013 there were 5,195 miles of CO 2 pipelines operating in the United States. This represents a seven percent increase in CO 2 pipeline miles o ver the previous year and a 38 percent increase in CO 2 pipeline miles since 2004. Therefore, the EPA’s assumptions, while they may appl y to all cases, are representative for cost estimation purposes. In reality , the EPA understands that pipelines of longer or shorter distances may be constructed for compliance with the NSPS
. With respect to pipeline construction in the southeast (such as North Carolina), offshore saline geologic capacity exists within 100 kilometers of the state , and state demand could also be served b y coal
- fired electricity generation capacity built in nearb y areas and this electricity then delivered through transmission lines
. See Figure 1 of TSD on geographic availability
. In any case, there are alternative compliance pathway s available for achieving the final standard of performance which do not involve sequestration
. **Comment 6.3 -**  **73:** Commenter 10618 provided cost estimates of CO 2 pipeline development: Duke Energy

estimated a CO 2 pipeline along existing right of way from North Carolina to sites6
- 43

in the Gulf States and Appalachia would approach $5 billion, and the International Energy Agency estimated nearl y $300 billion to construct necessary pipelines to transport the CO 2 from capture to end use facilities for a 50% reduction
. Commenter 9666 cited a study that as of 2010 industry had spent $2.2 billion for construction of over 2,200 miles of CO 2 pipelines within the Permian Basin alone
. Commenter 9596 noted that the costs for CO 2 pipeline construction predicted b y a study conduc ted for the Carolinas vary from $3.8 billion to $4.3 billion. Commenter 8925 noted that CO 2 pipeline cost estimates published in the open literature for the U.S. range from $50,000 to $110,000 per inch
- mile of pipeline, including labor, materials and right
- of
- way costs, which vary

by location. Commenter 9195 noted that at a cost factor of $100,000 per inch
- mile, a 24
- inch pipeline would cost roughl y $2.4 million per mile, and a two thousand mile pipeline of modest size would cost roughl y $5 billion to construct. Commenter 7977 noted that the EPA is required to comprehensivel y evaluate the impact of all associated transportation costs via CO 2 pipelines, including availability and acquisitions of right
of
- way for new pipelines, capital and operating costs, and actual length of transmission pipelines. Commenter 10043 noted that it is unclear whether the EPA's estimate of CO 2 pipeline construction costs includes the costs of right
- of
- way , pipeline construction, permitting delay s, and length of transportation, amo ng other costs. Commenter 9600 also stated that it does not appear that the EPA has taken into account the costs of CO 2 pipelines, Commenter 9734 stated that the cost that would be required to construct CO 2 pipelines to transport captured CO 2 to oil fields would be insurmountable, and that the EPA has recognized this
. Commenters 9657 and 9734 also noted that there are significant costs for building the CO 2 pipeline framework and believe that the EPA has not incorporated these burdens into its analy sis. Commenter 8925 noted that published sources indicate that CO 2 pipeline construction costs range from $50,000 to $110,000 per inch
- mile of pipeline, including labor, materials and right
of
- way acquisition costs. Commenter 8925 noted that once permits and ri ghts
- of
- way were secured, construction of a 12.2 mile intrastate CO 2 pipeline to support a CO 2 capture and EOR project was completed within 3 months
. Commenter 8925 noted that the applicant needed to consult with eight separate Federal and State agencies a s part of the pipeline permitting process. Commenter 10039 asserted that the lack of a regulatory framework and the NETLcost and performance assumptions that the EPA has relied on renders the proposal arbitrary and unreasonable, with no nexus with any EGU siting requirements. Commenter 10039 notes that all CCS analy sis cases assume generation will be located within 62 miles of a local available sequestration site for purposes of estimating CO 2 transportation costs. The commenter asserted that sequestratio n sites are not possible in large parts of the country and therefore transportation cost assumptions are arbitrarily low. The cost assumption has no basis in any real siting requirement or electric generation needs analy sis and is therefore arbitrary and i nappropriate for consideration of the costs of the technology when developing the NSPS
. Commenter 10039 notes that under no EPA, DOE, or EIA models of the electric generating sector, does the EPA show that 200 individual generating units will be installed within 62 miles of any area of the country which is assumed to be suitable for CO 2 storage. **Response 6.3 -**  **73:** The EPA estimated costs for CO 2 based on the NETLstudies referenced in Section V.I. of the preamble and based transport costs on a generic 100 km (62 mi) pipeline and a generic 80 kilometer pipeline. At least one study estimated that of the 500 largest point sources6
- 44

of CO 2 in the United States, 95 percent are within 50 miles of a potential storage reservoir
. For new sources, pipeline distance and costs can be factored into siting and, as discussed in section V.K, there is widespread availability of geologic formations for geologic sequestration (GS). Moreover, data from the Pipeline the and Hazardous Materials Safety Administration show that in 2013 there were 5,195 miles of CO 2 pipelines operating in the United States. This represents a seven percent increase in CO 2 pipeline miles over the previous year and a 38 percent increase in CO 2 pipeline miles since 2004. Therefore, the EPA’s assumptions are representative for cost estimation purposes. See responses to previous comments on the regulatory framework for CO 2 pipelines and Section V. I.5 and N .4 of the preamble
. See also Figure 1 of TSD on geographic availability
. In any case, there are alternative compliance pathw ays available for achieving the final standard of performance which do not involve sequestration
. The EPA recognizes that siting and construction of CO 2 pipelines will generally involve securing permits from multiple jurisdictions. Costs of acquisition of both land and subsurface property rights (‘pore acquisition rights’) are included in the EPA’s cost estimates
. **Comment 6.3 -**  **74:** Commenters 9600 and 10097 noted that the EPA relied exclusively on DOE studies to predict the levelized cost of electricity (LCOE) for EGUs, and noted that the L COE data do not factor in CO 2 transport and sequestration costs where EOR is not available. Commenters 9201, 9600, and 10097 noted that the proposal completel y i gnores any costs associated with the transportation and storage components of CCS, and concludes that based on these facts within the proposal, the EPA cannot reasonably conclude that partial carbon capture is of reasonable cost based on this information derived from these DOE studies
. Commenter 7977 also noted that the DOE/NETL costs the EPA relied for the rule on exclude transportation costs of CO 2 , which could significantl y increase the cost estimate for new sources implementing CCS technology . Commenter 7977 also noted that Section 111 (a)(1) of the CAA requires that the EPA a ccount for the "costs of achieving such reductions." Since EPA is proposing that CCS is the BSER for coal
- fired EGUs, the EPA must account for the cost of transporting CO 2 . Commenter 9396 stated that the proposed rule’s analy sis of partial sequestration as BSER effectivel y ends with CO 2 capture at the plants, failing to provide analysis of the other component parts of CCS

– pipeline CO 2 transportation, CO 2 monitoring, and permanent CO 2 sequestration. In determining the BSER, the EPA has not examined the entire process and fails to include in the standard full evaluation of all the critical components to assure the emissions reductions are accomplished permanently
. **Response 6.3 -**  **74:** The EPA in fact included cost estimates for CO 2 transport when EOR opportunities are not available

– consistent with its overall conservative cost methodology of assuming no revenues from sale of captured CO 2 . The EPA also carefull y reviewed the assumptions on which the transport cost estimates are bas ed and continues to find them reasonable. For transport, costs reflect pipeline capital costs, related capital expenditures, and O&M costs. Sequestration cost estimates reflect the cost of site screening and evaluation, the cost of injection wells, the cos t of injection equipment, operation and maintenance costs, pore volume acquisition expense, and long term liability protection. These sequestration costs reflect the regulatory

requirements of the Underground Injection Control Class VI program and GHGRP subpart RR for geologic sequestration of CO 2 in deep saline formations. See the preamble for additional information in Section V.I.5
.6
- 45

**Comment 6.3 -**  **75:** Commenter 9648 stated that n ot all the energy and emissions related effects impacted for the CCS sy stems by the proposed ru le have been identified and incorporated in the rulemaking
. For example, electric power consumption for operation of CCS CO 2 separation and injection technologies are estimated to be 30 percent of the plant’s total electricity generation rate, and this estimate does not include additional energy requirements for transport and compression for EGU sites that do not have nearby geologic reserves for storage, such as those in North Carolina. **Response 6.3 -**  **75:** The cost studies used b y the EPA in the cost anal ysis for the rulemaki ng include both construction cost and operating and maintenance (O&M) costs for CO 2 transport . Pipeline O&M costs include d in the studies include the cost of electricity and other consumables that would be needed to operate the CO 2 pipeline. Ty pically the electricity

needed to operate a CO 2 pipeline would not come directl y from the EGU from which the captured CO 2 is being transported, but rather would be provided directly to the pipeline by the pipeline operator, which could be a separate entity from the EGU operator
. Therefore the electric power consumption for operation of the pipeline would not generall y directly affect the EGU’s net electricity generation rate. **Comment 6.3 -**  **76:** Commenter 7977 noted that the economics of EOR change drastically with distance and CO 2 transp ortation needs. The cost of building infrastructure for CO 2 transport or transporting CO 2 hundreds of miles far exceeds that of a facility located on an existing EOR site. The EPA should provide cost calculations for new facilities that do not have EOR within a certain geographic distance, as CCS won't be economically feasible for facilities without easy access to EOR. Based on the EPA's own anal ys is, there are 37 states where CO 2 - EOR is not utilized and eleven states that have virtuall y no CO 2 storage capa city or CO 2 - EOR operations
. Commenters 7977 concludes that the cost of building infrastructure for CO 2 transport or transporting CO 2 hundreds of miles far exceeds that of a facility located on an existing EOR site
. **Response 6.3 -**  **76:** The EPA does not agree that the absence of EOR sites in the vicinity of new EGUs would render the EGU sites infeasible. The EPA recognizes that the cost of CCS may vary depending upon the proposed location of the EGU based on geographic and other factors inclu ding locations of potential sequestration sites; however, the EPA does not agree that CCS is economicall y infeasible for new EGUs located in areas in which there are no EOR operations
. Potential sequestration sites including both EOR sites and deep saline formation sites as well as other non
- EOR sites are located throughout the U.S. and construction of CO 2 pipelines is adequatel y demonstrated
. **Comment 6.3 -**  **77:** Commenter 9195 noted that the EPA's proposal will have significant disparate geographic impacts, and that geologi c features appropriate for EOR or geologic sequestration are not evenly distributed throughout the country
. Commenter 9195 noted that the DC Circuit Court has said that sec. 111 standards “ must not give a competitive advantage to one State over another in attracting industry” and questioned whether construction of CO 2 pipelines can solve this issue
. Commenter 9780 in testimony stated that it is not clear how EOR could defray the costs of an overall CCS project if long pipelines or transmission lines would h ave to be built (and paid for), and stated that the EPA has made no effort to quantify whether the price of captured CO 2 would overcome the increased costs associated with pipeline or transmission construction. Commenter 9780 also noted that the EPA has failed to account for the lengthy ,6
- 46

costly , and uncertain permitting processes for major infrastructure like pipelines and transmission lines, and has not addressed the fact that the owners of new EGUs installing CCS are not likel y to be the entities responsible for permitting, building and paying for this critical infrastructure. Commenter 9780 concluded that in an effort to dismiss the geographic constraints of EOR, the EPA has made unsubstantiated and unverifiable claims about the ease and cost of building pipelines and transmission lines. **Response 6.3 -**  **77:** The EPA does not agree that the rule provides a “competitive advantage” to one state over another in attracting industry
. There are various compliance paths which may be used, some of which do not involve sequestration, so that compliance is not limited by geographic location. **Geologic Sequestration Comment 6.3**  **- 78:**  Commenter 10098 stated that the EPA's claim that geologic sequestration is currentl y available is contradicted b y the extensive ongoing research and development seeking to make geologic sequestration commerciall y available. Commenter 10098 further stated that although the proposed rule provides a theoretical overview of how geologic sequestration could work a discussion of commercial geologic storage facilities is conspicuously a bsent
. Commenter 10098 noted that it is arbitrary and capricious to declare that an experimental technology is technicall y feasible and available without any explanation as to wh y the technology is considered ready for commercial use or acknowledgment of the evidence of operational setbacks. Commenter 9472 stated that the EPA has not adequately examined the feasibility

and challenges of CO 2 storage in the proposed NSPS. Commenter 9472 further noted that the EPA failed to consider several aspects of CO 2 storage that limit the feasibility of utilizing CCS at a coal
- fueled power plant. **Response 6.3 -**  **78:** 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 VIprogram. Itwould not have done so, and under the regulations could not have done so, without demonstrations that CO 2 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 CO 2 can be safel y injected and securely sequestered for long periods of time at volumes and rates consistent with those expected under this rule. **Comment 6.3 -**  **79:** Commenter 10095 stated that the EPA's development of its proposal does not account for the costs and burdens associated with the level of effort necessary to confirm the feasibility of sequestration sites and that the EPA instead relies on theory and generalizations. Commenter 10392 stated that the cos t - effectiveness of partial CCS

– particularly if involving permanent geologic sequestration

– is entirel y unproven and not commercially available. **Response 6.3 -**  **79:** The EPA’ s cost estimates account for the costs of GS , among them site screening and evaluation costs, costs for injection wells and equipment, O&M costs, and6
- 47

monitoring costs. The EPA’s cost estimates for sequestration thus cover all aspects commenters claimed the EPA disregarded. The EPA believes that the use of costs and scenarios presented in the studies referenced are representative for purposes of the cost analy sis. The NETL cost estimates upon which the EPA’s costs are based draw directl y f rom the UIC Class VIeconomic impact anal ys is
. That analy sis is based on estimated characteristics for a representative group of projects over a 50
- ye ar period of analy sis, as well as industry averages for several cost components and sub
- components. See al so RIA chapter 4. **Comment 6.3 -**  **80:** Commenters 1959, 2471, 8349, 9194, 9426, 9780, 10086, and 10239 stated that there is no power plant with full
- scale geologic sequestration functioning anywhere in the US today . Commenters 1959, 8349, 9194, 9780, and 10239 noted that there is no evidence of successful commercial implementation
. Commenters 2471, 8349, 9780 and 10239 noted that the EPA made reference to a number of plants, but none of them are actually operating, but are only planned. Commenter 10239 additionally noted that the EPA provides no analy sis regarding these facilities and fails to acknowledge that at least one has been suspended due to concerns over vertical leakage. Commenter 9780 noted that there is insufficient monitoring experience with post - injection storage o f CO 2 to support findings of adequate demonstration. Commenter 9780 specifically noted that 3 of the 4 large
- scale storage projects listed by the EPA as evidence of the technical feasibility of storage are capturing their CO 2 from natural gas extraction o r processing facilities while the fourth receives captured CO 2 from a gasification plant for use in EOR, none receive captured CO 2 from an EGU. Commenters 9426 and 9683 stated that there is not relevant experience to support a finding that permanent geolog ical sequestration of CO 2 on the scale required for use with commercial power generation has been adequately demonstrated, or that any level of CO 2 emission from sequestration repositories is achievable under the range of relevant conditions for the industry as a whole. Commenters 9725 and 10050 stated that the EPA cannot show that the proposed coal unit standard can be met on a continuous basis given the lack of any demonstration of continuous sequestration of the large amounts of CO 2 from a commercial scale base load generation plant. **Response 6.3 -**  **80:** The EPA notes that SaskPower’s Boundary Dam CCS Project in Estevan, Saskatchewan, Canada, less than 10 miles from the US border, is the world’s first commercial
scale full y integrated post
- combustion CCS project at a coal
- fired power plant. The project fully integrates the rebuilt 110 MW coal
- fired Unit #3 with a CO 2 capture system The CO 2 from the capture s ys tem is more than 99.999 percent pure with only trace levels of N 2 in the product stream. The captured CO 2 is transporte d by pipeline to nearby

oil fields in southern Saskatchewan where it is used for enhanced oil recovery (EOR) operations
. In the United States, the EPA has issued Class VI UI C permits for six wells for two projects. EPA considered , among other information, information on the regional geology and local geologic features at each site as part of its permitting process to determine that the wells were appropriatel y sited and met the Class VI requirements. Additionally , there are several large scale CO 2 sequestration projects including the Illinois Basin Decatur Project and the Cranfield (Tuscaloosa) Project that demonstrate that storage of large amounts of CO 2 can be achieved. In6
- 48

April 2015, DOE announced that CCS projects supported b y the department have safely and permanentl y stored 10 million metric tons of CO 2 , which is the same order of magnitude expected for an EGU. E xisting commercial CCS facilities in other countries demonstrate the commercial storage of CO 2 , and the ability

to inject large qu antities over long period of time. The CO 2 streams from these facilities have phys ical and chemical characteristics similar to pipeline grade CO 2 that would be expected from an EGU so the source of the CO 2 is not a factor in assessing the feasibility of long term secure storage. Commenter 10239 refers to the In Salah project where CO 2 injection has been suspended due to concerns over vertical leakage. Monitoring data and anal ys es indicated that CO 2 had migrated from the injection zone into the lower caprock, but had not reached the main caprock seal. No CO 2 was released. While the In Salah project is no longer injecting CO 2 , the events demonstrate that the monitoring program served its intended purpose in det ecting adverse conditions prior to the release of any CO 2 . (Indeed, the E lectric Power Research Institute (EPRI), a nonprofit research organization funded b y the electric utility industry , likewise stated in its public comments that In Salah served as an e xample of the efficacy of sub
- surface monitoring in preventing environmental release of sequestered CO 2 .) Post injection site care, including monitoring of the stored CO 2 , is required under UIC Class VI permits, and all Class VI permits issued to date have included required post injection site care plans
. The risk of release is highest during the injection phase and decreases during the post injection period and monitoring requirements reflect the relative risk during each phase. 5 The EPA has reviewed and considered the results from several long
- term monitoring programs, including more than 10 years of monitoring from the seque stration site at the Wey burn oil field, and the Sleipner project, which began injecting CO 2 into the deep subsurface in 1996
. The EPA also recognizes that several EOR projects have been monitoring reservoir conditions for more than 30 years. The EPA believes that the proposed standard can be met on a continuous basis because several of the sequestration projects described i n the proposal including Sleipner in the North Sea, Snohvit in the Barents Sea and Wey burn in Canada have demonstrated continuous operation for many ye ars. **Comment 6.3 -**  **81:** Commenter 9426 noted that geologic storage of CO 2 is not technologicall y viable in some regions of the United S tates since the necessary geologic conditions to support CO 2 storage simply do not exist in those regions
. Commenter 10778 stated that the theoretical feasibility of sequestration geology in the Coastal Plains and Gulf Coast does not mean seq uestration is actually

available and capable of being implemented in the Region. The commenter stated that the Coastal Plains region of the United States, especiall y the Gulf Coast, contains the largest storage sequestration resource of any region; however , the commenter clarified as a threshold matter, the potential feasibility of geologic sequestration does not equate to a finding that this technology is either “available” or that it has been “adequately demonstrated” within the meaning of CAA Section 111 . Further, the commenter stated that while the Coastal Plains region could have a greater percentage of the

5 Report of the Interagency Task Force on Carbon Capture and Storage (August 2010), page 47.6
- 49

basic geologic s ys tems that might support sequestration, this does not equate with sequestration capability
. Commenter 9426 stated that because the geology necessary

for carbon sequestration is highl y site
- specific and suitable sites are concentrated in a few areas of the country , it may be impossible for the EPA to determine that an NSPS based on CCS is achievable for sources across the nation. The commenter stated that before the EPA may impose a standard across the entire electric generating industry it must show that the standard is achievable across the entire industry , which includes a wide variety of geologic characteristics. According to the c ommenter, geologic limitations require long
- distance transportation of removed CO 2 prior to sequestration, then the EPA must factor in the transportation and associated costs as part of its BSER demonstration. Commenter 9596 stated storage sites for CO 2 are simply not available in many

areas of the country . According to the commenter, CCS is only an option in certain areas of the United States that has the correct geological formations to sequester CO 2 (or have access to long
- distance CO 2 pipelines that can convey CO 2 to a proper sequestration site). The commenter concluded that EPA cannot require the use of a compliance option that is only available in some regions of the United States. Commenter 10033 stated it is likely that many areas are simpl y unsu itable for CCS based on geology or other factors. Commenter 10039 stated that the EPA ’ s basis for the technical feasibility of CO 2 sequestration is based on the potential technologies for monitoring and verifying sequestration and that the data presented i s insufficient to show that CO 2 sequestration is a feasible, permanent storage solution for CO 2 from EGUs. Commenter 10039 notes that the USGS analy sis cited by the EPA as to the availability

of CO 2 storage resources shows that large sections of the US are unsuitable for sequestration for various reasons. Commenter 10098 stated that USGS does not know how much of these regional areas may actuall y be used for CO 2 s torage. Commenter 9326 stated that much is yet to be proven regarding the permanent storage of CO 2 in deep geologic formations
. Commenter 9326 further stated that not every power plant is located on or near favorable geology for CO 2 storage and that hundreds of miles of pipelines would have to be built to service these facilities, which continues to add on to this high cost of CO 2 capture. Commenter 10095 stated that injection and storage of commercial volumes of CO 2 produced b y an EGU is not available in all regions, has not progressed beyond the research, development and earl y demonstration phase, and requires additional study and development before it can be considered adequately

demonstrated. Commenter 9197 stated their doubts that CCS will be feasible to implement in many parts of the country because storage sites for CO 2 are simply not available in many

areas of the country
. Commenter 9197 further stated that the EPA should not require new facilities to use a compliance option that is only available in some regions of the United States.6
- 50

Commenters 8949, 9201, 9381, 9407, 9666, 10023, 10052, 10100 and 10660 asserted that CCS is not available in all areas of the U.S. due to geologic restrictions, lack of transportation infrastructure, or lack of EOR
. Commenter 9407 further stated that NSPS is nationally applicable and must be implementable over broad geographic regions. Commenters 9201, 9381, 9666, 10052, 10100 and 10660 stated that the requirement would result in advantages for states such as those in the Coastal Plains and Southwest that have storage capacity or EOR, and disadvantages for states th at lack sufficient resources for sequestration, such as the Pacific Northwest and Atlantic Coast. Commenters 9201, 9381, 10048, and 10052 stated that areas with little or no storage capacity would have to construct costly , lengthy and expensive pipeline s ys tems to meet the regulatory requirements, if property rights and easements were obtainable. Furthermore, Commenters 9201 and 9666 reiterated that the National Carbon Storage Atlas assessment of potential geological storage opportunities was an initial as sessment and more precise assessments that identify all relevant properties (e.g., permeability , penetrations, understanding of underground fluid displacement, fractures and potential for fractures) will take additional time to complete. Additionally , Comm enter 9666 stated that the EPA did not consider economic viability or lack of accessibility

to storage resources due to land
- management or regulatory restrictions, such as areas containing freshwater in the West. Commenter 9407 stated that pipelines, deep well sequestration, EOR and other infrastructure must be available for the proposed BSER. Commenter 9780 stated that there is no evidence in the proposal that the EPA considered regional differences in EOR opportunities and sequestration site availability in assessing the feasibility of deploying partial CCS for coal
- based units. Commenter 9426 further stated that in regions of the country where storage is not available, the EPA would be required to establish alternative standards. **Response 6.3 -**  **81:** See Section V. M . of the preamble and the technical support document on geographic availability
. Potential GS formations are widel y available in the United States. The EPA recognizes that geologic conditions to support CO 2 storage may not exist in all regions of the country . Where such capacity is unavailable, electricity demand in those areas can be served by coal
- fired power plants built in neighboring areas with geologic availability with generated electricity being supplied via transmission line, see Figure 1 of TSD on geograph ic availability , or the CO 2 can be transported to available GS sites via pipeline. For other of those areas, coal
fired power plants are either not being built due to state law prohibition s against building such units, or other available compliance altern atives exist allowing a new coal
- fired power plant meeting the promulgated NSPS to be sited. There are alternative means of complying with the final standards of performance which do not necessitate use of partial CCS, so any siting difficulties based on l ack of a CO 2 repository would be obviated. **Comment 6.3 -**  **82:** Commenter 9683 stated that industry
- wide carbon storage has even less evidence of feasibility

than does carbon capture, but is the only feasible large
- scale fate for the amount of CO 2 to be captured from a full
- s cale electric generating unit. Commenter 9683 further6
- 51

stated that depleted oil and gas formations provide the only evidence that large amounts of CO 2 can be stored safely

over the long term, but noted also that these formations do not exist in sufficient g eographic dispersion throughout the US. **Response 6.3 -**  **82:** The commenter is correct that depleted oil and gas formations provide potential capacity for CO 2 captured from a full
- scale electric generating unit and that the CO 2 can be stored safely

over the long term. However, the EPA does not agree that oil and gas formations provide the only evidence of large scale storage. The three international sites (Sleipner, Snohvit and In Salah) and DOE pilot and demonstration projects provide evidence of the feasibility

of saline stora ge sites also
. The issue of geographic availability is addressed elsewhere in this section and in Preamble section V.M. **Comment 6.3 -**  **83:** Commenter 10106 stated that the presence of sequestration geology within state lines does not dictate the availability or feasibility of CCS
. Commenter 10106 noted that different states are positioned differently in terms of the ease of compliance for many reasons, including cost, and that this is true under most Clean Air Act regulations. Commenter 10095 stated that some states may not have the capability

of implementing CCS without exporting CO 2 to other states or offshore
. Commenter 10095 noted that the EPA proposal does not broach how a state would address these barriers and externalitie s. Commenters 9423 and 10500 stated that carbon sequestration may not be available in various regions of the United States and that the CCS requirement will result in a competitive advantage for states that have EOR or sequestration opportunities and disadvantages for those that do not. Commenter 9774 stated that fourteen states do not have any geologic formations suitable for carbon sequestration. Commenter 10031 stated that at least 30% of the states have little to no known storage capacity

in the form of saline reservoirs. C ommenter 9770 stated Minnesota does not have the geology to sequester CO 2 either for saline aquifer storage, which has not been commercially demonstrated, or for enhanced oil recovery (EOR). Commenter 9194 specifically addressed their concerns with geologic sequestration viability in Florida. Commenter 2470 stated Florida has insufficient ability to utilize enhanced oil recovery for the captured carbon from the CCS process due to the minimal oil and gas production currentl y within the State. According to the commenter, moving the captured CO 2 to other areas within the Southeast with greater oil and gas resources will require the construction of a pipeline and additional associated costs. **Response 6.3 -**  **83:** The EPA largel y agrees with the commenter that each state has unique geologic circumstances
. Transporting CO 2 to areas of geologic availability is an option for complying with the NSPS and there are many examples of transportation of CO 2 . The EPA noted in the January 2014 Proposed Rule that certain sources may be precluded from locating in certain areas for economic or technical reasons which is not inconsistent with6
- 52

congressional intent for CAA section 111
. The presence of suitable geology for sequestration is an initial factor to consider in determining the feasibility of a specific site for a new EGU. Site specific studies must then be conducted to ensure the location is capable of safe, long
- term storage o f CO 2 and not all locations will meet the siting criteria
. The EPA notes that DOE and USGS resource assessments have identified 39 states that have saline storage opportunities. Many of the states that do not have storage access are unlikel y to see new co al fired power plants because there is no need for the additional power, coal
- fired power has never been utilized in the area (e.g. Hawaii), or there are other preferred power options that can meet the performance standard
. The EPA believes that the rule o ffers a wide range of options that allow states considerable flexibility to compl y with the rule without creating an economic disadvantage. States with little or no saline storage capacity may choose to transport CO 2 to locations with available storage, or site facilities near storage areas and using transmission lines to provide power to other areas. In addition, there are various compliance alternatives to achieve the promulgated standard of performance, not all of which involve sequestration. With respe ct to the commenter’s assertions about the lack of availability of EOR in Florida, the BSER determination and regulatory impact anal ys is for this rule relies on GS in deep saline formations . The EPA notes that Figure 1 of the technical support document on geographic availability

shows the areas of Florida that are within 100 kilometers of a potential GS formation; electricity demand may be served by

coal
- fired electricity generation built in areas that are proximate with geologic sequestration, and this ele ctricity can be delivered through transmission lines. See preamble section V. M
. 7
. **Comment 6.3 -**  **84:** Commenter 9426 stated that the EPA must show that storage of large volumes of CO 2 has been adequately demonstrated on a consistent basis and must also identify locations where suitable geological conditions would allow for such storage
. Commenter 9426 specifically stated that while there may be potential CO 2 storage areas offshore of the Carolinas, the ability to inject CO 2 in these areas has not been demonstrated. Commenter 1 0095 noted that geologic data may simply show large areas are not suitable for underground injection and storage of CO 2 and that consistent geology is imperative for ensuring the adequacy

of a formation for CO 2 injection and storage. **Response 6.3 -**  **84:** The EPA has identified and described several large storage projects that demonstrate the ability

to safel y store large volumes of CO 2 . Analy ses by DOE and USGS identify many areas where conditions are favorable for storage, but recognize that site specific stu dies will be required to ensure the location is capable of safe, long
- term storage of CO 2 . DOE studies have identified several offshore areas, including the Carolinas, with t he potential for saline storage
. In addi tion, should none of these storage opportunities be readily available, there are alternative compliance pathway s to meet the promulgated standard. **Comment 6.3 -**  **85:** Commenter 10030 cited the WCEV project in Michigan, and stated that as the design of the project was only in relation to a slip
- stream, it cannot form a basis for concluding that the facility

as a whole or the available geology feasibl y could accommodate a full
- scale CCS6
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sy stem capable of sequestering the CO 2 necessary for the WCEV to meet the proposal ’ s emission limitations. Commenter 9426 noted that ne ither the Kemper County nor the SaskPower Boundary Dam projects shed light on the challenges associated with storing CO 2 in saline geological formations, and these first generation of CCS systems will likely reveal performance and reliability issues that m ay require costly

additional measures to address. **Response 6.3 -**  **85:** The EPA has not used the Wolverine Clean Energy Venture (WCEV) project in Michigan as a basis for concluding that the facility, as a whole could accommodate a full
- scale CCS system. Today ’s rule specificall y notes the proposed Wolverine EGU project in Rogers City, Michigan has been cancelled and is therefore not addressed in the final rule. See preamble section III.J. With regards to the issue of slip stream, see section V.D.2.a. of the final rule preamble o f the NSPS for the EPA’s response to this comment. We also note that the Boundary Dam project developer has publically extolled the reliability

of the CCS system in operation, and that the sy stem in fact has been on
- line without incident since it commenced operations. Commenter 9426 is correct that neither the Kemper County nor the SaskPower Boundary Dam projects plan to store CO 2 in a deep saline formation as a primary location. However, Boundary Dam is in fact sequestering the excess CO 2 which it is not s elling for EOR in a deep saline formation. The EPA has issued six UI C Class VI permits to two applicants under the Class VIprogram, each permit involving deep saline injection of large volumes of captured, anthropogenic CO 2 . The EPA would not have issued these permits without finding (and demonstrating in the administrative record) that the permittees would meet all requirements of the rigorous Class VI regulation, whose requirements assure that sequestered carbon dioxide will remain confined with out endangering underground sources of drinking water . **Comment 6.3 -**  **86:** Commenter 10239 stated that it is unlawful for the EPA to prohibit coal
- fired EGUs in areas that lack geologic storage options. According to the commenter, appl yi ng a national standard based on CCS wou ld have the effect of creating the exact ty pe of localized competitive advantages that Congress sought to avoid when it enacted the NSPS program, as only regions with geologic storage could construct coal
- fired EGUs. The commenter also stated that using Se ction 110 attainment provisions to prohibit facilities from being constructed in certain areas is irrelevant since GHGs do not produce localized air impacts and there are no national ambient air quality standards for GHGs that could be used to invoke Secti on 110. **Response 6.3 -**  **86:** The final standard of performance for fossil
- fired EGUs does not create these effects
. Most areas of the country have potential GS opportunities
. Some states prohibit new coal
- burning capacity
. Inthe unlikely event that a new source locates in ano ther state (and there is no record evidence of any such possibility), there are alternative compliance pathways available under the final standard which do not involve capture and sequestration and which have associated geographical constraints. The EPA ha s determined that more than 95 percent of the 500 largest CO 2 point sources in the U.S. are within 50 miles of a possible geologic sequestration site so localized competitive advantages would be minimized. In drafting the CAA Section 111, Congress recogniz ed that certain emission sources may be precluded from locating in certain6
- 54

areas for economic or technical reasons and there is no requirement that BSER apply to all locations equally
. **Comment 6.3 -**  **87:** Commenters 10098 and 10239 stated that the EPA lacks record support fo r its assertion that geologic storage capacity is widespread and available throughout the U.S. and Canada, and typically available within 50 miles of existing power plant locations. Commenter 10098 noted that the USGS review cited in the proposed rule is an initial assessment of storage capacity and provides no information on areas that may actuall y be used for CO 2 storage. According to Commenter 10239, it is arbitrary and capricious for the EPA to simply rel y on the potential availability

of suitable formations, further stating that such reviews of potentially suitable formations cannot establish actual availability because each potential geologic sequestration site must undergo appropriate site characterization to ensure that the site can safel y and secure ly

store CO 2 . Commenter 9780 stated that the distance to geology suitable for geologic storage, and the distance to oil production development activities that might purchase CO 2 for EOR, vary widel y from location to location and from region to region and can have a substantial impact on the feasibility of deploying CCS at a particular EGU. Commenters 8974, 10024, 10393, and 10665 stated that most utilities are not located near enhanced oil and gas or geologic formations that may be able to permanently

sequ ester CO 2 . The commenters additionally

note that until those issues are resolved, no utility could realisticall y build a new coal
- fired power plant under the proposed rule. Commenter 8349 noted approval in I llinois for a 30 mile pipeline intended to carry CO 2 from the plant site to the injection site, but stated that this fact only emphasizes the complications of locating the correct geology for sequestration in relation to a plant site. Commenter 9648 noted, that sequestration of CO 2 in large
- scale geologi c storage areas is not an option for North Carolina, particularly in areas where coal
- fired EGUs are located. **Response 6.3 -**  **87:** The EPA recognizes that the USGS review cited in the proposed rule is an initial assessment of storage capacity and additional site specific work would be needed to demonstrate that a specific site meets the requirements for safe and secure storage under the U IC Class VIrules
. Given the large areal extent of potential storage areas, the EPA believes that based on the USGS assessment suitable storage areas can be identified in proximity to new power plants
. The distance to geology

suitable for geologic storage is a factor that will be necessary to consider in siting new coal fired EGUs. The EPA believes that while there may be regional differences in the proximity

to storage, there is widespread availability of storage capacity near likel y new coal fired plants. While additional planning and permitting may be required, building pipelines to transport CO 2 to storage areas may allow for additional flexibility in siting EGUs. The USGS has identified storage capacity in North Carolina, primaril y in offshore areas
. Siting new coal fired EGUs in North Carolina may require transporting CO 2 to storage areas by pipeline to offshore sub
- seabed geologic formations
.6
- 55

**Comment 6.3 -**  **88:** Commenter 10239 disagreed with the EPA's reliance on ca se law for the geologic sequestration requirement for coal
- fired EGUs. With respect to EPA reliance on the "basic demand" theory , under which it claims it can ban new coal
- fired EGUs under Section 111 as long as basic demand for electricity can be met thro ugh other sources, the commenter cited Int ’ l Harvester Co. v. EPA , 478 F.2d 615 (D.C. Cir. 1973), noting that the court affirmed the EPA ’ s decision not to extend the deadline for Title II emissions standards after concluding that petitioners failed to demo nstrate that the necessary control technology was not available. In contrast, the commenter stated, the EPA proposes a rule that requires a technology "geologic storage" that is not, and never will be, available in some parts of the country. Further, the c ommenter noted in Int’ l Harvester , the requirement to apply the "basic demand" theory was mandated b y the statute, id. at 640; no such statutory mandate applies under Section 111. The commenter also stated the EPA's reliance on NRDC v. EPA , 489 F
. 3d 1364 ( D.C. Cir. 2007) is equally unavailing. According to the commenter, NRDC involved a claim under Section 112 that certain control technology , while technicall y available, was too expensive. Id. at 1375
- 76. The commenter stated that in addition to the fact th at the Section 112, maximum achievable control technology

(MACT) is much more stringent that the Section 111 BSER standard, geologic storage faces significant technological, geological, and legal challenges, not merel y economic challenges associated with i mplementing a control technology
. **Response 6.3 -**  **88:** First, the EPA believes that a new steam generating affected source could meet the promulgated standard and be located anywhere in the country
. There is available sequestration capacity in most areas of the country, and there are alternative way s a new EGU could meet the standard, not involving sequestration, should a new source decide to locate in an area where these sequestration oppo rtunities are unavailable
. See Portland Cement Ass’n v. EPA , 665 F. 3d 177, 191 (D.C. C ir. 2011), holding that the EPA could adopt section 111 standards of performance based on the performance of a kiln ty pe that kilns of older design would have great difficulty satisfying, since among other things, there were alternative methods of complian ce available should a new kiln o f this older design be built
. The court also noted that it was highl y unlikely that such a new kiln would ever be constructed and that the EPA could consider this in adopting a standard of performance reflecting a different ty pe of kiln design
. Similarly here, there is significant doubt that a new steam generating unit would be sited in one of the few areas without ready access to sequestration or EOR opportunities (and commenters have supplied no information indicating that such a possibility actually exists)
. Finally , the promulgated standard of performance can be met without capturing CO 2 or sequestering it, using alternative means of control which have no associated geographical constraints. Moreover, as explained at 79 FR 1466
- 67, the legislative history to section 111 makes clear Congress did not intend that every new source would be able to meet a standard
. The EPA is required, in adopting section 111 standards of performance, to consider impacts on energy (CAA section 1 11 (a)(1)), and has done so here, finding with ample record support that the final standards of performance for coal
- burning EGUs will not impair electricity availability or reliability
. See RIA chapter 4 and preamble section V.O.3. This determination tra cks well with the holding of International Harvester that under the technology
- forcing CAA provision there at issue, the EPA could legitimately adopt a standard that would not be feasible for every vehicle ty pe so long as basic demand is satisfied
. Li kewis e, under Plywood MACT ( NRDC v. EPA), the court held that the EPA was not required to create a separate subcategory to accommodate a particular type of plant for which control technology was more expensive, again indicating that6
- 56

technology
- based standards d o not have to be tailored to accommodate the circumstances of each ty pe of source
. The commenter’s statement that MACT requirements are more stringent than those for BSER is not germane, since this part of the opinion involved the EPA’s authority to subcategorize under section 112 (d)(1), a provision which is identical in all material respects to the subcategorization authority for new source standards in section 111 (b)(2)
. See 479 F. 3d at 1376
. **Comment 6.3 -**  **89:** Commenter 9514 stated that though the EPA ’ s proposal intends to ensure captured CO 2 emissions are permanentl y stored over the long
- term, the rule does not contain sufficient enforceable requirements for permanent sequestration. The commenter provided the example that if the geologic storage facility reports high leakage rates, the rule does not require any action on the part of the EGU that was the source of the carbon in question. As a result, the commenter recommended the EPA work with the appropriate state and federal authorities to establish a comprehensi ve regulatory structure governing sequestration of captured CO 2 . Commenters 1959 and 9396 stated that legal and regulatory uncertainties remain regarding widespread deplo ym ent of long term storage for both EOR and non
- EOR operations. Commenter 10039 remarked that the EPA has no regulatory structures or operating data to adequatel y demonstrate that permanent sequestration can be achieved and verified at a commercial scale, under commercial scale timeframes. Commenter 10039 stated that the EPA ignores that s equestration is not proposed or required in this or any

other rule and has no regulations which require permanent sequestration, accounts for CO 2 disposition from any entity, or monitors for or prevents the re
- emission of captured CO 2 and therefore cannot conclude that control of CO 2 is required b y this rule. **Response 6.3 -**  **89:** Commenter 9514 notes that GHGRP subpart RR do es not provide mechanisms to assure containment of sequestered CO 2 . The EPA believes that the monitoring, verification and reporting plan required b y subpart RR provides some measure of assurance when implemented in conjunction with Class VI(or II) requirements under the UI C program
. The Class VI rules contain rigorous requirements for site selection, well construction and operation, testing and monitoring, corrective action, financial responsibility and post
- injection site care and site care. These requirements assure that there will be no endangerment of underground sources of drinking water from sequestered CO 2 and should, by extension, reduc e releases to the atmosphere
. The Class VI Director may also require surface air monitoring and/or soil gas monitoring to detect movement of CO 2 that could endanger a USDW. UI C Class II regulations provide minimum federal requirements for site characteriz ation, area of review, well construction (e.g., casing and cementing), well operation (e.g., injection pressure), injectate sampling, mechanical integrity testing, plugging and abandonment, financial responsibility , and reporting. UI C wells must undergo pe riodic mechanical integrity testing which will detect well construction and operational conditions that could lead to loss of injectate and migration into USDWs. In conjunction with the subpart RR monitoring requirements, these standards likewise assure that injected CO 2 does not endangering underground sources of drinking water and is not released to the atmosphere
. To comply

with the CCS requirement in the rule an EGU must send its captured CO 2 to an EOR or geologic sequestration site reporting under sub part RR. Facilities reporting under subpart RR6
- 57

are required to have a monitoring and leak detection program in accordance with the EPA
approved Monitoring Reporting and Verification (MRV) plan. Additionally, Class VI well owners or operators must develop and update a site
- specific, comprehensive emergency and remedial response plan that describes actions to be taken (e.g., cease injection) to address potential events that may cause endangerment to a USDW during the construction, operation, and post
- injectio n site care periods of the project (40 CFR §146.94). G eologic sequestration sites operating under a Class VI permit must continuously monitor the operation, and, injection must cease if there is evidence that the injected CO 2 and/or associated pressure fro nt may cause endangerment to a USDW (40 CFR § 146.94(b))
. Once the anomalous operating conditions are verified, the cessation of injection, as required b y UI C permits, will minimize any risk of release to air
. The EPA believes that the protections provided by the existing regulatory

framework demonstrate sufficient enforceable requirements to minimize leakage. The EPA cites several studies that have demonstrated the effective and safe storage of CO 2 in EOR operations including the SACROC Unit in the Permian basin which has been injecting CO 2 since 1972, the Wey

burn oil field in Saskatchewan, the Sleipner gas storage project in the North Sea, Snöhvit in the Barents Sea, and In Salah in Algeria, which have all been operating for many ye ars . Under the DOE Phas e III Regional Carbon Sequestration Partnership six projects are currentl y conducting large volume injections, and one, the Cranfield Earl y Test has injected over 8 million metric tons of CO 2 since 2009. The U.S. experience with large
- scale CO 2 injection, combined with ongoing research, development, and demonstration programs in the U.S. and throughout the world, provide confidence that the storage can be achieved and verified at a commercial scale, under commercial scale timeframes. **Comment 6.3 -**  **90:** Commenter 9666 provided a discussion about characteristics of CO 2 storage. Specificall y, the commenter stated that USGS concludes the Gulf Coast area contains almost 60% of the national CO 2 storage capacity in deep saline reservoirs. **Response 6.3 -**  **90:** The USGS assessment es timates a mean of 3,000 billion metric tons of subsurface CO 2 storage potential across the United States which is 500 times the 2011 annual U.S. energy

related CO 2 emissions. I f 60% of this capacity is in deep saline reservoirs in the Gulf coast, there wil l still be 1200 billion tons of storage in the remainder of the U.S.

– more than 200 times the 2011 annual energy related CO 2 emissions. **Comment 6.3 -**  **91:** Commenters 9666 and 10036 stated that although DOE
-NETL studies show that large areas of the US are potentiall y feasibl e for CO 2 storage, CO 2 storage at any one site will not be known until the site is assessed for specific criteria, such as a regionall y extensive confining zone and injectivity . According to Commenter 9666, these criteria cannot be evaluated until the subs urface ph ys ical characteristics of a site are mapped or documented, an anal ys is that requires an extensive effort. Commenters 9666 and 10036 concluded that it can take at least five ye ars to evaluate a site for CO 2 storage potential. Commenter 10036 furthe r stated that no geologic storage site has been characterized sufficiently to guarantee that it will provide secure permanent storage for a commercial
- scale power plant. Commenter 10098 stated that simply identifying a geologic formation as a potential can didate site is not enough to assume that it will actually be viable for carbon storage
. Commenter 10098 further stated that nothing in the proposed rule evinces that the EPA has performed any anal ys is6
- 58

regarding the actual availability of geologic formation s that could comply with the requirements of the Agency ’ s Class VI injection well regulations. Commenter 10048 stated that a significant investment is required to better characterize and quantify the country ’ s sequestration capability
. Commenter 10048 further stated that although a site many initially appear to be ideal for CO 2 sequestration, it may be determined to be unworkable after further detailed investigation. Commenter 9426 stated that to be feasible for CO 2 storage, a site indicated to be favorable for CO 2 storage must be fully characterized and shown to demonstrate particular geologic features, including CO 2 containment in the target geologic formations. **Response 6.3 -**  **91:** The EPA agrees with the commenters that each sequestration determination involves site
- specifi c determinations, which require time and care to perform sufficiently . The site characterization requirements and permit review process for Class VI wells provide a comprehensive framework to ensure sites are suitable for long
- term storage of CO 2 . The site characterization requires anal ys is of many factors including those mentioned by the commenters to ensure CO 2 can be securely contained in the target geologic formations. If the site characterization process identifies unsuitable geologic conditions the developer may be required to remediate the site or to select an alternate storage location. This is one of the strengths of the Class VIand Class II regulatory programs, and why

relian ce on these standards is a reasonable way for the EPA to meet the requirement in CAA section 111 to consider non
- air health and environmental impacts of a standard of performance. The EPA issued Class VI permits to the FutureGen Alliance , a commercial scal e power plant, to inject and sequester captured CO 2 into deep saline formations pursuant to the Class VI regulatory standards
. In doing so, the EPA found, and demonstrated in the administrative record for these permits, that the captured CO 2 can be securel y sequestered for long
- term storage . The commenters are thus incorrect that no geologic site has been sufficientl y characterized to guarantee that it will provide long
- term storage for a commercial scale power plant. Because of the lead times for planning, permitting and constructing a new power plant, the EPA believes the current state of characterization of potential geologic sequestration sites would not be a barrier to CCS. In the time since the commenter submitted comments , several Class VI permits hav e been issued by the EPA. These projects demonstrate that a GS site permit applicant could potentially

prepare and obtain a UIC permit concurrent with permits required for an EGU. As just noted, the EPA’s anal ys es and findings supporting issuance of permit s under the Class VI regulations to Archer Daniel s Midland and FutureGen indicate the availability of “geologic formations that can comply with the Class VI injection well regulations”
. (Of course, the formation does not itself comply ; even if the area of containment is otherwise suitable, the rules require comprehensive construction, monitoring, testing, financial responsibility and other requirements to assure complete and safe containment). The EPA’s estimated compliance costs include the costs for seque stration site characterization and are based on the NETL CO 2 Saline Storage Cost Model and documented in Carbon Dioxide Transport and Storage Costs in NETL Studies (DOE/NETL
- 2013/1614). The model includes co s ts for four sites simultaneously undergoing characterization, each having a 2
- D seismic survey and one test well drilled to collect6
- 59

relevant reservoir data. One of these four sites is selected as the eventual storage site and has an additional test well drilled plus a 3
- D seismic survey covering the Area of Review; pore
- space rights and property access are also costed
. **Comment 6.3 -**  **92:** Commenter 9426 stated CCS cannot serve as a s ystem of emission reduction without a suitable site for carbon storage or reuse that eliminates any emissions or limits on a continuous basis CO 2 emissions to the ambient air. Commenter 9003 stated that it is i nappropriate to require CCS as BSER when the infrastructure to accommodate new units only exists in some areas of the country
. Commenter 9600 stated that the proposal glosses over the availability of infrastructure needed to transport and sequester the CO 2 captured b y coal
- fired EGUs with the proposed BSER. **Response 6.3 -**  **92:** The EPA has determined that partial CCS is the BSER that will meet the standard set in the rule, and suitable sites are available for geologic sequestration. A new SCPC with partial CCS can meet the limi ts on a continuous basis, thus reducing CO 2 emissions to the atmosphere . The rule requires monitoring of emissions from the source to verify compliance with the standard. As discussed in previous responses, studies by the US GS and DOE have identified the capacity to store large volume of CO 2 across broad areas of the country. Many of the areas without saline storage potential are not expected to have new coal
- fired EGUs built without CCS for legal or practical reasons. The EPA believes that the rule will a dvance CCS technology and spur development of the necessary infrastructure to support broad development of CCS. **Comment 6.3 -**  **93:** Commenter 10618 noted the experiences of the Mountaineer CCS programs that indicated the complexity at every level of developing injection well s in regards to technical, financial, and schedule risks
. Commenter 10618 further noted that the agency failed to properl y account for various design and development barriers in their evaluation of CCS as BSER. **Response 6.3 -**  **93:** E ach sequestration site involves highl y 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 CO 2 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 F utureGen permits for Class VI wells involved far fewer injection and monitoring wells than AEP references. 6

6 The FutureGen UIC Class VI injection well permits (four in total) require nine monitoring wells. http://www.epa.gov/r5water/uic/futuregen/. The Archer Daniels Mi dland UIC Class VI injection well permit issued in September 2014 (CCS2) requires five monitoring wells and the Archer Daniels Midland UIC Class VI injection well permit issued in December 2014 (CCS1) was permitted with two monitoring wells. http://www.epa.gov/region5/water/uic/adm/
.6
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The commenter’s reference to the experiences with the Mountaineer project is not reflective of the rule for new fossil fired EGUs. The Mountaineer C CS project was an early pilot scale development project to demonstrate the commercial viability for retrofitting an existing coal
fired power plant. The plant was not initially sited and constructed to consider the needs and technical requirement of CCS, b ut initial assessment indicated that the plant may be suitable for retrofit and associated CCS storage. The project was cancelled in July 2011 due to several factors including economic and policy conditions ; however, the project increased the understanding of technical and project risks associated with CCS development. In the time since the Mountaineer project was initiated, there have been numerous technical advancements, and much has been learned to facilitate the development of CCS projects. The EPA has evaluated potential design and development barriers for CCS as part of the BSER analy sis, and has concluded that there are no insurmountable technological, legal, institutional, regulatory or other barriers that would prevent broad deplo ym ent of CCS. **Comment 6.3 -**  **94:** Commenter 9194 stated that there is no factual basis on which the EPA may assert that sequestration technology meets the required three part test for Section 111 technologies
- that it is widely usable and technical ly

and economicall y feasible
. Commenter 9194 further stated that the EPA has not examined the entire sy stem and fails to include in the standard the critical components
-- sequestration, transportation and monitoring
-- to assure emission reductions are accomp lished. Commenter 9648 agreed with the EPA ’ s conclusion that there is not sufficient information and knowledge about geologic sequestration and the commenter believes that the EPA's statements about CO 2 storage confirm that this technology is not BSER. **Response 6.3 -**  **94:** The commenter’s legal argument is addressed in section 2 of this document
. Briefl y, there is no requirement in section 111 that a standard of performance address the fate of captured pollutants which are not emitted to the atmosphere
. Rather, there is a requi rement that non - air health and environmental impacts of a standard be considered, and the EPA has done so here, documenting that captured CO 2 will be safely transported, accounted for, and sequestered over the long
- term (in Class VI or Class II sites). The comments are also factuall y mistaken
. CO 2 transport is demonstrated many times over
. A substantial network of CO 2 pipelines exist, and are comprehensivel y regulated under standards adopted b y the U.S. Department of Transportation Pipeline Hazardous Materials Safety Administration found at 49 CFR part 195 (Transportation of Hazardous Liquids by Pipeline). Sequestration of captured CO 2 is likewise comprehensively regulated under the regulations for underground injection
. The UIC Class VI requirements facilitate injection of CO 2 for GS, while protecting human health and the environment b y ensuring the protection of underground sources of drinking water
. Moreover, the EPA has issued class VI permits under the Class VIprogram, and obviously

would not have done so without the administrative record for each permit demonstrating that geologic sequestration of captured CO 2 in the injection sites was both technicall y feasible, and fully protective. Finally , injection of anthropogenic CO 2 for EOR has a many de cades long operating experience, is well understood, and has been successfull y applied.6
- 61

The EPA ’ s recognition that additional work is needed to advance the understanding of certain aspects of sequestration should not be construed to suggest that there is c urrently insufficient information or knowledge to evaluate the technical feasibility and availability

of CCS. The EPA has documented many successful projects that demonstrate that the technology meets the requirements for BSER
. **Comment 6.3 -**  **95:** Commenter 9666 stated that because any NSPS must actually reduce emissions, the EPA must show that its proposed standard based on CCS contains achievable limits on the CO 2 emitted from sequestration sites receiving separated CO 2 from regulated new sources. According to the commenter , the EPA has not made, and cannot make, this showing. Furthermore, the commenter stated that the EPA provides no evidence that the separated CO 2 will remain in geological storage, and does not require such storage in the proposed rule. Commenter 9666 stat ed the EPA's proposed rule does not even evaluate permanent geological storage of large volumes of CO 2 , much less find that such storage has been demonstrated. **Response 6.3 -**  **95:** See Section V.N.5 of the final rule preamble of the NSPS for the EPA’s response to this comment. As described in previous responses within this section, the EPA has evaluated GS of large volumes of CO 2 through a review of several large scale commercial CO 2 injection and storage cases as well as the latest research and development conducted b y DOE and has concluded, based on these examples, that such storage has been demonstrated. Additionally , the effectiveness of long
- term trapping of CO 2 has been demonstrated b y natural analogs in a range of geologic settings where CO 2 has remained trapped for millions of years. **Comment 6.3 -**  **96:** Commenter 1902 stated that knowledge about potential formations that might be suitable for permanent storage of commercial volumes of CO 2 produced by a power plant is incomplete. Commenters 1902 and 9602 stated that it is not feasible or demonstrated to hold the CO 2 volume for hundreds and perhaps thousands of years
. Commenter 10036 further stated that there is little experience injecting CO 2 into c oal seams for permanent storage because of various setbacks. Commenter 7977 noted that the proposed regulation provides no scientific evidence of long
- term storage of CO 2 . Commenter 10095 stated that limitations and uncertainties regarding the adequacy of coal seams for CO 2 storage remain and that access to coal seams may not be available due to the value of coal as a commodity
. Commenter 10095 further stated that there is little experience injecting CO 2 into hydraulically

fractured coal seams for permanent storage due to their structure posing risks to their structural integrity and drinking water sources. Commenter 9194 noted that deep saline aquifers have not been geologically assessed b y either the private sector or the government on the level needed to adequatel y demonstrate that there are consistent caprock typ e formations to hold CO 2 under pressure for hundreds and perhaps thousands of years. **Response 6.3 -**  **96:** As discussed elsewhere in this section, the EPA not only has found that large scale geologic sequestration of anthropogenic CO 2 is possible and promulgated a regulatory6
- 62

framework for how to do so safel y without endangering underground sources of drinking water, but has issued permits under the Class VI UI C program to conduct such geologic sequestration
. Four of the se permits were for injection of CO 2 from a fossil
- fuel (coal
- fired steam generating EGU (Future Gen)
. As described in section V. N of the preamble to the final rule, the Class VI rules, complemented b y the subpart RR reporting and monitoring requirements, a ssure as well that injected CO 2 will remain sequestered without release to the atmosphere
. The EPA believes that existing data from DO E research programs show that CO 2 can be sequestered safel y and effectivel y . T he monitoring programs required as part for the UIC Class VIpermit and GHGRP subpart RR reporting will identify an y such releases. The rule requires captured CO 2 to be sent to a facility that will ensure the safe and secure long term storage, and document the volume received. The site characterization, modeling and monitoring requirements under UIC Class VI P rogram ensure that knowledge about potential formations for long
- term storage is developed and reviewed prior to authorizing injection. Site characterization requires a significant level of geologic data collection, testing and modeling to demonstrate that the caprock (i.e., confining zone) can provide the containment necessary to ensure long term storage. The BSER anal ys is and RIA rel y on GS in deep saline formations. Curre nt estimates of storage capacity indicate that coal seams provide only a small percentage of total US storage capacity. **Comment 6.3 -**  **97:** Commenter 10664 stated that there is a strong implication that technologies that recycle captured CO 2 to produc e a sustainable fuel, which will subsequently release CO 2 into the atmosphere when later combusted b y a mobile source, do not permanently store or isolate that CO 2 molecule from the atmosphere and therefore may not be used by EGUs to meet the CO 2 emission limit. **Response 6.3 -**  **97:** The rule generall y requires that captured CO 2 be either injected on
- site for geologic sequestration or transferred offsite to a facility reporting under 40 CFR subpart RR
. The EPA recognizes there are emerging technologies alternative to geologic sequestration that are designed to safel y sequester or otherwise utilize captured CO 2 such that it is not released to the atmosphere
. These technologies are not sufficiently advance d that the EPA is prepared to unqualifiedly

structure this final rule to allow for their use, nor are there plenary s ys tems of regulatory

control and GHG reporting for these approaches, as there are for geologic sequestration
. Nonetheless, as stated above, these technologies not only show promise, but could potentially

be demonstrated to show permanent storage of CO 2 . The final rule provides for a case - by
- case adjudication by the EPA of applications seeking to demonstrate to the EPA that a non - geologic sequ estration technology would result in permanent confinement of captured CO 2 from an affected EGU. **Comment 6.3 -**  **98:** Commenter 9513 agreed with the EPA that CO 2 injection into geologic formations is technicall y feasible and that the EPA ’ s decision to move forward with a CCS requirement is justified, but also noted that more work needs to be done to ensure that the injected CO 2 will remain sequestered for geologic time frames and will not cause or contribute to unintended adverse consequences. Commenter 9513 stated that the EPA must work with the appropriate authorities to develop a better technical understanding of the risks and develop6
- 63

definitive site characterization, monitoring and remediation protocols and a comprehensive regulatory

scheme for geologic sequestration. **Response 6.3 -**  **98:** Facili ties that inject CO 2 for long
- term storage must obtain a UI C Class VI permit. The UIC C l ass VI program requires extensive subsurface analy sis , computational modeling to delineate the project area (the “area of review”) and monitoring , as well as post
injec tion site care and site closure to ensure the CO 2 will remain sequestered for long periods. The EPA has developed detailed guidance documents for UI C Class VI permit applicants regarding project plans, well construction, site characterization, monitoring and remediation protocols. Research is being conducted b y DOE through the National Risk Assessment Partnership to develop risk assessment tools to support geologic sequestration project risks and ensure safe, long
- term storage . The EPA believes that there is a comprehensive regulatory framework for geologic sequestration that includes the SDWA UI C Cl ass VI rule, CAA GHGRP Reporting Program rule, the RCRA CO 2 Hazardous Waste Exemption and DOT pipeline safety standards. These federal rules provide the basic f

ramework for the safe and secure storage of CO 2 . The Class VI permits issued to Archer Daniel s Midland and FutureGen reflect the EPA’s findings, documented in the administrative record for each permit, that the sequestration sites at issue were suitable f

or long
- term, secure and safe storage of large volumes of CO 2 . **Comment 6.3 -**  **99:** Commenters 9666 and 9774 stated carbon sequestration has not been proven on a long
- term basis and CCS has not been implemented within the utility sector to the extent necessary for setting an NSPS. Commenter 9666 stated there is no relevant operating experience to support a finding that permanent geological sequestration of CO 2 on the scale required for use with commercial power generation has been adequately demonstrated, or that any level of CO 2 emission from sequestration repositories is achievable under the range of relevant conditions for the industry

as a whole. Commenters 9197 and 9596 noted that experts and stakeholders have raised significant questions about the long
- term feasibility of sequestering large amounts of CO 2 underground. **Response 6.3 -**  **99:** EPA cites several examples of CO 2 injection sites that have been in operation for many ye ars, including the SACROC site in Texas that has been safel y i njecting CO 2 for more than 40 years . The EPA believes that the examples provided demonstrate that the three components of CCS, capture, transport and storage, have been adequatel y demonstrated and support the development of this NSPS. Monitoring data from injection sites in a wide range of geologic settings indi cate that CO 2 can be sequestered safely and effectively
. **Comment 6.3 -**  **100:** Commenters 10036 stated that the US could potentially store billions, may

be trillions, of tons of CO 2 in deep saline formations (based on the Carbon Atlas), but sustained operations and monitoring of CO 2 in saline formations in the US have not progressed beyond the demonstration phase
. Commenter 10095 stated that the US could potentially store more than 1 2 billion tons of CO 2 in deep saline formations, according to a DOE report. Commenter 10095 further stated that saline formations must demonstrate particular geologic features, including CO 2 containment in the target geologic formations and non
- interferenc e with underground sources of6
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drinking water
. Commenter 10095 noted that CO 2 storage in saline formations is occurring but not with CO 2 captured from an EGU. Commenters 9774 stated that carbon sequestration capacity is not proven and available at all potential sites of a new coal
- fired generating unit. Commenters 0587 and 10036 stated that carbon sequestration has not been proven on a commercial scale. Commenter 9774 noted that the EPA identifies the carbon storage capacity in North America while also ackno wledging that virtually all of this capacity

is unproven. According to Commenter 9774, the EPA must rely onl y upon proven sequestration sites in the analy sis of CCS. Commenter 8925 cited a real
- life example studied by the SECARB partnership to illustrate that the area in the subsurface occupied b y injected CO 2 emissions from a single EGU will likely extend over many

square miles and stresses the importance of characterizing and utilizing large regional reservoirs for storage due to the large quantities of CO 2 from multiple EGUs. Commenter 10031 stated that significant uncertainties exist with regard to candidate sites for sequestration. Commenter 9396 referred to a statement from API stating that there are significant challenges to scaling up CCS for EGUs. **Response 6.3 -**  **100:** The monitoring and operational experience gained from EOR projects over the past 40 years is directly applicable to storage in saline formations, and provides a strong basis for demonstrating the feasibility of CO 2 storage in saline formations. Large scal e demonstration projects such as Cranfield and I llinois Basin Decatur Project further support the feasibility of saline storage. Prior to receiving a UIC Class VI permit the applicant must demonstrate that geologic features at the proposed injection site ensure CO 2 containment in the target geologic formations and that the GS project would not impact underground sources of drinking water
. The response to Commenters ’ 0587, 10036 and 9774 assertion that sequestration has not been proven on a commercial scale is addressed elsewhere in this section. The review process for UI C Class VI permit applications will address the commenters ’ concerns that regional reservoirs are used for storage due to the large quantities of CO 2 from multiple EGUs. The rigorous review and ongoing monitoring required under UIC Class VI will reduce the uncertainties that exist with regard to candidate sites for sequestration. **Comment 6.3 -**  **101:** Commenter 9666 stated the adequate demonstration of CO 2 storage will depend on the resolution of numerous technical issues and that sequestration of CO 2 generated by a new source may

not prevent the emission of that CO 2 to the ambient air. According to the commenter, CO 2 must be injected at extremel y high supercritical pressures to enter either a saline reservoir or a depleted oil and gas reservoir. Once injected below the surface, supercritical CO 2 is buoyant and will both rise to the top of the storage formation and radiate outward from the injection point in a horizontal manner below the caprock layer. The commenter stated it is essential that the geology of a carbon storage site ensures a secure fate and that CO 2 does not migrate through fractures to penetrate groundwater reservoirs and is not released to th e ambient air through abandoned wells.6
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Commenter 8966 stated that carbon storage raises many safety, environmental, and liability issues that have not been adequatel y demonstrated by the EPA
. Commenter 8966 noted that the reservoirs required under the CCS model must contain a capacity not yet achieved or tested in practice
. Commenter 8966 raised concerns that sequestration on such a large scale poses severe risks in the event of reservoir leaks that can rise to the ground surface
. Commenter 8966 further st ated that a fundamental lack of understanding in the physics of CO 2 leakage and the processes that control leakages dictates that development of large CO 2 reservoirs is not ready for commercial implementation. Commenter 1747 stated that any standard that relies on sequestration must ensure that CO 2 injected stay s out of the atmosphere, and that the parties required to meet the standard are responsible for the leakage. Commenter 7433 stated that there is a concern with leakage of stored CO 2 and whether that will compromise CCS as a GHG emission mitigation option. Commenter 9202 stated that the storage of captured CO 2 must be secure for an exceptionally long time frame and that leakage of stored CO 2 negates all benefits of capturing emissions. **Response 6.3 -**  **101:** The site charac terization and monitoring requirements in the UI C Class VI permit program and the monitoring required b y Subpart RR provide a framework to ensure that the geology

of a carbon storage site provides a secure storage and that CO 2 does not migrate through frac tures to endanger underground sources of drinking water and does not migrate through abandoned wells or other leakage pathways (U IC Program) and is not released to the atmosphere (Subpart RR)
. Site characterization requires extensive data collection and computational modeling to predict the behavior of CO 2 in the subsurface, and ongoing monitoring to demonstrate that the CO 2 is behaving as predicted. These computational models apply fundamental and advanced understanding of the chemical and phy sical interactions of CO 2 in the subsurface. UIC Class VI regulations require computational model ing to determine the fate of the CO 2 as part of the Area of Review. Specifically , 40 CFR 146.84(c)(1) states that o wners or operators of Class VI wells must predict, using existing site characterization, monitoring and operational data, and computational modeling, the projected lateral and vertical migration of the CO 2 plume and formation fluids in the subsurfac e from the commencement of injection activities until the plume movement ceases, until pressure differentials sufficient to cause the movement of injected fluids or formation fluids into a USDW are no longer present, or until the end of a fixed time period . The requirement goes on further to specify the model must take into account any geologic heterogeneities or other discontinuities
. The MRV Plan that is prepared under subpart RR requires an assess ment and risk evaluation of potential leakage pathways. S everal large CO 2 injection and storage examples have demonstrated that CO 2 can be sequestered at a capacity

necessary

for commercial implementation. The SACROC Unit in the Permian basin has injected CO 2 since 1972 for enhanced oil recovery purposes. One study evaluated a portion of this project, and estimated that the injection operations resulted in final6
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sequestration of about 55 million tons of CO 2 . 7 This study used modeling and simulations, along with collection and anal ysis of seismic surveys, and well logging data, to evaluate the ongoing and potential CO 2 trapping occurring through various mechanisms. The monitoring at this site demonstrated that CO 2 is trapped in geologic formations. In a separate study in the SACROC Unit, the Texas Bureau of Economic Geology conducted an extensive groundwater sampling program to look for evidence of CO 2 leakage in the shallow freshwater aquifers. No evidence of leakage was detected. 8 An extensive CO 2 leakage monitoring program was conducted b y a third party (International Energy

Agency Greenhouse Gas Programme) for 10 years at the Wey burn oil field in Saskatchewan, during which time over 16 million tonnes of CO 2 have been stored. The Cranfield test in Mississippi has stored over 4.7 million metric tons of CO 2 in a saline reservoir since 2009, with no evidence of leakage. At the Sleipner site in Norway more than 15 million tons of CO 2 have been stored in the saline aquifer with no evidence of leakage . The EPA believes that these large scale injection and demonstration projects show the capacity to store CO 2 from EGUs on a commercial scale
. **Comment 6.3 -**  **102:** Commenter 9666 provided the following technical information related to sequestrati on: to comply

with the proposed standard, a 500 MW boiler firing bituminous coal at a gross heat rate of 8,500 Btu/kWh and an 80 percent capacity factor would need to separate almost 1.2 million tons of CO 2 , which would produce approximately 1.5 million cu bic meters of CO 2 at supercritical pressure annuall y for sequestration. **Response 6.3 -**  **102:** The Archer Daniel s Midland Class VI permit is for injection and sequestration of an estimated 5 .5 million tons of CO 2 . The FutureGen Class VI permit s are for 22.5 million tons of injected CO 2 . These projects are of a magnitude comparable to the (hy pothetical) example in the comment
. We repeat that the EPA’s findings, and administrative record supporting those findings, is that each site was capable of safe ly sequestering the injected CO 2 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 CO 2 to the atmosphere
. The commenter’s estimate of the mass and volume of CO 2 produced from a standard 500 MW boiler is consistent with the estimates DOE has used as guidelines for the Regional Carbon Sequestration Partnership Phase III Demonstration projects for large scale injection and storage. Under the DOE Phase III Regional Carbon Sequestration Partnership six projects are currently conducting large volume injections, and one, the Cranfield site has injected over 8 million metric tons of CO 2 since 2009. Globall y, there are commercial integrated CCS facilities safely and

7 Han, Weon S., McPherson, B J., L ichtner, P C., and Wang, F P. “Evaluation of CO 2 trapping mechanisms at the SACROC northern platform, Permian basin, Texas, site of 35 years of CO 2 injection.” American Journal of Science 310. (2010): 282
- 324. 8 Romanak, K.D., Smy

th, R.C., Yang, C., and Hovorka, S., Detection of anthropogenic CO 2 in dilute groundwater: field observations and geochemical modeling of the Dockum aquifer at the SACROC oilfield, West Texas, USA: presented at the 9th Annual Conference on Carbon Capture & Sequestration, Pittsburgh, PA, May 10
- 13, 2010. GCCC Digital Publication Series #10
- 06.6
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effectivel y sequestering captured CO 2 into deep geologic formations at rates of one million tonnes per ye ar. **Comment 6.3 -**  **103:** Commenter 9194 noted that CO 2 currently used in the oil and gas sector in the US and w orldwide is recycled, not permanently stored, and that CO 2 in this industry has a residence time of only

day s. The commenter additionally noted that this is in sharp contrast to the idea of CO 2 storage for the power sector that the EPA is proposing. **Response 6.3 -**  **103:** The EP A does not agree with commenter’s assertion that CO 2 currently used in the oil and gas sector is recycled, not permanently stored. In the EOR process some of the CO 2 is recycled but large amounts are stored via residual trapping, solubility trapping and stratigraphic trapping. Direct observation of trapping in the deep subsurface is not possible but numerous monitoring and modeling studies have demonstrated the permanent storage of CO 2 in EOR operations. The SACROC Unit in the Permian basin is one example of long term CO 2 storage. A 2010 study evaluated the trapping mechanisms using numerical models, and identified residual trapping and solubility trapping as the dominant trapping mechanisms over a 200 year modeling period
. The volumes of CO 2 injected and stored at SACROC are consistent with the volumes expected from plants covered under this rule. **Comment 6.3 -**  **104:** Commenter 10035 stated that excessive emphasis on underground injection and geologic sequ estration as approaches to achieve the standards would be shortsighted, as it would limit the amount of CO 2 that could be sequestered, reused, or recycled by other means. Commenter 10035 further stated that excluding CO 2 utilization would directly impact i nvestments in the US manufacturing base and development of innovations to reduce greenhouse gas emissions. Commenter 9317 stated that a blanket prohibition on alternatives to geologic sequestration actuall y discourages the development of alternatives and that the EPA should instead propose a streamlined approach for approving alternatives to CCS that states could consider. **Response 6.3 -**  **104:**
. The final rule provides for a case
- by
- case approval mechanism for alternative CO 2 storage methods. **Comment 6.3 -**  **105:** Commenter 10098 stated that EPA has not grappled with findings that many potential geological storage areas could be impacted by shale gas development. Commenter 10098 noted that a recent study found that as much as 80% of deep saline aquifers overlap with potenti al shale
- gas production reg ions (commenter provided journal article citation). Commenter 10098 further notes that this could lead to the EPA imposing restrictions on the very gas production activities that make a severe curtailment of new coal
- fired electricity generation possible. **Response 6.3 -**  **105:** The presence of shale gas development areas that are spatiall y coincident with areas potentiall y suitable for geologic storage or EOR does not necessarily preclude the use of the saline or oil bearing zone for sequestration. Under the Class VI permit, each sequestration site must undergo a rigorous risk anal ys is to determine if safe long
- term storage is possible. The depth and thickness of potentially productive shale formations would be evaluated along with the depth of the saline storage formation, and th e typ e and thickness of the intervening geologic6
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layers. Onl y areas where storage locations are incompatible with oil and gas extraction would potentially

affect production. Following Class VI geologic storage site closure, the owner or operator of a Class VIinjection well must record a notation on the deed to the facility property ( 40 CFR 146.93(g) ) . The notation must state that the land has been used for GS, the name of the state agency , local authority , and/or tribe with which the survey plat was filed, as well as the address of the EPA Regional Office to which it was submitted; and the volume of fluid injected, the injection zone(s), and the period over which the injection occurred. This notification will enable regulatory authorities to impose appropri ate conditions on subsequent drilling activities that may penetrate the injection and confining zone(s). **Comment 6.3 -**  **106:** Commenter 9683 noted that scale
- up presents perhaps even thornier complexities for storage than for capture. For large
- scale storage, an area potentially dozens of square miles across must be studied. A confining zone free of transmissive faults and fractures must be present and must be of sufficient thickness, and the formation must exhibit porosity and permeability

to accommodate high
- volume injections over decades. Furthermore, storage of tens of millions of tons of CO 2 in a saline or other non
- EOR formatio n requires aggregation of property rights across a broad area potentiall y encompassing not only areas to which the CO 2 may migrate, but areas into which brines and other materials displaced by CO 2 injections may reach. **Response 6.3 -**  **106:** The commenter is correct that large areas may need to be studied for certain storage sites. Site characterization is critical to operating safe and effective geologic sequestration projects and identifies potential risks and eliminates unacceptable sites. Large scale subsurface studies are commonly required in other industries including mining, oil and gas exploration, water resources and waste management. See the Section 6. 3 topic titled Geologic Sequestration P roperty Rights for responses to property rights comments . **Comment 6.3 -**  **107:** Commenter 9600 noted that while the proposal recognizes that CO 2 sequestration, or storage or utilization in EOR activities at an EGU site would require pipeline transportation and subsurface injection facilities offsite, the proposal offers no rational discussion regarding the availability of these facilities
. Additionally , Commenter 9600 noted that the proposal does not address phy sical or economic considerations associated with CO 2 storage. Commenter 10618 stated that the equipment to capt ure CO 2 is large and an entire s ys tem capable of treating the effluent of a power plant requires extensive tracts of land
. The commenter cites an AEP/Alstom study

and further states that size alone would preclude the use of the technology at many existing power plants and must be carefully considered in the design of any new power plant. **Response 6.3 -**  **107:** The commenter is mistaken
. The ph ys ical and cost issues associated with CO 2 sequestration (i.e. storage) were discussed in detail at the proposal
. See e.g. 79 FR at 1482
- 1484 (preamble); Draft RIA (EPA
- 452/R
- 13
- 003) at pp. 5
- 29 to 30 and NETL Cost and Performance of PC and IGCC Plants for a Range of Carbon Dioxide Capture (DOE/NETL
-6
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2011/1498) at pp. 46
- 50. The EPA has addressed the availabili ty of CO 2 pipelines in the Section 6.3 topic titled CO 2 T ransport , and the availability of offsite subsurface injection facilities in the Section 6.3 topics titled Geologic Sequestration and Enhanced Oil Recovery and CO 2 Utilization
. The EPA discusses the phy sical considerations a ssociated with CO 2 storage in terms of the capacity estimates of saline storage areas and notes that 95% of the current coal fired plants are within 50 miles of potential storage sites. The proposal also discusses the availability and location of EOR, wher e injection facilities, pipelines and other supporting infrastructure are in operation. An extensive discussion of economic and cost considerations is presented in the Regulatory

Impact Analysis for the NSPS, and summarized in the preamble to the rule. Th e EPA agrees with the commenter that additional equipment is required for CO 2 capture at EGUs and the footprint of some existing plants may not allow for the equipment to be installed. Today ’s rule applies to new plants exclusively which can be sized to ac commodate the equipment. With regard to AEP and Alstom statements, contemporaneous statements of both companies extolled CCS, praised the success of the Mountaineer project, indicated that a regulatory mandate for CCS would further investment in and furth er deplo ym ent of CCS, and that the project was not implemented full scale due at least in part to the absence of such regulatory certainty. See preamble section V.I.4. See also statement of Alstom senior Vice President for Power and Environment Policies Joan Macnaughton (August 4, 2011): “AEP’s decision to put Mountaineer II on
- hold (sic) is a bellwether to our leaders on the consequences of uncertain climate policy . The Validation Plant at Mountaineer demonstrated the ability to capture up to 90% of the carbon dioxide from a stream of the plant’s emissions. The technology works. But without clear policies in place outlining options for cost recovery , power generators are hard
pressed to invest in its continued refinement.” The press release further st ates that Vice President MacN aughton “presented findings from a recently
- conducted cost analy sis showing that the cost of electricity generated b y coal and natural gas plants equipped with CCS is competitive with other low or no
- carbon energy sources, such as wind, solar, geothermal, h ydro and nuclear.” See http://www.alstom.com/Global/US/Resources/Documents/Press%20Releases/PR_JMacN_CCSb riefing_FINAL.pdf **Comment 6.3 -**  **108:** Commenter 10098 stated that it would not be unreasonable to assume that, in certain geographic locatio ns with limited CO 2 transportation and storage options and under certain market conditions, a power plant with CCS capability could find itself having to give away CO 2 or even pay

for the disposal of its captured CO 2 stream, which reverses the EPA ’ s prior position on the issue of selling CO 2 for EOR without any explanation. **Response 6.3 -**  **108:** The BSER and regulatory impact anal ys is assume GS in deep saline formations . The EPA recognizes that some EGUs may not be located near EOR areas, which provide an opportunity to defray s ome of the cost associated with partial CCS, and may incur costs for the transportation and storage of CO 2 . **Comment 6.3 -**  **109:** Commenter 9195 noted a DOE document "Mitigation Action Plan for the W.A. Parish Post
- Combustion CO 2 Capture and Sequestration Project" and proposed the following questions to the EPA regarding DOE ’ s view on carbon storage activities:6
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1. Does EPA fully

agree with this assessment? (Explain EPA rationale/legal justifications) 2. If EPA does not full y agree, has or will EPA object? Why or why not? 3. (Co mmenter also asks to) Provide any documentation that EPA considered this or other determinations made b y DOE or other agencies that CCS is a connected s ystem that includes storage. **Response 6.3 -**  **109:** A response is not provided here as this comment is outside the scope of the NSPS. The referenced document relates to a National Environmental Policy Act (NEPA) mitigation plan for DOE’s action of providing partial funding to construct an industrial CO 2 capture s ys tem and pipeline, and conduct monitoring. The CO 2 will be used for EOR and the EOR aspect of the project, although not funded b y DOE, was included in the project description because the s ys tem components are integrated into the project concept and considered connected actions
. **Comment 6.3 -**  **110:** Commenter 10786 also discussed the storage o f CO 2 , stating that the EPA has not provided support for the position that CO 2 losses downstream are expected to be modest. **Response 6.3 -**  **110:** The EPA believes that CO 2 losses downstream will be modest based on the review of monitoring data from numerous CO 2 storage sites. The characterization, construction and operational requirements in the UI C Class VI permit and the monitoring requirements in subpart RR provide additional support to ensure safe operation and earl y detection of leakage. **Comment 6.3 -**  **111:** Commenter 8925 discussed the relative scale and relevant lessons learned from the three large scale projects in the world currently injecting CO 2 at approximately one million metric tons per year. The commenter notes the following project comparisons and lessons learned:

 Eac h project is only

approximately

one - third of the CO 2 that would be stored by a single 1,000 MW coal
- fired EGU, illustrating the need to rapidly expand our experience base to scales commensurate with full scale commercial power projects to improve technical certainty, operational reliability and a better understanding of project costs upon which sound financial investment decisions can be made. Commenter 9666 also echoed the need for an expansion of experience and commercial demonstration.  Adequate monitorin g and anal ys es at the sites are critical to inform the operator of a potential problem and shut down of CO 2 injection before the caprock is breached.  There are significant risks associated with geologic uncertainty at storage site. The large volumes invol ved with full
- scale CO 2 storage and scarcity of information on saline formations may

require that several attempts be made to identify specific injection sites with suitable storage capacity and formation injectivity . For example, project developers for th e onshore ZeroGen project in Australia spent AU$90 million on site characterization activities before the project was abandoned because the formation was found to be uneconomical for large scale CO 2 storage. Commenter 9666 also discussed the economic and t emporal implications of assessing the viability of a site for storage, determining that the site is unsuitable, and then starting the evaluation process again at a different site.6
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Commenter 10097 stated that the proposal does not address phys ical and econo mic considerations associated with transport and storage. **Response 6.3 -**  **111:** The EPA believes that the current experience with large scale capture and storage projects is applicable to larger sy stems, such as the 1000 MW plants the commenter describes. The selection of partial CCS as BSER will further technological development and improve operational reliability and provide a better understanding of project costs for larger projects. The current regulatory

framework provides extensive requirements for operators to monitor and anal yz e site operations to ensure the safe storage of CO 2 . In particular the UIC permit requires monitoring to detect anomalous conditions that could indicate leakage. F ailure of mechanical integrity would necessitate the cessation of injection in accordance with the UIC permits. Site characterization is an essential element in reducing risks associated with geologic uncertainty at storage sites, and not all propos ed sites will meet the requirements for demonstrating safe and secure storage of CO 2 . DOE has developed guidance for selecting sites, and through the Regional Carbon Sequestration Partnerships has conducted detailed geologic evaluations of regional areas t o help focus the assessments and reduce the time and cost of site selection. The response to the transportation considerations in this comment are addressed in the prior section . The EPA discusses the physical considerations associated with CO 2 storage in terms of the capacity

estimates of saline storage areas and also discusses the availability and location of EOR, where injection facilities, pipelines and other supporting infrastructure are in operation. An extensive discussion of economic and cost consid erations is presented in the Regulatory Impact Analy sis for the NSPS, and summarized in the preamble to the rule. **Comment 6.3 -**  **112:** Commenter 9425 stated water use could also be an issue in many locations as it is estimated that the addition of an amine
- based CCS system wou ld double the consumptive water use of a power plant, which may be unacceptable in some locations. **Response 6.3 -**  **112:** The commenter appears to exaggerate the extent of water use needed for post - combustion partial CCS
. See preamble section V.O.2. **Enhanced Oil Recovery and CO**  **2 Utilization**  **Comment 6.3 -**  **113:** Commenter 9664 stated that EOR is an essential part of a widely available near term sy stem for transportation and sequestration of CO 2 . **Response 6.3 -**  **113:** EOR provides an opportunity for EGUs to defray some of the cost of CCS using infrastructure that is already in place. Twelve states currentl y have active EOR operations, and 18 states are within 100 kilometers of active EOR areas. **Comment 6.3 -**  **114:** Commenters 10098 and 10239 stated that, without justification, the EPA arbitraril y and capriciously asserts that CO 2 captured from coal
- fired EGUs can be transported and sold for enhanced recovery of oil and other hydrocarbons and fails to account for the6
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regulatory

and economic conditions that may prevent or dissuade EOR operators from using anthropogenic CO 2 in their operations. Co mmenter 10618 states that regulatory challenges for EOR operators may

be significant as well, citing the October 2013 comments from U.S. EPA on the draft environmental impact statement for the proposed Hydrogen Energy California IGCC/CCS project . The EPA 's comments note that for the Elk Hills Oil Field, the thousands of well bores on the site create a potential for leaking of the injected CO 2 , and the EPA recommended that the old wells with the potential for leaking should be located and permanentl y sealed. Commenter 10618 stated that the prospect of being required to locate and permanentl y seal "hundreds of wells" and "thousands of well bores" is simply not practical, far outside the ty pical scope of EOR operations, and alone would likely doom any CCS proje ct from being developed, as the process is time
- consuming and the outcome of requirements is wrought with uncertainties. **Response 6.3 -**  **114:** The BSER determination and regulatory impact analy sis for this rule relies on GS in deep saline formations
. However, the EPA also reco gnizes the potential for sequestering CO 2 via EOR and allows the use of EOR as a compliance option . The EPA disagrees wi th the commenters ’ example that locating and plugging wells is not practical and far outside the ty

pical scope of EOR operations. The current UI C Class II permit process for EOR projects includes conducting studies that ensure USD Ws are protected from endangerment during injection. This process requires identifying active and inactive wells within the Area of Review, and demonstrating that all wells are properly constructed or have been plugged in a manner that will not permit the movement of fluids into strata other than the permitted injection zone . Where new Class II wells are constructed, wells within their Areas of Review must undergo correction actions, including plugging or remediation, prior to injection to ensure protection of USDWs. Additionally, planning for EOR includes identifying and mitigating barriers that prevent full contact of CO 2 with the oil, such as preferential flow paths or movement of CO 2 into non oil
- bearing areas, caused b y m anmade conditions such as improperly plugged boreholes and wells. **Comment 6.3 -**  **115:** Commenters 9201, 9472, 9426, 9683, 9666, 9678, 10048, 10098 and 10239 stated that the EPA provides no support that a future coal
- fired EGU will be reasonabl y close to one of the approximately 100 EOR sites in the country . Commenter 8024 disagrees with the EPA ’ s view that potential EOR applications represent a viable path for capturing and sequestering CO 2 emissions from utility
- scale power plants. Commenter noted that EOR opportunities are inherently limited to petroleum
- producing regions, or areas with available pipeline access, and do not extend to the full range of states to which the NSPS apply
. Comment ers 10036 and 10095 noted the limited availability of EOR as an option for new EGUs in certain regions. Commenters 9657 and 10017 stated that enhanced oil recovery (EOR) is not widely available across the U.S. Commenter 9657 noted that the vast majority of CO 2 - EOR is conducted in oil reservoirs in southwest Texas and southeast New Mexico, along with eleven other states. Commenter 7977 noted that although the proposed rule has nationwide applicability , the fact that EOR seldom occurs in Kentucky prevents EGUs located in the state from rel yi ng on EOR to defray

the cost s of implementing CCS, making CC S not economically feasible. Commenters 1959 and 9657 noted that for large portions of the U.S., EOR cannot be viable, geologically . Commenter 10105 stated that N evada ’ s ability to employ

C C S for enhanced oil recovery is limited, as Nevada has small oil fields, and the conditions of Nevada's oil fields are geologically

unsuitable and are susceptible to leakage. Commenters 9678 and 10043 assert that6
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EOR is not a wid ely

available method and Commenter 10043 asserted that most utilities are not near EOR sites or geologic formations suitable for long term storage. Commenter 2471 stated that the projects used b y EPA to justify CCS as BSER are EOR projects and none are planned to inject CO 2 into geology

that has no recovery

opportunities for oil and gas. According to the commenter, b y contrast, many coal and natural gas fired plants in the US are located in states with little or no oil and gas recovery opportunities. **Response 6.3 -**  **115:** Analy s is of recent DOE and USGS storage resource assessments indicate that twelve states currently have active CO 2 EOR operations and 18 states are within 100 kilometers of active CO 2 EOR locations. To access the existing EOR areas, as well as other potential EO R locations not currentl y utilizing CO 2 EOR, construction of CO 2 pipelines is feasible. Any new EGUs proposed would need to be planned prior to siting and construction and new EGUs have several compliance options including constructing coal fired plants n ear EOR and transporting the electricity via transmission lines, or transporting captured CO 2 to deep saline formations or other non
- EOR sequestration sites. The costs for CCS either with or without EOR are consistent with the D.C. Circuit’s criteria for d etermining that costs are reasonable
. **Comment 6.3 -**  **116:** Commenters 9201, 9472, 9426, 9683, 9666, 9678, 10098 and 10239 asserted that the rulemaking places additional regulatory burdens on an EOR operator that it would not face if it accepted any other CO 2 stream. Commenter 9666 asserted that EOR operators have stated that they

will refuse to accept CO 2 from EGUs under this rule because of the additional regulatory

constraints on EOR operators that the EPA plans to impose. **Response 6.3 -**  **116:** The NSPS establishe s a standard of performance based on a highl y efficient SCPC using partial carbon capture and storage (CCS) as the BSER. Sequestration sites receiving and injecting the captured CO 2 are required to obtain UI C permits and report under subpart RR of the GHGRP. Although the NSPS does not impose regulatory requirements on the transportation pipeline or the sequestration site, such requirements already exist under other regulatory

program s of the Department of Transportation and the EPA. In order to ensure the EGU is compliant with the standard the EPA is reasonably rel yi ng on UI C requirements in combination with the subpart RR requirements to provide secure sequestration of captured CO 2 . **Comment 6.3 -**  **117:** Commenter 9772 expressed concern that federal rules will deter not encourage the use of CO 2 captured b y emissions sources in EOR operation. Commenter 9772 specificall y noted that Subpart RR of the Greenhouse Gas Reporting Rules will allow an emitter to us e EOR
- based storage only where the offsite injector reports the CO 2 storage to the EPA , which would result in an emitter trying to mandate an EPA rule for an EOR operator now onl y subject to Subpart UU of the Greenhouse Gas Reporting Rule. This is a situation that would certainl y lead to EOR avoiding the purchase of CO 2 subject to those rules. Concern about Subpart RR compliance, commingling of purchased and other CO 2 , and rules governing storage would also lead to litigation. **Response 6.3 -**  **117:** The Commenter is concerned that the use of subpart RR will discourage use of anthropogenic CO 2 . The EPA disagrees with this comment in several respects. First, the BSER determination and regulatory impact anal ys is for this rule relies on GS in deep saline6
- 74

formations, not on EOR. Howe ver, the EPA also recognizes the potential for sequestering CO 2 via EOR, but disagrees that subpart RR is prohibitive to the use of EOR. The rule provides requirements for EGUs to verify that CO 2 captured at an affected unit is geologicall y sequestered CO 2 through an arrangement with EOR operators complying with the requirements of Subpart RR of the Greenhouse Gas Reporting Program (40 CFR 98.440 et seq.). This specification limits qualifying geologic sequestration operations onl y to those operations adheri ng to Subpart RR of the Greenhouse Gas Reporting Program and does not apply to EOR operations that do not report under subpart RR
. Subpart RR requires that facilities that conduct geologic sequestration of CO 2 for long
- term containment in subsurface geolog ic formations, regardless of the class of Underground Injection Control permit that they hold, report basic information on the amount of CO 2 received for injection; develop and implement an EPA
- approved monitoring, reporting, and verification (MRV) plan; and report the amount of CO 2 sequestered using a mass balance approach and annual monitoring activities. Reporting under subpart RR will not c hange the status of a Class II well
. See preamble section V.N. 5 .a. **Comment 6.3 -**  **118:** Commenter 8024 also stated that the agency's assumed $20/ton to $40/ton revenue stream from EOR CO 2 sales is inadequate to offset the full costs of CO 2 capture, compression and transport, which is recognized by proposed federal legislation such as S. 3581 (112th Cong., 2d Sess.) **Response 6.3 -**  **118:** The BSER determination and regulatory impact analy sis for this rule relies on GS in deep saline formations, not on EOR . The EPA recognizes that the revenue stream from CO 2 sales to EOR operators does not currently cover all costs associated with CO 2 capture, compression and transport, but does provide a revenue stream to offset some of the costs associated with the implementation of partial CCS . The EPA is assessing c osts conservativel y b y not including any revenues from EOR, even though new plants may well avail themselves of EOR opportunities (e.g. Boundary Dam and Kemper). **Comment 6.3 -**  **119:** Commenters 9201, 9505, 10786, 10087 and 10088 stated that many locations for coal
- fired power plants have no CO 2 pipelines and none proposed, therefore EOR technology

cannot be representative. Commenter 10088 therefore suggested that the cost estimates are inadequate and incomplete, as requiring CCS in locations with no access to EOR will be far mo re costly

than in locations within 50 miles of geology suitable for EOR. Commenter 9487 stated EPA identifies only 13 states with in which carbon dioxide has been used in such formations for EOR and recognizes that EOR will not be "practically available" in all geographic locations. Thus, the commenter contends, meeting the NSPS will not be feasible and sustainable in up to 37 states. According to the commenter, the inability to build new coal
fueled generation in those states will be a function of the fac ility's inability to meet the NSPS itself, and not result from otherwise existing state or local factors (such as air quality or zoning limitations) disallowing an NSPS compliant facility. **Response 6.3 -**  **119:** First, the final standard assumes (conservatively) that captured CO 2 will be sequestered for long
- term containment
. The preamble to the final rule explains our basis for finding that there is ample geologic sequestration capacity available in most parts of the country
. The proposal also notes the possibility (borne out by experience) that captured CO 2 can also be used for EOR in many areas . Thus, geologic sequestration is available in most, of the continental6
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United States
. EOR is available in certain areas, including the areas for which demand can be served b y coal
- fired power plants located in neighboring areas with EOR
. Although there are some areas in which GS is not available, that is not an impediment to our defining BSER to be partial CCS because
-- a. For at least some of those areas, demand in those areas can be serv ed b y coal
- fired power plants built in neighboring areas with GS; b. F or other of those areas, coal
- fired power plants are not being built due to state law restrictions
. In addition, new fossil
- fired EGUs could utilize other compliance alternatives which do not involve sequestration
. In the final rule the EPA identified partial CCS as the BSER and determined that estimated costs are reasonable compared to other options, even without EOR. Many EOR operators have found that pipelines longer than 50 miles are economically feasible in EOR projects. For example, Chaparral Oil recently

constructed a 68 mile pipeline in eastern Oklahoma for its EOR operations in Osage County , Oklahoma. Denbury Resources completed the final section of the 325
- mile Green Pipeline for transporting CO 2 from Donaldsonville, L ouisiana, to EOR oil fields in Texas, and also completed construction and commenced operation of the 232
- mile Greencore Pipeline in 2013. NRG (Petra Nova) has begun construction on a project to capture CO 2 from a pow er plant in Fort Bend County , Texas for transport to EOR sites in Jackson County , Texas through an 82
- mile CO 2 pipeline. These examples demonstrate that the cost of pip eline c o nstruction is not expected to be a constraint on using CO 2 from new power plants affected by this rule. **Comment 6.3 -**  **120:** Commenter 8949 states that EPA should not use the Kemper County facility as a viable example that CCS is BSER. Commenter continues that this facility is onl y commerciall y- viable because of a suite of financial incentives and public subsidies, including revenue from CO 2 sales for EOR. The commenter believes that it is unreasonable for the EPA to expect every

new facility subject to this rule to be able to acquire federal financial assistance and revenue from EOR. Commenter 10048 also states that CCS will only be possible at locations where developers can take advantage of financial incentives **Response 6.3 -**  **120:** Southern Company Mississippi Power Kemper County Energy Facility has reached an advanced stage of construction and is expected to be fully operational in 2016. The advanced stage of the project and agreements for offtake of the CO 2 for EOR demonstrate the availability

of the technology

to perform partial pre - combustion CCS at solid fuel power plants should plants choose to pursue this alternative means of achieving the standard of performance. While some funding for this project was provided by federal assistance the majority was funded privately by the utility . Sales of CO 2 and other products will offset some of the costs of the plant. Subsidies t o support emerging energy generation and pollution control technology are not unusual
. Government subsidies in the form of tax benefits, loan guarantees, low
- cost leases, or direct expenditures have supported development of fossil fuel as well as nuclear, geothermal, wind, and solar energy

development. **Comment 6.3 -**  **121:** Commenters 10036 and 10095 stated that delivery of CO 2 is likely

to be sporadic in quantity

and timing due to constantl y changing electricity demand. Commenter6
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10036 also noted that any issue at the injection site, or along the pipeline, impact would directl y affect the power plant’s ability to operate and to serve its customers while remaining in compliance with the NSPS emission limit. Commenter 8024 expressed concern that the EPA has not addressed the possibility that EOR or carbon sequestration facility operators (who may

be third parties) may

be unable to accept CO 2 from power plants due to operational constraints, even when those plants would be required to continue producing power. **Response 6.3 -**  **121:** See section V. N .3.c of the final rule preamble of the NSPS for the EPA ’s response to this comment. The EPA disagrees with the premise of the comment that CO 2 from an affected EGU must go to either EOR or saline storage, where operational constraints may ca u s e the facility to be unable to accept CO 2 . As described in the preamble, the design of optional saline storage at Boundary Dam shows that captured CO 2 from a fossil
- fired EGU can go to both EOR, and the excess to a deep saline formation
. **Comment 6.3 -**  **122:** Commenters 9513 and 10119 stat ed that the Proposed Rule considered the economic benefits of CO 2 injection for EOR but did not consider the greenhouse gas emissions associated with production, refining, and combustion of additional oil reserves made available through EOR operations that otherwise might not be produced at all. The commenters asserted that the omission not only skews the costs and benefits assessment but may undercut or even eliminate any

emissions reductions achieved by requiring CCS in the first place and undermine the p urpose of the CAA. Commenter 0588 stated that EPA, in assessing emission reductions from the proposed rule, failed to take into account the CO 2 attributable to the oil that is recovered using gas captured at the coal plant and sold to oil companies to enh ance EOR activities. According to the commenter, these emissions
- a direct consequence of the NSPS
- would significantl y undermine the effectiveness of the proposed standard, and could even exceed the mass of the CO 2 "saved" b y partial CCS. The commenter therefore stated that such a standard would be arbitrary and capricious, for "control technologies cannot be "best" if they create greater problems than they solve." The commenter stated that EPA completely fails to take into account the expanded carbon fo otprint of the oil industry caused b y its power plant rule, which is an impermissible omission by

the administrator, because the emissions attributable to EOR are inherent to the NSPS as envisioned by

the administrator, as opposed to being indirect in nature. According to the commenter, in the final rule, she must reasonably account for all CO 2 emissions attributable to the NSPS as envisioned by the EPA. Commenters 5532 and 1612 object strongl y to the use of C C S as a mechanism to extract more fossil fuels f

rom the earth that will, for the most part, be burned for energy and themselves contribute GHG ’ s to the atmosphere. Commenters 5532 and 1612 are also concerned that this policy might indirectl y encourage inadequately regulated oil
- fracking operations and that it will lengthen, not shorten the time before the United States has done its fair share to protect the climate and that emplo yi ng EOR is a form of fuel switching from coal to oil that works against EPA ’ s efforts to reduce carbon pollution, fight climat e change and protect the environment. Commenter 9202 affirms the proposed Carbon Pollution Standards for New Power Plants as a good and essential component of policies to reduce U.S. climate impacts. However, the c ommenter has concerns about allowing the u se of captured CO 2 for enhanced oil and gas6
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recovery and disagrees with the provisions in Section VII. E. 2. (c) that would allow the use of captured CO 2 for EOR. Commenter notes that the purpose of carbon capture and storage is defeated when the "storage" leads directly to the production and combustion of other fossil fuels. The climate impact of that new oil or gas production should be added to the measur ed CO 2 output from the power plant, and considered part of the 1,100 pounds of CO 2 per megawatt - hour. Commenter 10046 noted that substantially more carbon dioxide is emitted from burning this oil than is stored. Commenter 10046 explained that this means th at the EPA 's regulations will actuall y lead to more carbon dioxide emissions than no regulation at all. Commenter 9513 references the study b y the Texas Bureau of Economic Geology that assessed CO 2 leakage at the SACROC field in the Permian Basin based on extensive groundwater sampling, as well as a study by Jaramillo et al. (2009) which looked at SACROC in addition to for other fields, and noted that the study found that the net life cycle GHG emissions for each project, was actuall y larger than the CO 2 in jected and stored in the reservoirs. In particular, the SACROC project had the largest net emissions, exceeding 300 million metric tons of CO 2 e. In its evaluation of the impact of using EOR for CCS, the EPA should consider this and other anal ys es that do n ot draw boundaries that exclude the emissions associated with the full life cycle of power generation and oil production and processing. Commenter 9034 stated that the EPA ’ s BSER analy sis should have taken into account CO 2 emissions generated b y combustio n of the oil recovered, as required b y CAA Section lll. Commenter further stated that the Competitive Enterprise Institute studied this issue and found that if a ty

pical coal plant in compliance with the EPA 's proposed emissions standard sells its captured CO 2 for EOR, it would generate 1.3 million more kilograms of CO 2 emissions per megawatt capacity annually than the plant would "save" using CCS
. Commenter further stated that such a negative cost
- benefit is unreasonable and unacceptable. Commenter 10680 noted that the EPA ’ s proposed rule states that increased supply of anthropogenic CO 2 may

allow for further oil production from “ depleted ” oil fields, and will result in increased emissions, as CCS promotes EOR. Commenter 10680 stated that the rule is fundamentally flawed in that the emissions the EPA wishes to reduce are instead increased as a direct result of the very practices the EPA prescribes to defend partial CCS as BSER. Commenter 10680 noted that new CCS equipped coal
- fired power plants coupled with EOR projects inherently lead to net increases in CO 2 emissions compared to identically

constructed new coal
- fired power plants witho ut CCS systems. Commenter 10680 stated that science indicates that when CCS
- EOR projects are examined in tandem these s ys tems lead to net positive CO 2 emissions. **Response 6.3 -**  **122:** T he EPA reiterates that the BSER determination and regulatory impact anal ys is for this rule re lies on GS in deep saline formations, not on EOR. Some commenters expressed concerns regarding the use of captured CO 2 for CO 2 - EOR on a life
cycle basis. Most of those commenting on this issue reference the work b y Jaramillo et al.6
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(2009) , 9 while other co mments present a back
- of
- the
- envelope anal ys is related to emissions from the combustion of oil
. These commenters are mistaken and EPA has in fact thoroughl y considered these factors in finalizing the rule. T here is m ore recent work by Jaramillo and her col leagues, published in 2013, which has expanded on the 2009 work
. 10 The 2013 study compares the lifecycle GHG emissions from EOR operations using different sources for CO 2 (assuming a 90% capture efficiency at the source in all cases) and to non
- CO 2 - EOR meth ods. The 2013 study also includes a case of coal as a source of CO 2 for EOR based on a reference coal IGCC plant with CO 2 capture. Based on its assumptions, the 2013 study concluded that sources of CO 2 derived from the scenario of coal as a source of CO 2 for EOR result in about 31 % lower net CO 2 emissions per barrel of oil recovered compared to natural
- source CO 2 - EOR. The paper further notes that if even 25% of the CO 2 currentl y used for EOR came from the scenario of coal as a source of CO 2 for EOR instea d of natural CO 2 sources, then approximately 5
- 6 million metric tons of CO 2 e would be avoided and sequestered per ye ar. The EPA also notes that very important in the studies by Jaramillo and her colleagues, as well as other researchers that have investigated this topic, are the assumptions for CO 2 utilization

– the amount of CO 2 needed to recover the incremental oil from CO 2 - EOR

– which then provides the basis for the amount of CO 2 assumed to be stored in the reservoirs from the application of CO 2 - EOR; th e quantity

against which offsetting CO 2 emissions is compared. A study by NETL concluded that, b y far, this was the most important parameter that can impact estimates of net emissions from CO 2 - EOR operations. 11 Most studies use assumptions of CO 2 utilization (and perhaps ultimatel y stored) as a result of CO 2 - EOR that are based on historical CO 2 - EOR operations. Most of these studies assume values for CO 2 utilization on the order of 0.2 metric tons of CO 2 per incremental barrel of oil recovered (Jaramillo assumed values ranging from 0.15 to 0.22). Current EOR operations in the Permian Basin have typical utilization values of 0.4 metric tons of CO 2 per barrel of oil recovered. 12 A lternative assumptions about CO 2 utilization can result in significant increases in the volumes of CO 2 stored per barrel of oil recovery , and result in significantl y greater amounts of CO 2 avoided and sequestered associated with CO 2 - EOR. CO 2 - EOR has been successfully used for decades at many production fields throughout the United States, and is expected to continue for the foreseeable future. The decision to initiate or expand an EOR project is based on the economic viability of the specific project, and driven by

9 Jaramillo, Paulina., W. Michael Griffin, and Sean T. McCoy, S., “Life Cycle Inventory of CO 2 in an Enhanced Oil Recovery System,” Environmental Science and Technology, Vol. 42, No. 21, 2009. 10 Hussain, Daniar, David A. Dzombak, Paulina Jaramillo, and Gregory V. Lowry, “Comparative lifecycle inventory (LCI) of greenhouse gas (GHG) emissions of enhanced oil recovery (EOR) methods using different CO 2 sources, International Journal of Greenhouse Gas Control, Vol. 16 , pp. 129

– 144, 2013. 11 U.S. Department of Energy, National Energy Technology Laboratory, An Assessment of Gate
- to - G ate Environmental Life Cycle Performance of Water
- Alternating
- Gas CO2
- Enhanced Oil Recovery in the Permian Basin, Report No. DOE/NETL
- 2010/1433, September 30, 2010 ( http://www.netl.doe.gov/energy
analyses/pubs/CO2_EOR_LCA_093010.pdf ). 12 National Enhanced Oil Recovery Initiative, Analysis for Carbon Dioxide Enhanced Oil Recovery: A Critical Domestic Energy, Economic, and Environmental Opportunity

– Detailed Methodology and As sum ptions (May 25, 2012), page 6 ( http://neori.org/NEORI%20Methodology%20Brief.pdf ).6
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broad market dy

nami cs. In making a decision, EOR operators consider many cost components of the EOR project including engineering and design, new infrastructure development, electricity, and fuel costs in addition to the long term cost of purchasing CO 2 . These costs are balanced against the long
- term demand for oil and the price EOR owners or operators can receive for the additional oil produced throughout the lifetime of the project. EOR operators will obtain CO 2 from the most cost effective reliable source to make the ir pro ject s viable
. New sources of natural CO 2 are available and awaiting the right market conditions for development. Likewise, many new anthropogenic sources other than EGUs such as gas plants are available to support the oil industry ’s expansion of EOR as mar ket conditions allow. Thus, the industry is not dependent solely on the CO 2 from new EGUs compl yi ng with this rule to g enerate additional oil from EOR. Even if one thinks of CO 2 - EOR’s oil as additive , the amount of oil produced through EOR with captured CO 2 from new EGUs would vary by project but would likely

have a negligible impact on the overall demand for oil, and CO 2 - EOR provides a net GHG emissions benefit compared to non - CO 2 - EOR oil production processes due to the amounts of CO 2 stored with CO 2 - EOR. T he commenter is incorrect in asserting that EOR will encourage additional hydraulic fracturing. Hydraulic fracturing creates preferential high permeability pathways for the produced fluids to flow towards the producing well, and would encourage the channe ling of injected CO 2 though these fractures. EOR projects are designed to create a large uniform front of CO 2 to contact the maximum volume of the reservoir and not flow through preferential pathway s . Furthermore, the commenter has failed to recognize that hydraulic fracturing is regulated by state and federal agencies
. **Comment 6.3 -**  **123:** Commenter 9780 suggested that EGUs should not be held liable for emissions that may

occur during storage or EOR, as this would require EGUs to rely on third
parties to ensure compliance with required operating permits. Commenter 10239 stated that just beca use a company can recover CO 2 does not mean they have a contractual customer or partner willing to purchase the CO 2 . **Response 6.3 -**  **123:** The BSER for the standard is partial CCS, which includes transport of captured CO 2 to an on - site or off
- site repository

reportin g under GH GRP subpart RR
. This is the affected source’s sole obligation regarding sequestration
. However, the EPA is further reasonabl y rel yi ng on the protective requirements for injection wells under the Class VIand II UI C rules, complemented by the monitoring and reporting requirements of the GHGRP, to assure long
- term and safe sequestration
. **Comment 6.3 -**  **124:** Commenter 9666 suggested that extensive time may be required to characterize the storage capability of depleted oil and gas reservoirs for EOR, although likely less than the minimum 5 years cited for saline reservoirs. **Response 6.3 -**  **124:** Because of the long lead times for planning, permitting and constructing a new power plant, the EPA believes the current state of characterization of potential oil and gas fields for CO 2 EOR would not be a barri er to CCS with EOR . The EPA notes that DOE has conducted initial assessments of oil producing states and identified 220 million metric tons of storage capacity in oil and gas reservoirs. DOE has also conducted detailed CO 2 EOR modeling of oil fields in nin e regions of the United States to evaluate the application of “next generation”6
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CO 2 - EOR technologies that would significantly increase the geographic extent and accessibility of CO 2 - EOR operations. **Comment 6.3 -**  **125:** Commenter 9514 noted that although permanent sequestration of CO 2 via EOR is essential for rule's objectives, EOR operations have not historically been designed for this purpose. **Response 6.3 -**  **125:** The EPA reiterates that the BSER determination and regulatory impact anal ys is relies on GS in deep saline formations, not EOR. The EPA agrees that EOR operations have not historicall y been designed specifically for long term storage of CO 2 , but recognizes that CO 2 storage associated with EOR is a common occurrence
. **Comment 6.3 -**  **126:** Commenter 10786 stated that the EPA fails to identify the technical and economic complexities of EOR, let alone analyze and discuss them. Commenter explained that the EPA incorrectly

suggests, without reference or support, that the EOR industry is ready , willing and able to abide by the current CCS regulatory program, as further revised by the NSPS. **Response 6.3 -**  **126:** The EPA is reasonably relying on the existing protective standards for injection wells under the Class VIand II UI C rules, complemented by the monitoring and reporting require ments of the GHGRP
. The “current regulatory

CCS program” for EOR is identical, for the most part, to the status quo before promulgation of the NSPS: EOR operators receiving CO 2 from any source must comply with requirements for Class II injection wells
. The requirement in this rule is reporting and monitoring pursuant to the subpart RR GHG reporting regulations
. The EPA further notes that commenters to the Class VI rulemaking vociferously maintained that Class II operations are well understood, successful an d have a long history of safe operation, so the commenter’s reference here to “technical complexity” is unclear
. See e.g. Comments of Texas Carbon Capture and Sequestration Association (“gas storage is substantially similar to EOR and in those instances any regulations for Class VI should more closel y resemble Class VI”); Comments of British Petroleum (safety of Class II requirements); Comments of U.S. Chamber of Commerce (same); Sandridge Energy

(same). 13 , 14 , 15 , 16 **Comment 6.3 -**  **127:** Commenter 10618 stated that EOR operators are in the business of timely and cost
- effectively

producing hydrocarbons, not pro viding reliable, affordable electricity or playing an integral role in the definition of a best sy stem of emission reductions for another industry . EOR processes operate outside the influence of electricity demand, power prices, or generation outages. EOR operators are part of a larger industry where competition and opportunities for development continue to expand, especiall y with the growth of hydraulic fracking and shale
- gas e xtraction techniques. In other words, if the power industry is able to provide another suppl y of CO 2 to support EOR operations that is cost
- effective, then EOR operators may

be willing use it.

13 See Docket Id No. EPA
- HQ
- OW
- 2008
- 0390
- 0223. 14 See Docket Id No. EPA
- HQ
- OW
- 2008
- 0390
- 0225. 15 See Docket Id No. EPA
- HQ
- OW
- 2008
- 0390
- 0148. 16 See Docket Id No. EPA
- HQ
- OW
- 2008
- 0390
- 0219.6
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**Response 6.3 -**  **127:** DOE
- sponsored studies have shown that one barrier to expanded use of CO 2 EOR is the availability

of CO 2 . 17 The NSPS will increase the availability and geographic distribution of anthropogenic CO 2 for use b y the EOR industry, which will provide additional opportunities for development of EOR fields. The increased avail ability and lower cost from these efforts will provide further cost
- effective supplies of CO 2 to support EOR operations. **Comment 6.3 -**  **128:** Commenter 9735 stated that in addition to technical feasibility , economic feasibility is required for BSER technologies. This has yet t o be demonstrated for CCS. All four of the projects cited b y EPA relied on substantial government support and the anal ys is failed to demonstrate any financial benefit for utility companies or how rates will remain affordable for customers. Commenter 10017 stated that the EPA ” s CCS technology examples also skews affordability

because every

plant uses EOR, which provides a substantial revenue stream to offset the high capital costs and operating costs of CCS. U.S. EPA should not develop a standard based on th e economics relevant to o nly a fraction of the country
. Commenter 10087 suggested that plants wouldn't be economic unless they can sell the CO 2 for enhanced oil recovery
. **Response 6.3 -**  **128:** The EPA reiterates that the BSER determination and regulatory impact anal ys is for thi s rule relies on GS in deep saline formations, not on EOR . The EPA anal yz ed the cost of partial CCS as a BSER as compared to other fossil fuel and non
- fossil fuel options that achieve emissions control , and determined that the cost structure, with and with out EOR, is reasonable as defined b y case law . The EPA notes that under CAA section 111, an emissions standard may

meet the requirements of a “ standard of performance ” even if it cannot be met by every new source in the source category that would have been constructed in the absence of that standard
. **Comment 6.3 -**  **129:** Commenter 10618 stated that in some cases, EOR operators have been economicall y driven to minimize the quantity of CO 2 left underground in favor of reusing the injected CO 2 in other recovery operations. **Response 6.3 -**  **129:** The EPA recognizes that in some cases the economics of a particular EOR project may

minimize the amount of CO 2 left underground. Research b y DOE has shown that increasing the volume of CO 2 used in EOR projects will increase the amount of contact between oil an d CO 2 , and will result in higher oil production. The use of increased CO 2 volumes is one of the advanced technologies DOE considers “next
- generation EOR” that improve the performance of CO 2 EOR floods and result in significant increase in oil production and CO 2 storage . 18 **Comment 6.3 -**  **130:** Commenter 10034 stated that when promulgating rules for oil and gas extraction the EPA should evaluate the effect on EOR use and subsequent demand for captured

17 “I mp roving Domestic Energy Security and Lowering CO 2 Emissions with “Next Generation” CO 2 - Enhanced Oil Recovery”, Advanced Resources International, Inc. (ARI), 2011. Available at: http://www.netl.doe.gov/research/energy
- analysis/publications/details?pub=df02ffba
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CO 2 . Changes in demand for captured CO 2 will affect whether the partial CCS te chnologies prescribed in this rule are actuall y economically viable for new coal
- fired power plants, and whether any further implementation costs will be incurred. The commenter suggested that as the EPA promulgates new regulations related to the extractio n of oil and natural gas using EOR, it should consider the cumulative effect on the incentives provided in this rulemaking. Commenter 9731 encourages the EPA to adopt a holistic approach to ensuring that CCS and the use of CO 2 in EOR operations will be a viable option for controlling GHG emissions and must be mindful of the consequences of other significant regulations including the Underground Injection Control (UIC) Class VIrule and Subpart RR of the GHG reporting rules. **Response 6.3 -**  **130:** The commenter refers to rules go verning oil and gas extraction which are outside the scope of this NSPS . The EPA notes that data from the Oil & Gas Journal Annual EOR survey

has shown a steady

increase in the number of CO 2 EOR projects and the volume of oil produced b y CO 2 EOR over the last 20 years. Such expansion and increased oil production increase the demand for CO 2 . The EPA believes that the Underground Injection Control (UI C) Class VI rule and Subpart RR of the GHG reporting rules offer an integrated and complementary set of regulations that ensure an appropriate level of verification and accounting of CO 2 from EGUs
. **Comment 6.3 -**  **131:** Commenter 7977 stated that if the regulated industry as a whole does not have EOR as a means of reducing costs, CCS cannot be deemed adequately demonstr ated to achieve a standard that may appl y to the industry as a whole. Therefore, the EPA eliminates new opportunities for coal
- fired EGUs in states where EOR is not readily available. **Response 6.3 -**  **131:** As explained in section V.N.6 of the preamble to the final rule, and in the Regulatory

Impact Analysis supporting the final NSPS, the EPA ’s consideration of cost for purposes of determining whether the BSER is adequately demonstrated is based on geologic sequestration of captured CO 2 . We show there that those costs are reason able for new coal
- fired EGUs
. This cost anal ys is is, however, quite conservative
. EOR opportunities should exist for some new sources, which have the leeway to site near EOR wells (e.g. the Boundary Dam EGU in Saskatchewan, or the Kemper facility in Missis sippi, both of which are located proximate to EOR sites, and Boundary Dam is presentl y supplying CO 2 for EOR operations)
. In addition, the final standard is a performance standard which may be achievable without using capture and sequestration
. **Comment 6.3 -**  **132:** Commenter 10786 explained that nowhere in the NSPS does the EPA purport to describe the current commercial make
- up of the EOR industry , which is relativel y small, geographicall y focused in a handful of areas, and composed of a few companies. Commenter noted that the NSPS suggests falsel y that there are many EOR companies dispersed throughout the United States who are poised to purchase and inject NSPS
- compliant CO 2 . Commenter 8501 stated that the presumptions the EPA makes regarding enhanced oil recovery (EOR) as an ancillary

form of partial CCS are not supportable, as there is little discussion of the actual demand of CO 2 for EOR operations or pipeline delivery capability

of the CO 2 to the oil fields. If the demand currently existed and it were economicall y feasible, market forces would dictate greater interest in developing carbon capture projects to meet this demand. It is not6
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apparent this demand has ever materialized or will ever materialize. If, as EPA projects, no one is going to build a coal
- fired plant with CCS for at least ten years, then the EOR market to capture and transport the CO 2 will never develop. **Response 6.3 -**  **132:** The EPA believes that the EOR industry is well established, geographical ly diverse, and is well positioned to expand operations in response to the availability of new sources of CO 2 . DOE has id entified 220 million metric tons of storage capacity in 29 states with oil and gas reservoirs. DOE has identified “next generation CO 2 EOR” technologies that improve the performance of CO 2 EOR floods that will further increase the EOR production by making CO 2 EOR available in reservoirs previously believed to be unsuitable for CO 2 EOR. 19 “Next generation CO 2 EOR” will further expand the ge ographic extent and accessibility of CO 2 - EOR operations in the U.S. DOE sponsored studies have shown that one barrier to expanded use of CO 2 EOR is the limited availability of CO 2 . **Comment 6.3 -**  **133:** Commenter 10786 noted that the optimistic picture of the EOR industry as p otential purchasers of NSPS
- compliant CO 2 in the NSPS conflicts with the comparable assessments of associated storage via CO 2 - EOR in GHG PSD and EIS proceedings. **Response 6.3 -**  **133:** Previous assessments of proposed projects with respect to application of CO 2 capture and trans port were conducted on a site
- specific basis and considered site
- specific factors in the anal ys es . Anal ys es conducted b y FERC and other agencies for the purposes of environmental impact assessments of proposed energy projects are conducted under a different set of criteria than the BSER and BACT analy ses conducted under the CAA. A CAA New Source Performance Standard (NSPS) establishes a “BACT floor” that is to be considered in facility
- specific BACT analy ses conducted under the PSD program
. The definition of BACT in the CAA specifies that “[i]n no event shall application of [BACT] result in emissions of any pollutants which will exceed the emissions allowed by any applicable standard established pursuant to section 111 or 112 of the Act.” Thi s has historically been interpreted to mean that BACT cannot be less stringent than any applicable standard of performance under the NSPS. See e.g. EPA, PSD and Title V Permitting Guidance for Greenhouse Gases, p. 20
- 21 (March 2011). Thus, upon completion of an NSPS, the EPA reads the CAA to mean that the NSPS establishes a “BACT Floor” for PSD permits issued to affected facilities covered b y an NSPS
. **Comment 6.3 -**  **134:** Commenter 10039 noted that EPA ’ s Technical Support Document "Effect of EPAct05 on BSER for New Fossil Fuel
- Fired Boilers and IGCCs" indicates that the studies EPA uses to justify

the technical feasibility

of CO 2 injection and storage have shown that 20% or more of CO 2 used for EOR is no t permanentl y sequestered but is re
- emitted or "produced" with the oil recovered. Consequently the EPA cannot utilize this technology as a justification of the technical feasibility of CO 2 injection and permanent sequestration.

19 “I mp roving Domestic Energy Security and Lowering CO 2 Emissions with “Next Generation” CO 2 - Enhan ced Oil Recovery”, Advanced Resources International, Inc. (ARI), 2011. Available at: http://www.netl.doe.gov/research/energy
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**Response 6.3 -**  **134:** The Technical Support Document referenced b y the commenter provides background information on several EOR projects, but none of the studies cited in the TSD show that 20% or more of the CO 2 used is emitted . Furthermore, CO 2 that is produced and recycled is accounted for and reported as part of the Greenhouse Gas Reporting Program requirements at 40 CFR Part 98 subpart RR
. **Comment 6.3 -**  **135:** Commenter 10039 stated that the studies that the EPA cites are not empirical evidence of the permanence of the sequestration process, but instead estimate the viabi lity of the EOR to store injected CO 2 . The EPA ’ s anal ys is of the CO 2 reduction potential of CCS does not account for the CO 2 emissions that will occur. It is not reasonable for the EPA to claim that EOR is the likely

method for permanent storage of CO 2 but fails to acknowledge that CO 2 from EOR does not actuall y permanently store all of the CO 2 injected. It appears that data is extremely limited on the exact extent to which EOR operations permanentl y sequester CO 2 and use of this technology

as justification of the Best Sy stem of Emission Reduction must preclude any re emission of CO 2 or the reduction potential of the technology is overstated. **Response 6.3 -**  **135:** The EPA has cited several studies that have demonstrated the safe and effective storage of CO 2 in EOR operations. CO 2 has been injected in the SACROC Unit in the Permian basin since 1972 for EOR purposes. A study evaluated a portion of this project, and estimated that the injection operations resulted in final sequestration of about 55 million tons of CO 2 . 20 In a separate study in the SACROC Unit, the Texas Bureau of Economic Geology conducted an extensive groundwater sampling program to look for evidence of CO 2 leakage in the shallow freshwater aquifers. 21 No evidence of leakage was detected. The International Energy Agenc y Greenhouse Gas Programme conducted an extensive monitoring program at the Wey burn oil field in Saskatchewan between 2000 and 2010 (the site receiving CO 2 captured b y the Dakota Gasification sy nfuel plant) . During that time , over 16 million metric tons of CO 2 were safel y sequestered as evidenced b y soil gas survey s, shallow groundwater monitoring, seismic survey s and wellbore integrity testing. An extensive shallow groundwater monitoring program revealed no significant changes in water chemistry that could be attributed to CO 2 storage operations. 22 The International Energy Agency Greenhouse Gas Programme developed a best practices manual for CO 2 monitoring at EOR sites based on the comprehensive analysis of surface and subsurface monitoring methods applied o ver the 10 ye ars. 23 Furthermore, DOE has conducted surface and subsurface monitoring at numerous sites to assess the permanence of injected CO 2 . The studies provide no evidence to suggest that the CO 2 from EOR cannot be permanentl y sequestered
. 20 Han, Weon S., McPherson, B J., Lichtner, P C., and Wang, F P. “Evaluation of CO 2 trapping mechanisms at the SACROC northern platform, Permian basin, Texas, site of 35 years of CO 2 injection.” American Journal of Science 310. (2010): 282
- 324. 21 Romanak, K.D., Smyth, R.C., Yang, C., and Hovorka, S., Detection of anthropogenic CO 2 in dilute groundwater: field observations and geochemical modeling of the Dockum aquifer at the SACROC oilfield, West Texas, USA: presented at the 9th Annual Conference on Carbon Capture & Sequestration, Pittsburgh, PA, May 10
- 13, 2010. GC CC Digital Publication Series #10
- 06. 22 Roston, B., and S. Whittaker (2010), 10+ years of the IEA
- GHG Weyburn
- Midale CO 2 mo nitoring and storage project; success and lessons learned from multiple hydrogeological investigations, to be published in Energy Pro cedia, Elsevier, Proceedings of 10th International Conference on Greenhouse Gas Control Technologies, IEA Greenhouse Gas Programme, Amsterdam, The Netherlands. 23 Hitchon, B. (Editor), 2012, Best Practices for Validating CO 2 Geological Storage: Geoscience P ublishing, p. 353.6
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**Comment 6.3 -**  **136:** Commenter 1 0618 stated that EPA is naive in assuming that the EOR experience to date could readil y accommodate the requirement to install CCS technologies on fossil
- fuel based generating units. Commenter referenced excerpts from the July 2010 PNNL
19557 report entitl ed " CO 2 - driven Enhanced Oil Recovery as a Stepping Stone to What?" by Dooley , et.al. of the Pacific Northwest National Laboratory , which detailed the reasons that CO 2

- EOR and CCS is not a viable option. Commenter 10618 stated the viability of opportuniti es for use of CO 2 - EOR faces many challenges, including those associated with the validation and accounting for CO 2 storage permanence. Current and past EOR practices have not been required to demonstrate permanent CO 2 storage. **Response 6.3 -**  **136:** Experience from over 40 year s of CO 2 EOR provides an extensive history that demonstrates the availability of technologies required for geologic sequestration of CO 2 captured from fossil fuel based generating units. The commenter refers to the anal ys is conducted by Dooley et al., but incorrectl y summarizes the conclusion of the paper which is that CO 2 EOR offers an opportunity

to jumpstart climate change mitigation motivated CCS deploy ment, but is unlikely to be a major or mandatory step to large
- scale CCS deploy ment. The determination that the BSER is adequatel y demonstrated and the regulatory impact anal ys is for this rule relies on GS in deep saline formations. However, the EPA also recognizes the potential for sequestering CO 2 via EOR and allows the use of EOR as a compliance option (provided the EOR site complies with the subpart RR reporting and monitoring rules). The BSER determination and regulatory

impact anal ys is for this rule relies on GS in deep saline formations, not o n EOR. **Comment 6.3 -**  **137:** Commenters 5532 and 1612 expressed objection to the inclusion of enhanced oil
- recovery

(EOR) in the ty

pes of carbon capture and storage (CCS) that the proposed standard promotes, even if it stimulates technology development. Commenters 5532 and 161 2 do not dispute the science of carbon capture and storage, but are dubious of many of its proponents’ claims with respect to the permanence and efficacy of such storage. Commenters 5532 and 1612 support carbon capture in cement or calcium carbonate, but n ot for additional petroleum extraction. **Response 6.3 -**  **137:** T he EPA is reasonably relying on the already- adopted, and very rigorous, Class VIwell requirements in combination with the subpart RR requirements to provide secure sequestration of captured CO 2 . The commenters ’ su pport for CO 2 storage technologies other than geologic sequestration is noted, however from a practical perspective these technologies are not sufficiently

advanced that the EPA is prepared to unquali fiedly structure this final rule to allow for their use, nor are there plenary s ys tems of regulatory

control and GHG reporting for these approaches, as there are for geologic sequestration
. Nonetheless, as stated above, these technologies not only

show promise, but could potentially be demonstrated to show perm anent storage of CO 2 . The EPA is establishing a mechanism in this final rule to provide for a case
- by
case adjudication by

the EPA of applications seeking to demonstrate to the EPA that a non
geologic sequestration technology would result in permanent conf inement of captured CO 2 from an affected EGU. **Comment 6.3 -**  **138:** Commenter 10137 recommended that the EPA adopt a NSPS that includes provision for using CCS, and that the Agency modify its proposal to allow EGU operators to direct captured CO 2 streams to EOR operators who co mply with subpart W and subpart UU reporting. Commenter noted that this has been successfully implemented by

the agency

and the6
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reporting community

for several years, and imposes no new mandatory requirement on the EOR operator. Commenter 10137 stated that emissions reported under subpart W can be subtracted proportionatel y from total CO 2 received from the EGU source, which must report the total CO 2 sent under subpart PP. Taking this approach would allow for EOR operators to incorporate supplies of anthropo genic CO 2 into the supply portfolio if, as, and when such anthropogenic CO 2 may become available. However, Commenter noted that the Commenter is not suggesting that using subpart W and UU reporting could make the proposed rule workable, because there are m any additional areas that need to be addressed, and the proposal as a whole is a barrier to CCS development. **Response 6.3 -**  **138:** Under subpart UU of the GHGRP, all EOR operators who inject CO 2 are required to report onl y basic information including the amount of CO 2 received. Under subpart W of the GHGRP, onshore oil and gas producers who meet certain criteria are required to report CO 2 , CH 4 and N2 O emissions for specified sources at basin
- level facilities. While these reporting requirements help provide an understanding of CO 2 received for injection and petroleum and natural gas s ys tem GHG emissions , neither provide verification of geologic sequestration of CO 2 . The reporting and monitoring required under subpart RR of the GHGRP is necessary and helps to provide a nationally uniform and practical methodology to provide assurance of long
term storage . **Comment 6.3 -**  **139:** Commenter 10043 noted that the oil industry captures relativel y small amounts of CO 2 to help move oil and gas more effectivel y, that fact says little if anything about the viabili ty

and adequate demonstration of CCS on the scale and in the locations that would be required for large coal
- fired generating units. In addition, the commenter states that the EOR industry does not have the requisite experience with and technical knowledge of long
- term CO 2 sequestration. The EOR industry stores CO 2 gas for short periods of time, and then transports it by pipeline for use at the next oil and gas recovery site, but the Proposed Rule would require permanent sequestration of CO 2 in massive quantities. **Response 6.3 -**  **139:** The oil industry has successfully

employed CO 2 EOR for more than 40 ye ars and currently

uses m ore than 72 million metric ton s per year of CO 2 for EOR. DOE has determined that using today ’s technology , expanded EOR would demand and store approximate ly

9 billion metric tons of CO 2 . 24 This number increases significantly if advanced EOR technologies are employed. While some of the CO 2 injected may be available for removal, a large portion may

be dissolved in formation fluids or immobile because it is res idually trapped in small pores. The dissolved and immobile CO 2 is permanentl y sequestered. **Comment 6.3 -**  **140:** Commenter 9657 noted that the EPA assumes CCS will be viable based on EOR revenue, and assumes that costs for EOR are uniform throughout the U.S. Commenters 9657, and 9734 and 10105 noted CCS can only be viable for plants near areas geologicall y suitable for EOR, which are located within sufficient proximity to pipelines that could transport the captured CO 2 to EOR operations. Commenter 9734 explained that the EPA rationalizes that
24 “I mp roving Domestic Energy Security and Lowering CO 2 Emissions with “Next Generation” CO 2 - Enhanced Oil Recovery”, Advanced Resources International, Inc. (ARI), 2011. Available at: http://www.netl.doe.gov/research/energy
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locations where EOR is not economical are limited due to other legal or practical limits on building coal
- fired power plants, such as high reserve margins and large renewable energy targets. This assumption is not correct. There are numerous areas throughout the country where constructing new coal
- fired power plants would be economical, but for the need to compl y with EPA rules. In these areas, technical and regulatory uncertainty regarding underground sequestration makes CCS infeasible. **Response 6.3 -**  **140:** The commenter is mistaken that the EPA assumes CCS will be viable based on EOR revenue. As explained in section V.N.6 of the pre amble to the final rule, and in the Regulatory

Impact Analysis supporting the final NSPS, the EPA ’s consideration of cost for purposes of determining whether the BSER is adequately demonstrated is based on geologic sequestration of captured CO 2 in deep sal ine formations, not EOR. The Regulatory Impact Analy sis does not assume that EOR costs are uniform throughout the US. The EPA included an anal ys is with a “low EOR” case and a “high EOR” case. New EGUs could be located near EOR or deep saline formation site s or transport CO 2 to the sites via CO 2 pipelines. Alternativel y new EGUs could be located closer to sequestration sites and provide electric power to customers through transmission lines
. The demonstration of carbon dioxide capture, transport and storage at multiple sites has been presented in the preamble. **Comment 6.3 -**  **141:** Commenter 9513 noted that while permanent sequestration may be feasible in formations used for EOR, the performance of the oil and gas sector in fracking activities over the past few ye ars and the BP M acondo oil well blowout do not provide a basis for a high degree of confidence that what may be feasible will actually

occur in practice. **Response 6.3 -**  **141:** As noted in preamble section V.N, the already- adopted, and very rigorous, Class VIwell requirements in combination wi th the subpart RR requirements provide secure sequestration of captured CO 2 . **Comment 6.3 -**  **142:** Commenter 9772 explained that economists at the University of Wyoming employed a method for predicting oil flows for a given reservoir and determined not all fields are suitable for EOR. Lithology , area, thickness, porosity and permeability

can all affect a reservoir ’ s viability . Higher oil prices and lower CO 2 prices can also determine whether or not a reservoir will be economically viable for EOR, along with geologic, infrastruc ture and economic factors. Instead of rel yi ng on revenue to offset the costs of CO 2 capture, EGUs will be required to add significant costs for transport and non
- EOR permanent storage. Costs could range from $1 to $10 per ton for transport and $.5 to $10 p er ton for permanent storage. **Response 6.3 -**  **142:** The EPA considers the costs of partial CCS at a level to meet the final standard of performance to be reasonable even without considering opportunities to further reduce implementation and compliance costs. We did not in the p roposal

– and we do not here in this final action

– rel y on any cost reduction opportunities to justify the costs of meeting the standard as reasonable, but again note the conservative assumptions embodied in our assessment of compliance costs. **Comment 6.3 -**  **143:** Commenter 9 472 provided a comment letter from the related rule "Draft Underground Injection Control (UI C) Program Guidance on Transitioning Class II Wells to Class VIWells, EPA
- 816
- P
- 13
- 004 (Draft Guidance)" and noted that, in light of the CAA6
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stationary source regu latory

programs in which CCS is playing a role, if the Draft Guidance does not meet the needs of the CO 2 - EOR industry , it also fails to meet the needs of the electricity generators that may

be required to rel y on EOR operators to compl y with their CAA obli gations. Commenter 9472 encourages the EPA to work with the CO 2 - EOR industry to create a certain regulatory

framework that ensures its ability to enter into long
- term CO 2 offtake contracts with CAA
- regulated EGUs that preserves existing CO 2 - EOR commercial operations and will provide the EPA with the human health and environmental protections that it is seeking. **Response 6.3 -**  **143:** See preamble section V. N .6 and the Section 6.3 topic titled Geologic Sequestration for a response to this comment. Injection of anthropogenic CO 2 into Class II wells does not force transition of these wells to Class VI wells

– not during the well’s active operation and not when EOR operations cease. We recognize the widespread use of EOR and the expectation that injected CO 2 can remain underground and not endanger USDWs
. **Comment 6.3 -**  **144:** Commenter 9195 stated that under the law, the advice of scientific experts is a pre - requisite, not an afterthought. Specificall y, the Environmental Research, Development, and Demonstration Authorization Act of 1978 (ERDDAA) establis hes the Science Advisory Board (SAB) as an independent body charged with providing advice to Congress and the EPA. Commenter qu estions the EPA, How, when, and in what manner has the Agency considered the advice of the SAB? Commenter 9195 further stated familiarity with the communications between the Science Advisory Board and the Administrator as well as the meetings held in December 2013 and January 2014 addressing CCS. Commenter also stated that the EPA staff who spoke on your behalf at the December 4
- 5, 2013 meeting said that looking at sequestration was outside their statutory obligation since other EPA programs would handle the storage or sequestration of the C02. Commenter asks following questions to the EPA: d. How can the Agency

both rely on the benefits of EOR sales for making a CCS system less expensive, and incorporate new storage requirements in the rule (Subpart RR) while simultaneously

denyi ng that CCS includes the storage half of the s ys tem? Commenter 9195 asks following questions to the EPA: a. Would you agree that the ability to do either EOR or geologic sequestration are very site specific, and many states and regions will simply not have EOR or sequestration options? b. Do yo u think this rule will put specific states and regions at a competitive disadvantage in terms of compliance? Commenter 10786 asserted that NSPS is inconsistent with State laws and regulations governing EOR generall y, Class II primacy, and associated long
- term storage via CO 2 - EOR. The commenter further stated that NS PS purports to preempt these State enactments without reliance on or citation to any

Federal law or regulation that authorizes such preemption. **Response 6.3 -**  **144:** When the Science Advisory Board (SAB) and its workgroups raise questions, the EPA takes them seriously . We use the SAB’s routine, transparent, and well
established processes to better understand the nature of the questions and how we can address6
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them. An SAB workgroup asked for information on the potential adverse impacts of carbon capture and sequestration (CCS) in November 2013 and how that issue is addressed in the proposed Carbon Pollution Standards. The SAB workgroup also asked about the adequacy of peer review of U.S. Department of Energy (DOE) National Energy

Technology

L aboratory (NETL) studies, which the EPA relied on to develop cost estimates for carbon capture technology

in the proposed rule. The SAB’s transparent, deliberative process provided an opportunity

for us to engage in a dialogue to better understand the workgroup’s concerns and to provide a clear er explanation of the scope of the proposed rule. The EPA clarified that we are not proposing to set any new requirements related to sequestration in this rule and thus, this rule does not include any new analysis related to such requirements. The EPA also provided some additional information on the basis of the DOE NETLcost studies that the EPA used in developing the proposed rule and the peer review process followed b y DOE NETL for that study. The DOE’s robust process included outside input from knowledg eable stakeholders including industry , academia and government experts in the design of the study and a peer review of the final report b y a wide range of similar experts. While the EPA did not conduct additional peer review of these studies, the different levels of multi
- stakeholder technical input and final review meet the requirements to support the anal ys es as defined b y the EPA Peer Review Handbook
. After consideration of the clarifying information and thorough discussion about the issues during several meetings of the SAB that were open to the public, the workgroup recommended to the full SAB that additional review of the science of sequestration was not necessary in the proposed Carbon Pollution Standard. The full SAB agreed with the workgroup’s assessment that the EPA relied on existing requirements for sequestration in the Carbon Pollution Standards and that peer review of the DOE cost studies was sufficient. In a memo dated January 29, 2014, the SAB informed the EPA that it will not undertake further review of the science supporting this action
. See also response 2.4.2 below dealing with comments regarding the Data Quality Act. The EPA is reasonably

relying on the alre ady- adopted, and very rigorous, Class VIwell requirements in combination with the subpart RR requirements to provide secure sequestration of captured CO 2 . In developing the Class VI rules, the EPA engaged with the SAB, providing detailed information on key issues relating to geologic sequestration

—including monitoring schemes; methods to predict and verify capacity , injectivity , and effectiveness of subsurface CO 2 storage; and characterization and management of risks associated with plume migration and pressure increases in the subsurface. See: http://yosemite.epa.gov/sab/sabproduct.nsf/0/AD 09B42B75D9E36D85257704004882CF?Open Document . In addition, the EPA developed a peer reviewed Vulnerability Evaluation Framework, which served as a technical support document for both the Class VIand Subpart RR rules. See: http://www.epa.gov/climatechange/Downloads/ghgemissions/VEF
Technical_Document_072408.pdf
. Certain regions of the U.S. have more favorable geology for EOR or saline storage of CO 2 , how ever the EPA notes that DOE and USGS resource assessments have identified 39 states that have either saline storage or EOR storage opportunities. Many of the states that do not have storage access are unlikely to see new coal fired power plants because the re is no need for the additional power, or there are other preferred power options that can meet the performance standard . The EPA believes that the rule offers a wide range of options that allow states considerable flexibility

to comply

with the rule with out creating an economic disadvantage.6
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UI C Class II wells are typically, but not exclusively regulated b y the states. Nothing in the NSPS rule preempts the states’ Underground Injection Control Program primacy in issuing Class II permits. Specificall y, rep orting under subpart RR does not preempt the Class II permit issued b y the states
. See preamble section V.N. 5 .a. **Comment 6.3 -**  **145:** Commenter 10029 stated that the proposal reflects the EPA ’ s assessment that it is unlikely

an y CO 2 reuse technology would, in the foreseeable future, be able to accommodate all of the CO 2 captured b y an affected EGU. Commenter further stated that whether or not this assessment is correct, it is relevant only to identifying the BSER that is available fo r the purpose of establishing a corresponding performance standard. Commenter further stated that once the EPA establishes a performance standard (i.e., an emission limit), it is the responsibility

of the affected EGU to determine how to achieve it. Commenter also stated that nothing in Section 111 of the CAA prohibits an affected EGU from using more than one technology

to achieve a standard, and an affected EGU should be permitted to incorporate a beneficial reuse technology as part of a sy stem designed to meet the CO 2 emission limit. Commenter stated an example, an affected EGU should be permitted to sell some portion captured CO 2 for reuse in the creation of an advanced biofuel, while transporting the balance of captured CO 2 in a pipeline to an oil field for use in enhanced oil recovery (EOR) or disposal through geologic sequestration. Commenter stated that the proposal impermissibly forecloses this and all other options that are otherwise available to affected EGUs. Commenter 10029 stated that under the E PA ’ s proposal, no technology could be used to achieve CO 2 reductions until it has been individually authorized by the EPA through a rulemaking. Commenter further stated that this would have a disastrously chilling effect on the development of CO 2 reuse tec hnology

and set a dangerous precedent for government interference into and control over private commercial decisions, not only regarding CO 2 controls on affected EGUs, but for all air pollutants and all source categories subject to regulation under Section 111. Commenter requested that the proposal be revised to comply with the CAA and allow reuse technologies to be used by affected EGUs, alone or in combination with other technologies to achieve the proposed CO 2 emission limit. **Response 6.3 -**  **145:** The commenter is correct that a BSER determination does not mandate that compliance utilize that technology , or indeed, utilize any specific technology
. A source must achieve the numerical level of the standard of performance
. Nor does anything in s ection 111 of the CAA prohibit an a ffected EGU from using more than one technology to achieve a standard. For example, some facilities may choose to use both saline and EOR options, as SaskPower did with the Boundary

Dam EGU. To address the issue of using multiple technologies to meet the s tandard, the EPA is establishing a mechanism for alternative sequestration technology in this final rule
. The rule provides for a case
- by
- case adjudication by the EPA of applications seeking to demonstrate to the EPA that a non
- geologic sequestration techn ology would result in permanent confinement of captured CO 2 from an affected EGU
. The EPA disagrees with the Commenter that the rule will have a “disastrousl y chilling effect on the development of CO 2 reuse”. The availability

of new supplies of anthropoge nic CO 2 in geographically diverse areas will enhance the opportunity for EOR and other reuses. **Comment 6.3 -**  **146:** Commenters (10662 and 10952) stated that the EPA ’ s proposal does not demonstrate compliance with Section 321 of the CAA, which gives the agency an affirmative6
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duty to perform continuing evaluation of potential loss or shifts of employment which may result from the administration or enforcement of the CAA or its regulatory framework. Commenters 10662 and 10952 stated that the proposed standards will give some states a competitive advantage over other states in attracting industry , as the geological features necessary for EOR and sequestration are not evenl y distributed throughout the country. Commenter also stated that the proposed regulation will have significantly disparate geographic impacts. Commenter 10662 stated that the EPA must also consider increased fuel transportation costs and increased electricity transmission costs incurred b y locating EGU facilities close to geological formations favorable to CCS. **Response 6.3 -**  **146:** Wh ile current locations of EOR are not evenl y distributed throughout the country , much of the U.S. has access to either existing EOR sites or oil and gas production that is amenable to EOR. Analysis of recent DOE storage resource assessments indicate that th ere are 39 states for which onshore and offshore deep saline formation storage capacity has been identified
. EOR operations are currentl y being conducted in 12 states. An additional 17 states have geology

that is amenable to EOR operations. There are 10 st ates with operating CO 2 pipelines and 23 states that are within 150 miles of an active EOR location. A few states do not have geologic conditions suitable for GS, or may not be located in proximity to these areas. However, in some cases, demand in those st ates can be served b y coal
- fired power plants located in areas suitable for GS, and in other cases, coal
- fired power plants are unlikely to be built in those areas for other reasons, such as the lack of available coal or state law restrictions
. Therefore the EPA does not anticipate that proximity to existing EOR operations will represent a competitive advantage in attracting new industry . The EPA has conducted the cost anal ys is in accordance with applicable regulations and case law and determined that the c ost structure is consistent with the D.C. Circuit’s criteria for determining that costs are reasonable. **Comment 6.3 -**  **147:** Commenter 10664 stated that the proposal is inconsistent with waste management options that the EPA endorses for other air, water and waste regulations by favoring disposal of CO 2 rather than recycling or reuse. The commenter recommended that the EPA embrace beneficial reuse as a first resort and choose disposal, or permanent storage, as a last resort. Commenter 9472 stated that existing power plants face a number of site
- and plant
- specific limitations to participating in a CCS demonstration project, including available surface space on site to construct and integrate a carbon capture unit, proximity to existing pipeline infrastructure to sell CO 2 into an EOR facility, suitable local storage geology if EOR is not available or cost effective, the extent of conventional air pollution control and the remaining useful life of the plant. Commenter 10786 stated that EOR operators are unlikely to purchase or inject CO 2 from CCS, unlikely to assume infinite climate stewardship responsibilities as it is inconsistent with law and business practices. The commenter asserted that operators may demand to be compensated rather than paying for the CO 2 , and that no operator will agree to a complete restructuring of its business for what the commenter estimates as a 5 percent increase in CO 2 supply
. Commenter 9426 stated that no effort has been made to investigate whether the price of captured CO 2 in an EOR application wo uld overcome the increased costs associated with transporting the CO 2 long distances
.6
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**Response 6.3 -**  **147:** Today ’s rule is not inconsistent with other EPA actions related to waste
. Although the determination that the BSER is adequately demonstrated and the regulatory impact anal ys is for this rule relies on GS in deep saline formations, the EPA also recognizes the potential for securel y sequestering CO 2 via EOR . The EPA recognizes that ty pes of CO 2 storage technologies other than geologic sequestration are under development (e.g. precipitate d calcium carbonate) and some are currentl y in commercial scale operation. The final rule also does not foreclose reuse or other recycling options (other than EOR, itself a form of recycling), but rather provides for a case
- by
- case adjudication b y the EPA of applications seeking to demonstrate storage methodologies of efficacy equal to (or surpassing) geologic sequestration. The EPA also does not acc ept the comment that subpart RR reporting will dissuade EOR operators from accepting CO 2 from an affected source
. The cost of compliance with subpart RR is not significant enough to offset the potential revenue for the EOR operator from the sale of produce d oil for CCS projects that are reliant on EOR. First, the costs associated with subpart RR are relativel y modest, especiall y in comparison with revenues from an EOR field. In the economic impact analy sis for subpart RR, the EPA estimated that an EOR proje ct with a Class II permit would incur a first year cost of up to $147,030 to develop an MRV plan, and an annual cost of $27,787 to maintain the plan; the EPA estimated annual reporting and recordkeeping costs at $13,262 per ye ar. 25 Monitoring costs are esti mated to range from $0.02 per metric ton (base case scenario) to approximately $2 per metric ton of CO 2 (high scenario). Using a range of scenarios (that included high end estimates), these s ubpart RR costs are approximately three to four percent of estimated revenues for an average EOR field, indicating that the costs can readily be absorbed. 75 FR 75073. Furthermore, there is a demand for new CO 2 by EOR operators, even beyond current natural sources of CO 2
. For example, in an April 2014 study , DOE conclu ded that future development of EOR will need to rel y on captured CO 2 . 26 Thus, the argument that EOR operators will obtain CO 2 from other sources without triggering subpart RR responsibilities, which assumes adequate supplies of CO 2 from other sources, lacks foundation. In addition, the Internal Revenue Code section 45Q provides a tax credit for CO 2 sequestration which is far greater than subpart RR costs. 27 Section 45Q(a)(1) allows a credit of $20 per metric ton of qualified CO 2 that is captured b y the taxpayer at a qualified facility , disposed of by the taxpayer in secure geological storage, and not used by the taxpayer as a tertiary injectant. Section 45Q(a)(2) allows a credit of $10 per metric ton of qualified CO 2 that is captured by the taxpayer at a qualified facility , used by the taxpayer as a tertiary injectant in a qualified enhanced oil or natural gas recovery

project, and disposed of b y the taxpayer in secure geological storage. The section 45Q credit for calendar ye ar 2015 is $21.85 per metric ton of qualified CO 2 under § 45Q(a)(1) and $10.92 per metric ton of qualified CO 2 under section 45Q(a)(2). In sum, the cost of complyingwith subpart RR requirements, including the cost of MRV, is not significant enough to deter EOR operators from purchasing EGU captured CO 2 .
25 Subpart RR costs are presented in 2008 US dollars. 26 “Near Term Projections of CO 2 Utilization for Enhanced Oil Recovery”. DOE/NETL
- 2014/1648. April 2014. 27 http://www.irs.gov/irb/2009
- 44_IRB/ar11.html and http://www.irs.gov/irb/2015
- 26_IRB/ar14.html
.6
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**Comment 6.3 -**  **148:** Commenters 9201, 9472, 9426, 9683, 9666, 9678, 10098 and 10239 asserted that willing operators reporting under Subpart RR could be construed as intent to conduct geologic storage, creating a risk that a well operator could become subject to more onerous permitting requirements under Class VI of the UIC program. **Response 6.3 -**  **148:** An EOR project reporting un der Subpart RR may be permitted as UIC Class II
. Reporting under Subpart RR does not cause an EOR project to be permitted as UIC Class VI. **Comment 6.3 -**  **149:** Commenter 8032 stated that the issue of what to do with the captured CO 2 is far from resolved. Commenter 6962 stated that is it not necessary to capture and permanentl y store CO 2 emissions and that is it necessary

to capture, fix and manage CO 2 emissions. The commenter further states that an Air Emission Recycling (AER) s ys tem utilizing the Calvin Cycle can accomplish th is goal
. **Response 6.3 -**  **149:** See sections V.M and N of the final rule preamble. **Comment 6.3 -**  **150:** Commenter 4711 stated that compressed air energy storage ( CAES) can represent a cost - effective grid
- level storage technology that is able to be used in many parts of the US. **Response 6.3 -**  **150:** The final rule establishes a case
- by
- case mechanism whereby the EPA can approve alternative storage methods for CO 2 that an applicant demonstrates are as effective as geologic sequestration. 

### 6. **3 .5**  **CO 2**  

### Transport and Geologic Sequestration Legal and Regulato **ry Issues Geologic Sequestration Property Rights**  **Comment 6.3 -**  **151:** Commenter 10023 stated that CO 2 storage raises numerous permitting and regulatory

issues, including property rights for subsurface storage
. Commenters 9407 and 10952 stated that the proposal and supporting information in the rulemaking docket lacks information that the EPA has considered key legal issues that need resolution, such as property rights. Commenter 10952 references the administration's task force report on CCS projects as previously

identified co ncerns that should be addressed. Commenters 9425, 9426, and 9666 stated the legal mechanisms for securing property rights for subsurface storage of supercritical CO 2 may be unclear or ineffective in many states, leading to unforeseen costs and delay s . Comm enter 9666 stated that subsurface property rights include subsurface mineral rights as well as pore space ownership, and although some states have enacted laws to clarify

pore space ownership, most have not, and without such clarification CCS cannot be und ertaken
. Commenter 9683 stated that the proposed rule gives virtually no consideration to property rights barriers attendant to CCS and describes the need to obtain subsurface rights as the most complex property rights issue facing geologic storage
. Sim ilarly , Commenters 9423, 9597, and 102396
- 94

asserted that CCS is challenged b y legal issues such as pore space ownership
. Commenters 9423 and 10239 stated that there are unanswered questions regarding ownership of underground pore space . Commenters 10036 and 10618 described various questions related to pore space ownership and use as key regulatory and legal barriers that pose very significant barriers to the feasibility and adequate demonstration of CCS
. Commenters 6948 and 9666 stated that in most states th e property rights needed for subsurface storage of CO 2 are not clearl y defined and no streamlined procedure for acquiring pore space has been developed
. Specifically , Commenters 6948 and 9666 stated that 5 states have addressed what property rights must be secured for geologic storage of CO 2 , and onl y 7 have developed any streamlined procedures for acquiring pore space. **Response 6.3 -**  **151:** The EPA notes that issues of individual property rights will involve site
specific resolution if and when they arise in particular proceedings
. These issues have not proved impediments to the Class VI projects pursuing GS , as illustrated by the cases of Archer Daniels Midland and FutureGen
. The EPA cost estimates for this rule include costs for acquiring both surface land and sub
- surface property rights ( “pore acquisition ” ). **Comment 6.3 -**  **152:** Commenter 9666 stated that many geological formations suitable for CCS cross political jurisdictions and may involve multiple cities, counties, and states, each with their own requirements
. Similarly , Commenter 9425 an d 10239 cited concerns over potential differences in laws in multiple jurisdictions. Commenter 10243 recommended that because geologic formations for storage extend beyond state lines, a uniform national policy should be adopted, as opposed to a state by s tate patchwork of rules, to help projects move forward once CCS is technologically and economically

feasible. **Response 6.3 -**  **152:** This comment is beyond the scope of this proceeding, but the EPA again notes that resolution of cross
- boundary issues is not a necessary

pre - condi tion to issuance of Class VIpermits
. The EPA notes that 40 CFR 146.82(b) of the UI C Class VI regulations specifies that the UI C Director shall notify an y States, Tribes, or Territories within the area of review of a Class VI project based on information p rovided in the permit application and per state UI C requirements. These issues have not proved impediments to the Class VI projects pursuing GS , as evidenced by the cases of Archer Daniels Midland and FutureGen . Furthermore, EOR with anthropogenic CO 2 like wise has been conducted successfully for decades without such issues proving an insurmountable obstacle
. In addition, of course, there are compliance alternatives to the promulgated standards that do not involve sequestration, so that the standard can be s atisfied in any

case in all areas. **Comment 6.3 -**  **153:** Commenter 9666 stated that CO 2 repositories must be extensive and due to their size could infringe on existing mineral, water, and private property rights (both surface and subsurface)
. Similarly , Commenter 9423 raised co ncern for the private property rights of owners of the surface lands above the injected CO 2 plume
. Commenter 9666 asserted that not all states clearly specify surface vs. subsurface property rights, which will lead to conflicts of interest and potential litigation. The commenter noted that it is not uncommon outside the eastern U.S. for subsurface and surface rights to be separated
. The commenter stated there is precedent regarding surface vs. subsurface ownership rights for6
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wastewater injection where operators of wastewater wells have been held accountable for “ trespass ” of injected wastes into subsurface properties owned by others, for which rights had not been acquired. Commenter 9666 stated that regional land use controls could be used to ban large
- scale CCS projects near valuable natural resources, presenting obstacles to implementing projects in otherwise viable locations. **Response 6.3 -**  **153:** The EPA notes that issues of individual property rights will involve site
specific resolution if and when they arise in particular proceedings
. These issues have not proved impediments to the Class VI projects pursuing GS, as evidenced by the cases of Archer Daniels Midland and FutureGen. **Comment 6.3 -**  **154:** Commenter 9683 noted that scale
- up presents complex issues for the storage of CO 2 . For example, storage of tens of millions of tons of CO 2 in a saline or other non
- EOR formation requires aggregation of property rights across a broad area potentially encompassing not only areas to which the CO 2 may migrate, but areas into which brines and other materials displaced b y CO 2 injections may reach. Commenter 9666 stated a critical complication is that subsurface lands with the desired pore space can be privatel y owned, and CO 2 injection can impact owners in multiple states
. Comm enter 9666 stated that compulsory unitization laws and eminent domain laws have been used to secure access to oil and gas fields from multiple owners, but these laws may be inadequate for CO 2 injection. According to the commenter, the key to success is the ability

to predict whether injected CO 2 will remain in the subsurface property or migrate laterally to other properties and further research is needed to improve the ability to predict and monitor the movement of CO 2 plumes from injection sites beyond present capabilities. **Response 6.3 -**  **154:** This comment is beyond the scope of this proceeding, but the EPA again notes that these issues have not proved impediments to the Class VIprojects pursuing GS, as evidenced b y the cases of Archer Daniels Midland and FutureGen
. The EP A agrees with the commenter’s assertion that the ability to predict whether injected CO 2 will remain in the subsurface is key to the success of CCS . The EPA Class VI regulations require that, prior to receiving a permit, a Class VI permit applicant develop and submit to the UI C Program computational models that predict the plume movement based on results of the thorough site characterization process. The Class VI rule also requires regular monitoring of the plume and pressure front during the injection peri od to determine if the behavior is consistent with model predictions
. I f the model ed results do not accuratel y reflect the actual conditions based on operational and monitoring information, the model must be revised . The EPA believes that the modeling and monitoring tools currently available provide the necessary level of information to ensure the safe and secure long
- term storage of CO 2 . **Comment 6.3 -**  **155:** Commenter 10098 and 10239 stated that if sequestration were permitted on federal land, it is not clear whether the federal government would charge companies rent for storage. According to the commenter, the proposed rule does not attempt to deal with this issue, and, even if it did, the EPA ’ s options are limited. The commenter stated that this issue is one of federal l and use law, which is outside of the EPA 's purview and it is not expected that the6
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concern would be resolved within any reasonable timeframe
. Commenter 10239 concluded that while these and other critical issues are largel y outside of the EPA's jurisdiction and control, it is nevertheless arbitrary

and capricious for the EPA to simply ignore them when assessing whether geologic storage is currently available. **Response 6.3 -**  **155:** D etermining rental rates for use of federal lands is outside of the EPA ’s authority and beyond the s cope of this rule . The EPA has included land and other property acquisition costs in its cost estimates for the rule . The EPA notes further that Class VIpermits have been issued b y the EPA, again indicating that land use issues have proved surmountable in practice. **CO 2**  **Transport Legal and Regulatory Issues Comment 6.3**  **- 156:**  Commenters 8022, 9382, 9426, 9666, 9780, 10239, and 10098 noted that CO 2 pipeline siting is subject to the laws of individual states, and that involvement of multiple jurisdictions could prevent or delay securing the necessary permits for pipelines to transport supercritical CO 2 . Commenter 10660 stated that siting of CO 2 pipelines raises interagency jurisdictional issues at the regulatory level. Commenter 6984 cited a study that noted that the federal Dep artment of Transportation’s Pipeline and Hazardous Materials Safety Administration safety rules are applicable to CO 2 pipelines but that states maintain much of the regulatory control over CO 2 pipelines. Commenters 9381 and 9780 noted that it is not clear whether legislation would be needed to allow FERC, in lieu of the Surface Transportation Board, jurisdiction to assure reasonable rates and open access to CO 2 pipelines. Commenter 9665 also noted the possibility

that such legislation would be needed. Comm enter 9665 stated that there are significant concerns regarding the availability and achievability

of the sequestration component of the partial CCS standard because it is unclear whether the current regulatory structure for CO 2 pipelines is adequate in th e event that CCS is required for all new Subpart Da units, much less natural gas
- fired combustion turbines. Statutory changes could be needed to transfer economic regulation of CO 2 pipelines to the Federal Energy Regulatory

Commission (FERC) in lieu of the Surface Transportation Board to assure reasonable rates and open access. Without such assurance, the EPA would be unable to adequatel y consider the cost of a requirement for parti al CCS as required under Clean Air Act Section 111(a)
. **Response 6.3 -**  **156:** This comment seems misplaced
. A s described in detail in the preamble to the final standard, there is a comprehensive and effective regulatory program for CO 2 pipelines administered b y the Pipeline and Hazardous Materials Administration
. Over 5,000 miles of dedicated CO 2 pipelines exist under this system, and that capacity is expanding due to increased demand
. This sy stem is already full y functioning and the commenter asserts but does not explain why a transfer of economic regulatory authority to another agency

is necessitated (or desirable)
. The sy stem functions well now, and is expanding
. The suggestion that capacity will be dwarfed by new coal CO 2 capture is not well taken, given that so little new ca pacity is likely to be added to the sy stem . Indeed, the robust growth in CO 2 pipeline demand is due to the need for CO 2 from other
- than coal sources
. See section V.I.5 of the final rule preamble of the NSPS
.6
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I ssues of pipeline siting can be accommodated in the planning and permitting process
. New sources, in particular, have a good deal of siting flexibility , since they are unconstrained by existing conditions. S afety of CO 2 pipeline operations falls under the jurisdiction of the Pipeline Hazardous Materials Safety Administration. States also retain significant control over the regulation of intrastate CO 2 pipeline operations . The EPA notes that issues associated with the governance and management of CO 2 pipeline infrastructure are beyond the scope of the final rule. Additionally , there is no evidence that current Federal and state laws governing access to and rate regulation of CO 2 pipelines has had a significant adverse effect on the development and expansion of CO 2 pipelines: in the past several ye ars hundreds of miles of pipelines that carry anthropogenic or natural
- occurring CO 2 have been permitted and constructed under existing state and federal regulations. **Comment 6.3 -**  **157:** Commenters 9381, 9426, 9666, 9780, 10239, and 10098 asserted that much of the nation ’ s law on C O 2 pipeline siting is underdeveloped at this time, potentially resulting in plant owners having to negotiate rights
- of
- way with hundreds of private landowners to run a CO 2 pipeline if state laws do not allow eminent domain as an option for procuring easements. Commenter 9666 suggested that legal issues of siting authority and the prospect of creating a mechanism to establish eminent domain to support timely CO 2 pipeline construction merited Congressional attention. Commenter 10098 stated that the proposed r ule provides a significant overview of federal regulations pertaining to geologic sequestration and makes only a passing reference to rights
- of

- way as if their successful acquisition was inevitable and just a cost of doing business. Additionally , commenter 10098 noted that state law decisions on eminent domain can lead to expensive and time consuming litigation b y landowners and non
- governmental organizations, and that procuring rights
- of
- way over federal lands can be especiall y resource intensive and time consuming due compliance with the National Environmental Policy Act, the Endangered Species Act, other federal land use laws, and public notice and comment periods. Commenter 10239 stated that siting of CO 2 pipelines are subject to state law, and, becaus e of this, negotiating rights
- of
- way for CO 2 pipelines will be a complicated and expensive process, particularl y if a state determines that CO 2 pipeline operators are not entitled to employ eminent domain to acquire rights
- of
- way . The commenter stated that rights of way over federal lands would be further complicated b y NEPA
. Commenter 10239 stated that while these critical issues are largel y outside of the EPA’s jurisdiction and control, it is nevertheless arbitrary and capricious for the EPA to simply ign ore them when assessing whether geologic storage is currentl y available. Commenter 9683 noted that State law is less clear and inconsistent on whether eminent domain authority is available for construction of CO 2 pipelines. Commenter 9683 noted that State law may extend eminent domain authority onl y in cases where the entity building the pipeline is a public utility, or onl y if the pipeline is needed to serve end
- use customers in the State. This may depend on whether the facility generating the CO 2 to be sent through the pipeline is within the state in which the pipeline would be constructed. Commenter 9683 also noted that at least one State requires that the pipeline have a “public use” in order to extend eminent domain authority
.6
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Similarly, commenters 10036 and 10618 stated that the EPA has ignored property rights issues that are barriers to the adequate demonstration and development of CCS, including jurisdictional determinations and how existing programs for eminent domain, unitization, public use, or voluntary acquisition translate to CO 2 pipeline development. The commenters state that these issues must be resolved on the state, interstate and national level in order to efficientl y and effectivel y regulate future CCS projects but will take time and resources. **Response 6.3 -**  **157:** The EPA recognizes that siting of CO 2 pipelines is largel y a state - regulated activity , and recognizes that state regulations concerning application of eminent domain vary among the states . The EPA does not consider state
- level pipeline siting processes and state
- level regulatory authority to be barriers to either the development of individual CO 2 pipelines or development of a broader national CO 2 pipeline network, as evidenced b y the many new CO 2 pipelines permitted and placed in service over the past few ye ars alone . The challenges associated with expansion of CO 2 pipeline infrastructure are not insurmountable. The legal and regulatory

issues cited b y the commenters, including eminent domain authority , environmental impact assessment, and time
- frame for siting, permitting, and c onstructing CO 2 pipelines are not new issues. For example, land
- use issues, acquisition of rights
- of
- way , and public perception of impacts are issues that all ty pes of pipeline development face, and are all issues that have been dealt with effectivel y in the past for siting, permitting, and construction of CO 2 pipelines. Additionally , although CO 2 pipeline infrastructure is currentl y limited to where active EOR production and extraction operations using CO 2 are occurring
. S everal hundred additional miles o f CO 2 pipeline are either under construction, planned, or proposed which will increase the accessibility

and geographic extent of this infrastructure in the near future
. Recently planned, proposed, and constructed CO 2 pipelines provide evidence that the pe rmitting process does not pose insurmountable obstacles to siting and construction of new CO 2 pipelines. **Comment 6.3 -**  **158:** Commenter 9665 noted that it is possible that legislation would be needed to have FERC issue certificates of public convenience and necessity , and related eminent domain rights, to CO 2 pipelines comparable to those granted for natural gas pipelines. Commenters 9665 and 10662 noted that Federal eminent domain that is available for natural gas pipelines is not currentl y available for CO 2 pipelines, and commenter 10662 noted that both the FERC ( Federal Energy Regulatory

Commission) and the STB ( Surface Transpo rtation Board) have declined to take jurisdiction over siting of CO 2 pipelines, and as a result siting of CO 2 pipelines is relegated to the states. Commenter 8925 also cited a study noting that there is no current Federal siting or eminent domain regulatory s cheme for CO 2 pipelines
. Commenters 9381 and 9665 conclude the current regulatory

framework for CO 2 pipelines cannot confidentl y be relied on as a basis for development of a much more robust CO 2 pipeline network, because CO 2 pipeline projects are subjec t to significant timing and cost uncertainties related to right
- of
- way acquisition. **Response 6.3 -**  **158:** EPA recognizes that siting and permitting of CO 2 pipelines is largely within the jurisdiction of the states and that regulations concerning eminent domain applicability to CO 2 pipelines differ among the states . The EPA also recognizes that CO 2 pipeline siting and construction costs will vary by state and by

proposed pipeline location . The EPA estimated CO 2 pipeline siting and construction costs based on cost studies prepared by the U.S. Department of Energy National Energy

Technology

L aboratory

(DOE
-NETL) and other sources (see e.g., DOE
NE TLreferences cited in section V.I.2.a of the preamble). The range of siting and construction6
- 99

costs considered is representative of costs that CO 2 pipeline developers would actually incur . The EPA does not agree that state
- by
- state CO 2 pipeline siting regulations and the lack of federal agency regulatory

authority over CO 2 pipeline siting represent insurmountable barriers to siting and construction of either individual CO 2 pipelines or a broader CO 2 pipeline network or that state - specific cost factors will result in CO 2 pipeline developers incurring costs outside the range of values considered b y the EPA in the cost anal ysis. The EPA does not agree that the current permitting framework for new CO 2 pipelines cannot be relied upon to enable the siting and construction of new CO 2 pipelines. Th ere are several hundred additional miles of CO 2 pipeline that are either under construction, planned, or proposed
. Recently planned, proposed, and constructed CO 2 pipelines provide evidence that the permitting process does not pose insurmountable obstacles to siting and construction of new CO 2 pipelines. **Comment 6.3 -**  **159:** Commenter 9780 asserted that legislation would be needed to authorize FERC to issue certificates of public convenience and necessity, and related eminent domain rights, to CO 2 pipelines comparable to those granted for natural gas pipelines. Commenter 9665 also noted the possibility

that such legislation would be needed to grant such authority to FERC
. Commenter 8032 noted that permitting sequestration locations will likely have serious technical, legal and cost issues related to siting and b uilding CO 2 pipelines, and cited as an example the issue of utilities not having the right of eminent domain. Commenter 9780 stated that building a natural gas pipeline can take ye ars, and it will take longer to build CO 2 pipelines unless the federal gover

nment amends the current process to facilitate construction
. Commenter 10662 also noted that there is currently insufficient development of key legal issues, such as the process by which to acquire rights
- of
- way for CO 2 pipelines. Commenter 8966 also stated that pipeline siting and construction is complicated b y geographic constraints based on the terrain of the pipeline path, local and state siting requirements, and acquisition of necessary rights
- of
- way . Commenter 9666 stated that the most significant barriers to expansion will be non
- technical issues

– addressing property rights for right
- of

- way access and multi
- state jurisdictions. **Response 6.3 -**  **159:** Federal and state regulatory requirements for siting and permitting new CO 2 pipelines are o utside the scope of this rule
. However, the EPA does not agree that Federal legislation concerning eminent domain and certification of public convenience and necessity for CO 2 pipelines would be needed to ensure timel y development of either individual CO 2 pipelines or a broader CO 2 pipeline network . The EPA agrees that siting and construction of new CO 2 pipelines could require several ye ars, however, the EPA does not consider that time frame to be inconsistent with the anticipated time frame for siting and construction of new coal
- fired EGUs expected to be few in number. State and Federal agencies have been permitting CO 2 pipelines for decades
. Moreover, data from the Pipeline and Hazardous Materials Safety Administration show that in 2013 there were 5,1 95 miles of CO 2 pipelines operating in the United States. This represents a seven percent increase in CO 2 pipeline miles over the previous year and a 38 percent increase in CO 2 pipeline miles since 2004
. The EPA views the existing CO 2 pipeline licensing process as adequate for siting and construction of new CO 2 pipelines that may be needed to provide CO 2 transport from new coal
- fired EGUs
. **Comment 6.3 -**  **160:** Commenters 9425, 9666 and 9683 stated that multiple jurisdictions, cross
state issues, and high pressures required for supercritical fluid transport could prevent or delay securing the necessary

permits for pipelines to transport supercritical CO 2 , and that proposed6
- 100

CO 2 pipelines may

incur public opposition
. Commenter 9666 noted that groups adversarial to coal
- fired generation can impose significant delays. It has been well demonstrated that some organizations have an established track record of contesting projects relating to CO 2 by opposing permits and legal action. Such delay s both slow p rogress and escalate cost of building any sequestration site and associated pipeline. For example, each month of delay in the Kemper County construction progress is estimated to add $15
- 25 million to the final cost. Commenter 9683 noted that without eminent domain, a project developer would have no recourse but to seek permission from each landowner through whose property the project would traverse, with a “ no ” answer requiring a re
- routing or scrapping the project entirely
. Commenter 9683 noted that Tenaska ’ s cancelled Taylorville project included a 450
- mile CO 2 pipeline to connect to an existing CO 2 pipeline
. Commenter 10239 noted that I llinois EPA identified access to CO 2 pipelines as a logistical challenge to the Taylorville project. Commenters 9 596, 9197, and 10618 also stated the absence of eminent domain authority for construction of CO 2 pipeline could introduce significant and potentiall y insurmountable barriers to the construction of a new CO 2 pipeline. Unlike natural gas pipelines, which can secure federal eminent domain authority, CO 2 pipelines must be built with the consent of every intervening landowner. The need to negotiate with and obtain an easement from potentially thousands of landowners for each new CO 2 pipeline could dramatically l engthen the amount of time between planning and construction of a CO 2 pipeline while dramaticall y raising costs. These factors, when combined with the time and financial expenditure necessary to obtain state and federal regulatory

approval for various aspe cts of each CO 2 pipeline renders this option non
- viable for most EGUs
. Commenter 9596 noted that studies they and others have undertaken demonstrate that there would be significant CO 2 pipeline siting issues associated with undertaking CCS in the Southea stern United States. **Response 6.3 -**  **160:** Commenter 9666 summarized a West Virginia Chamber of Commerce (Commenter 6948) survey of the state laws, regulations, and policies which found that states do not have adequate regulatory mechanisms in place to support CO 2 sequestrati on . The study by Commenter 6948 (cited by Commenter 9666 and Commenter 10618) noted that only 12 states have provided any streamlined process for the siting or construction of pipelines used to transport CO 2 . Commenter 10243 noted that while some states, including Michigan, have enacted legislation or regulation that address siting of CO 2 pipelines, without a uniform national policy related to right
- of

- way acquisition for CO 2 pipelines, Commenter 10243 expects significant timing and cost uncertainties arising as companies attempt to negotiate contracts to gain access to land, lay

pipeline, restore land, and conduct other pipeline siting and construction related activities. CO 2 pipeline specifications of the U.S. Department of Transportation Pipeline Hazardous Materials Safety Administration found at 49 CFR part 195 (Transportation of Hazardous L iquids by

Pipeline) appl y regardless of the source of the CO 2 and take into account CO 2 composition, impurities, and phase behavior
. These rules contain (among oth er provisions) detailed requirements related to reporting, pipeline design (temperature, pressure variation both internal and external, loads, ty pes of pipes, valves and fittings, connections, closure, and leak detection), construction, pressure testing, a nd corrosion control
. CO 2 - specific provisions require6
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special design for CO 2 at low temperatures
. 49 CFR section 195.102 (b)
. These requirements have applied for ye ars, successfull y, to compressed, supercritical CO 2 captured, transported via regulated pipe line, and used for EOR
. The commenters do not address these requirements, and their successful use in the EOR context, in assuming massive opposition to new pipeline (or use of existing pipelines) or why eminent domain authority would be necessitated
. As n oted above, issues of pipeline availability and use did not pose obstacles to granting UIC Class VIpermits to ADM and FutureGen. Denbury recently completed the final section of the 325
- mile Green Pipeline for transporting CO 2 from Donaldsonville, L ouisian a, 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 CO 2 pipeline from fertilizer plant in Coffey ville, Kansas, to an oil field in Oklahoma. These large CO 2 pipeline projects demonstrate that long CO 2 pipelines can be sited effectivel y under the current regulatory system
. Actual experience has shown that the commenters’ concerns are surmountable
. The EPA does not agree that a significant expan sion of the current CO 2 pipeline network would be needed within the foreseeable future for transport of CO 2 captured from new EGUs because of the expected limited construction of new coal
- fired EGUs . The EPA also does not agree that the siting and construc tion of CO 2 pipelines needs to be federall y regulated concerning rates and access, or that states that have not done so would need to establish eminent domain procedures, in order for CO 2 pipeline transportation to be provided for new coal
- fired EGUs . The EPA expects that new CO 2 pipelines needed to transport the CO 2 captured from a new coal
- fired EGU could be sited and constructed within a similar timeframe as would be needed for the planning, siting and construction of the new EGU itself. The commenters do not address whether new sources could site a source advantageousl y to account for pipeline availability . The EPA thus regards these comments as overstated
. In any case, compliance alternatives exist under the final standard which would not necessitate s equestration. **Comment 6.3 -**  **161:** Commenter 10618 stated that although it is a commonly held belief that CO 2 pipelines may

be developed to parallel existing electric transmission line rights
- of
- way , transmission line rights
- of
- way are commonly

specific to above ground structures, and would not apply to pipeline development
. Existing transmission line rights
- of
- way do not alway s provide access to perform work that is not affiliated with the transmission lines. For example, additional right
- of
- way permissions from landowners may be required to obtain access to conduct baseline field studies needed for pipeline siting and construction. **Response 6.3 -**  **161:** The EPA recognizes that electric transmission rights
- of
- way and pipeline rights
- of
- way requirements may

differ and that there may be restrictions o n the use of electric transmission line rights
- of
- way for other purposes . The EPA did not base the anal ys is of the technical and economic feasibility of CO 2 pipeline siting and construction on the use of electric transmission corridors, and any restriction s on specific rights
- of
- way do not affect the conclusions of the anal ys is. **Comment 6.3 -**  **162:** Commenter 10662 stated that the EPA ignores the realities of the lack of CO 2 pipelines across the country and the legal, regulatory and financial hurdles that exist to expand capac ity

by the orders of magnitude that would be needed to transport EGU CO 26
- 102

emissions. Commenter 9734 also noted that more CO 2 pipelines will need to be built, which would require the acquisition of property rights and compliance with numerous state and federal laws and regulations
. Commenter 9666 noted that in addition to construction of CO 2 pipelines, a network of booster compressors could also needed to operate the CO 2 pipeline network. **Response 6.3 -**  **162:** The EPA does not agree that a significant expansion of the current CO 2 pipeline network would be needed within the foreseeable future for transport of CO 2 captured from new EGUs because of the e xpected limited construction of new coal
- fired EGUs . The EPA also does not agree that the siting and construction of CO 2 pipelines needs to be federall y regulated concerning rates and access, or that states that have not done so would need to establish emi nent domain procedures, in order for CO 2 pipeline transportation to be provided for new coal
- fired EGUs . The EPA expects that new CO 2 pipelines needed to transport the CO 2 captured from a new coal
- fired EGU could be sited and constructed within a similar t imeframe as would be needed for the planning, siting and construction of the new EGU itself
. The existing CO 2 pipeline network includes booster compressors and other ancillary equipment, and the EPA does not consider the need to provide such equipment as a component of new CO 2 pipelines to be an impediment to siting, construction, or operation of proposed CO 2 pipelines. **Comment 6.3 -**  **163:** Commenters 10029 and 10664 expressed support for the creation of a network of new and existing pipelines throughout the United States, from which CO 2 may be introduced b y affected EGUs and distributed and sold at various points in the network. Commenters 1 0664 and 10029 noted that this will distribute the cost to construct and operate the network over a wide range of potential users, and facilitate the commercial deploy ment of CO 2 reuse technologies. Commenters 10029 and 10664 stated that the narrow approa ch in the EPA's proposal, which prohibits any

disposition of captured CO 2 except geologic sequestration, suggests the need for dedicated CO 2 pipelines that are constructed solel y to transport the captured CO 2 from an affected EGU directl y to a geologic sequestration site. Commenters 10029 and 10664 suggested that this unnecessaril y narrow approach would severel y restrict access to the CO 2 pipeline network, prevent the sale or distribution of CO 2 as a commodity for reuse, and needlessl y increase the costs to construct and operate that network. **Response 6.3 -**  **163:** A CO 2 pipeline network already exists which allows CO 2 from any source to be piped
. The final rule does not establish any restrictions on how the CO 2 pipeline network is used or the purposes to which CO 2 off
- taken from the CO 2 pipeline network is used. In addition, the final rule provides an alternative case
- by
- case compliance mechanism for storage of captured CO 2 allowing demonstrations that alternative storage technologies are as effective as geologic sequestration
. In addition, the final standard has alternative compliance pathway s that do not involve sequestration or other storage of CO 2 . The rule generall y requires that captured CO 2 be either injected on
- site for geologic sequestration or transferred offsite to facility reporting under 40 CFR subpart RR
. As stated in section V.M
. 4 of the preamble, there are emerging technologies alternative to geologic sequestration that are designed to safel y sequester or otherwise utilize captured CO 2 such that it is not releas ed to the atmosphere
. These technologies are not sufficiently advanced that the EPA is prepared to6
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unqualifiedly

structure this final rule to allow for their use, nor are there plenary s ys tems of regulatory

control and GHG reporting for these approaches, a s there are for geologic sequestration
. In this final rule, the EPA is establishing a mechanism for a case
- by
- case adjudication by

the EPA of applications seeking to demonstrate to the EPA that a non
- geologic sequestration technology

would result in perman ent confinement of captured CO 2 from an affected EGU. **Comment 6.3 -**  **164:** Commenter 10036 noted that the EPA stated that that 95 percent of the 500 largest CO 2 point sources are located within 50 miles of a possible geologic sequestration site which would lower transportatio n costs.” Commenter 10036 stated that the EPA ’s anal ys is is based solel y on the locations of existing sources while the proposed rule applies to only new sources, and that future power plants may need to be sited in locations very different from existing p ower plants. Commenter 10036 also noted that even fifty miles of new CO 2 pipeline would be considerable and might not be possible for a given location. For example, AEP’s proposed commercial scale CO 2 capture and storage s ys tem at Mountaineer Plant include d approximately

12.5 miles of CO 2 pipeline. Within that short 12.5 mile distance, AEP encountered more than 250 landowners that would have been impacted b y the CO 2 pipeline crossing their property . Had the project moved forward, AEP would have had to obtai n rights
- of
way for the CO 2 pipeline from all impacted property owners. **Response 6.3 -**  **164:** The EPA recognizes that new EGUs may need to be sited in locations different from the locations of existing EGUs, and that siting of new EGUs would take into consideration a number of factors
. However, the EPA does not agree that EPA’s anal ys is is based “solel y” on the locations of existing sources while the proposed rule applies to only new sources . Potential sequestration sites are located throughout the United S tates . The EPA also recognizes that acquisition of right
- of
- way is an essential component of the siting and construction of pipelines, and included estimated acquisition costs as part of its cost assessment
. However, the EPA does not consider the need for proponents of propo sed CO 2 pipelines to negotiate with individual landowners to be a substantial impediment , as evidenced, among other things, b y the Class VI permits issued to Archer Daniels Midland and FutureGen. **Comment 6.3 -**  **165:** Commenter 9683 noted that while it is technologically possible to build CO 2 pipelines, the EPA has given no consideration to the expense, legal and regulatory burdens (and perhaps in some cases impossibilities), and the length of time required for such construction to occur. Commenter 10048 also noted that the adv anced CO 2 pipeline infrastructure that would need to be developed would require a substantial amount of time to site, design, and construct. Commenter 9780 noted that the EPA has failed to account for the lengthy, costly , and uncertain permitting processes for major pipelines, and has not addressed the fact that the owners of new EGUs installing CCS are not likely to be the entities responsible for permitting, building and paying for the necessary

new CO 2 pipelines
. Commenter 9780 further states that the EP A has made unsubstantiated and unverifiable claims about the ease and cost of building CO 2 pipelines. **Response 6.3 -**  **165:** The EPA recognizes that new EGUs subject to the rule would not necessarily be the constructor or the owner
- operator of CO 2 pipelines that would transport the captured CO 2 to a sequestration site . The EPA does not consider the fact that the new EGU and new CO 2 pipeline may

have different owner
- operators to be a substantive impediment to siting and construction of new CO 2 pipelines
. Existing CO 2 pipelines that have been constructed to6
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transport either captured CO 2 or naturally
- occurring CO 2 to EOR sites are not necessaril y owned and operated b y the same entity that is operating the EOR sites. The owner
- operators engage in a commercial transaction concerning the transportation of the CO 2 supplied to the EOR site; the EPA anticipates that new EGU operators may engage in commercial transactions concerning the transportation of the CO 2 captured from the proposed EGU to a sequestration site. With resp ect to the time frame for siting and constructing CO 2 pipelines, the EPA anticipates that CO 2 pipelines that would transport captured CO 2 from new coal
- fired EGUs to sequestration sites could be sited and constructed within a similar time frame as would be needed for planning, siting and construction of the EGU itself, considering the limited construction of new coal
- fired EGUs that is expected
. **Comment 6.3 -**  **166:** Commenter 10105 noted that Nevada lacks the appropriate geology for sequestration and that as a result c aptured carbon would have to be transported to other states. That would require the availability of significant pipeline infrastructure. In a state like Nevada, with large rural areas, the cost of installing pipelines will likely be prohibitively

expensive
. Additionally , Nevada’s rural areas are prime sage grouse habitat and desert tortoise habitat. The sage grouse is currentl y i n the process of being listed as threatened or endangered, and the desert tortoise is a listed species. The listing of those speci es and the large size of their habitats would make siting a pipeline even more challenging
. Commenter 10618 identified p ermitting related challenges to the viability of any CCS project, including that the size of the CCS project alone (capture, transport, and storage s ys tems) would require extensive field studies to evaluate biological, cultural, and wetland resources to support the preparation of permit applications. **Response 6.3 -**  **166:** The EPA recognizes that not all states and areas of the U.S. have potential sequestration capacity, and acknowledges that CO 2 pipelines would need to be constructed to transport CO 2 captured from proposed EGUs that are not located in the vicinity of sequestration capacity . The EPA does not agree that the fact that certain states and areas of th e U.S. do not have potential sequestration capacity renders CO 2 capture, transport, and sequestration infeasible . The EPA recognizes that environmental impact review under NEPA would be required as a condition of siting and construction of proposed CO 2 pipelines that cross Federal land
. Such review would include an assessment of potential impacts of the proposed pipeline to endangered and threatened species in accordance with the Endangered Species Act, as well as assessment of potential impacts of the p roposed pipeline to natural, cultural and biological resources . Federal agencies including the BLM have conducted NEPA reviews of proposed pipeline projects potentially impacting sage grouse and other threatened and endangered species habitat and Federal a gencies and have established procedures for conducting assessments of potential impacts to natural, cultural, and biological resources
. Such environmental impact reviews are outside of the jurisdiction of the EPA and would be conducted by the responsible F ederal agency
. **Comment 6.3 -**  **167:** Commenter 9201 noted that the EPA did not consider or evaluate the impacts on land use and other environmental values from the construction of CO 2 pipelines to transport CO 2 to sequestration sites or for enhanced oil recovery as envisioned under the proposed rule
. Commenter 9195 questioned whether the EPA considered the potential non
- air environmental impacts of the construction of the national CO 2 pipeline network
. Commenter 10086 noted that the majority of the U.S. lacks pipelines to transp ort the CO 2 and that the EPA6
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failed to account for the lack of transportation infrastructure and the environmental impact and costs of constructing a network of pipelines across the United States
. **Response 6.3 -**  **167:** Siting and construction of proposed CO 2 pipelines is subje ct to permitting and environmental reviews conducted b y state and/or federal regulatory agencies. Proposed CO 2 pipelines crossing Federal (e.g., BLM) land would be subject to environmental reviews conducted b y the responsible Federal agency under the Natio nal Environmental Policy Act (NEPA) and the Federal agency ’s NEPA implementing regulations. For example, BLM has established and implements procedures for environmental reviews of proposed CO 2 pipelines under NEPA under Federal NEPA regulations and BLM’s i mplementing regulations
. NEPA reviews of proposed CO 2 pipelines include consideration of non
- air quality and other environmental impacts of construction and operation of the proposed pipeline. Proposed intrastate CO 2 pipelines and proposed interstate CO 2 p ipelines that do not cross Federal land are subject to permitting and environmental reviews under state regulations and potentially also under Federal regulations
. Therefore any CO 2 pipelines proposed to transport CO 2 captured from new EGUs that are subject to the proposed rule would be subject to project
- specific permitting and project
- specific environmental reviews including consideration of land use impacts, non
- air quality impacts and other environmental impacts of proposed pipeline construction and operation. **Comment 6.3 -**  **168:** Commenter 9780 agrees that CO 2 has been safel y transported via pipelines in the U.S. for nearly

40 years—

primarily for the purpose of enhanced oil recovery (EOR)

— and there are few technical hurdles associated with CO 2 pipelines , there are various legal and regulatory

issues that will need to be addressed for any significant expansion of the current, limited, 3,600
- mile CO 2 pipeline sy stem . These include issues of eminent domain for CO 2 pipeline siting and issues of reasonable rates and open access for CO 2 pipeline network operation. **Response 6.3 -**  **168:** The EPA agrees that CO 2 pipeline transport is demonstrated and technicall y feasible . The EPA recognizes that some states have already established eminent domain procedures for siting and construction of CO 2 pipelines while other states have not done so . The EPA does not agree that a significant expansion of the current CO 2 pipeline network would be needed within the foreseeable future for transport of CO 2 captured from new EGUs because of the expected limited construction of new coal
- fired EGUs. See RIA chapter 4 . The EPA also does not agree that the siting and construction of CO 2 pipelines needs to be federally regulated concerning rates and access, or that states that have not done so would need to es tablish eminent domain procedures, in order for CO 2 pipeline transportation to be provided for new coal
- fired EGUs . The EPA expects that new CO 2 pipelines needed to transport the CO 2 captured from a new coal
- fired EGU could be sited and constructed within a similar timeframe as would be needed for the planning, siting and construction of the new EGU itself. **Comment 6.3 -**  **169:** Commenter 8925 noted that once permits and rights
- of
- way were secured, construction of a 12.2 mile intrastate CO 2 pipeline was completed within 3 months
. Commenter 8925 noted that the applicant needed to consult with eight separate Federal and State agencies as part of the pipeline permitting process.6
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**Response 6.3 -**  **169:** EPA recognizes that multiple state and federal agen cies may need to be involved in siting and construction of CO 2 pipelines to comply with regulations
. The commenter illustrates that CO 2 pipelines can be and have been successfull y licensed, sited, and constructed, and that CO 2 pipelines can be and have been constructed in a timel y manner. **Comment 6.3 -**  **170:** Commenters 9600, 10097, 10098, and 10239 stated that the EPA has already determined that CCS is not technically feasible for EGUs and that the EPA has already identified the cost of building CO 2 pipelines as one factor in this determination. Commenter 10098 reviewed the EPA GHG Guidance for determination of Best Available Control Technology (BACT) and asserted that the EPA GHG Guidance expects CCS to be eliminated from further consideration under Step 2 or Step 4 of the dec ision making process. Commenter 10098 stated that for purposes of Step 2 of the decision making process, pertaining to technical feasibility , the EPA has already acknowledged the significant technical and logistical barriers ( including CO 2 transport) that hinder CCS
. Commenter 10618 also noted that the EPA has acknowledged in their guidance document for Prevention of Significant Deterioration PSD permitting for GHGs that the scope of design, construction, and operation considerations are much different and unique for CCS compared to other emission control s ystems . Commenters 10098 and 10239 cited several project
- specific anal ys es that determined that CCS was technically infeasible because of the lack of transportation infrastructure. **Response 6.3 -**  **170:** Commenter 10098 concludes that although the GHG Guidance urges permitting agencies to consider CCS, it left no question that CCS is not ready for widespread use; EPA’s own GHG Guidance and decisions based on the Guidance do not consider CCS to be technicall y feasible. Previous facility
- specific BACT determinations were not subje ct to a regulatory
- established “BACT Floor” because no standards were in place at the time the reviews were conducted
. The definition of BACT in the CAA specifies that “[i]n no event shall application of [BACT] result in emissions of any pollutants which will exceed the emissions allowed by any applicable standard established pursuant to section 111 or 112 of the Act.” This has historically been interpreted to mean that BACT cannot be less stringent than any applicable standard of performance under the NSP S. See e.g. EPA, PSD and Title V Permitting Guidance for Greenhouse Gases, p. 20
- 21 (March 2011). Thus, upon completion of an NSPS, the EPA reads the CAA to mean that the NSPS establishes a “BACT Floor” for PSD permits issued to affected facilities covered by

an NSPS. It is important to note that a proposed NSPS does not establish the BACT Floor for affected facilities seeking a PSD permit , as just noted above . This is explained on page 25 of EPA's PSD and Title V Permitting Guidance for Greenhouse Gases (March 2011 ), and is likewise clear from the language of CAA section 169 (3)
. However, although a proposed NSPS is not a controlling floor for BACT, the NSPS is an independent requirement that will apply to an NSPS source that commences construction after an NSPS is proposed and carries with it a strong presumption as to what level of control is achievable. This is not intended to limit available options to only those considered in the development of the NSPS.6
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Once the NSPS is finalized, then the standard would apply to any new source that meets the applicability

of the NSPS and has not commenced construction as of the date of the proposed NSPS, including any

existing facility

that adds EGU capacity

by adding a new EGU that is an affected facility

under th is NSPS
. **Comment 6.3 -**  **171:** Commenter 10052 stated that the EPA has not fully considered many elements of implementing partial CCS that may render the technology

commerciall y unavailable or not technicall y viable. Commenter 10052 noted that the EPA indicates that CO 2 has be en safel y transported via pipelines in the U.S. for nearly 40 ye ars and that 95 percent of the 500 largest CO 2 point sources are within 50 miles of a possible geologic sequestration site, but states that this assessment is broadly conclusory

and does not account for the geographicall y diverse and distant nature of power plant locations in much of the United States. The commenter stated that the EPA has similarly ignored my

riad factors that complicate the viability of sequestration sites, for example, in the Midwest and Western U.S., significant CO 2 pipeline infrastructure is likely to be needed for widespread deploy ment of CCS because the location at which the captured carbon may

be utilized for enhanced oil recovery (EOR) or geologically

sequestered is remote from the location of the resource. The commenter states that this is likely to render CCS prohibitively

expe nsive and potentially infeasible in certain locations of the country , because that the infrastructure required to transport the necessary quantities to CO 2 to sequestration sites or enhanced oil recovery

locations would outstrip the size of the existing natural gas pipeline infrastructure that exists today and because the ability

to obtain the required easements or property rights is questionable. **Response 6.3 -**  **171:** The EPA recognizes that sites for new EGUs may be geographicall y diverse and that some proposed EGU sites may n ot be located in the vicinity of potential EOR sites . The EPA recognizes also that CO 2 transport costs for new coal
- fired EGUs may vary geographicall y. There are multiple factors that contribute to the cost of CO 2 transportation via pipelines including but not limited to: availability and acquisition of rights
- of
- way for new pipelines, capital costs, operating costs, length and diameter of pipeline, terrain, flow rate of CO 2 , and the number of sources utilizing the pipeline. Studies and DOE quality guidelin es have shown CO 2 pipeline transport costs in the $1 to $4 dollar per ton of CO 2 range . The EPA does not agree that the potential geographic variability of potential new EGU sites renders the pipeline transport of CO 2 either technically

or economically

inf easible. Potential sequestration sites, either EOR formation or saline formations or other non
- EOR formations, are located throughout the United States and the EPA anticipates that proposed sites for new EGUs will be located in proximity to potential sequestration sites, and provision of electric power generation does not require coal
- fired facilities to be co
- located with the electric power demand they are intended to serve
. State and Federal agencies have permitted CO 2 pipelines for decade s, and several proposed CO 2 pipelines are currentl y in the state or federal agency permitting process and several others have recently been permitted . The EPA views the existing licensing process as adequate for any new CO 2 pipelines that may

be needed to transport CO 2 from new coal
- fired EGUs
. **Comment 6.3 -**  **172:** Commenter 10618 listed out examples of permitting related challenges to the schedule and budget of any CCS project, including extensive field study requirements for permit applications, multiple jurisdictional issues, and lack of experience permitting CCS on both the developer and regulator sides. The commenter stated that the permitting process for the6
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pipeline and well aspects of a CCS project alone could take years to resolve before construction could even b egin. Commenter 9472 also identified the long lead times and capital expenditure as issues for siting and construction of CO 2 pipelines. Commenter 10083 noted that the large proportion of federall y controlled lands in western states also creates its own ch allenges with respect to the timely permitting and construction of new generation resources and any needed pipeline infrastructure. **Response 6.3 -**  **172:** The EPA recognizes that implementation of the rule may entail siting and construction of CO 2 pipelines crossing Federal land . Federal agencies have decades of experience in reviewing and authorizing proposed CO 2 pipeline projects crossing Federal land, The Federal Bureau of Land Management (BLM), which manages approximately 250 million acres of land in the western U.S., has w el l
- established procedures for permitting CO 2 pipelines proposed to cross BLM land, and has issued permits for CO 2 pipelines
. The BLM in 2014 conducted reviews of proposed CO 2 pipeline projects under the BLM’s legal authority and established NEPA process
. The EPA recognizes that the review process for siting and construction of CO 2 pipelines crossing Federal land differs from processes that would be implemented for CO 2 pipelines crossing privately owned or other non
- Federal land, and that the Federal land management process may have a longer review schedule than for pipelines crossing privately owned or other non
- Federal land. However, the EPA does not agree that the Federal land management process represents a substantial impediment to the timely siting an d construction of CO 2 pipelines that may be needed, as evidenced b y the fact that many of the existing CO 2 pipelines cross Federal land. BLM conducted reviews of proposed CO 2 pipelines in 2014 and other pipeline projects were proposed for review in 2014
. T he reviews of proposed CO 2 pipeline projects conducted b y the BLM demonstrates that the Federal agency review process is a manageable process that would not impede the siting and construction of new CO 2 pipelines. **Comment 6.3 -**  **173:** Commenter 9735 stated that EOR is only fea sible when coal plants are located relatively

close to a mature oil field. The reality is that coal and oil formations are often far apart and CO 2 pipelines that would be required do not exist. When EOR is not an option, utility companies will need to tran sport CO 2 to appropriate geologic formations, such as saline aquifers. Commenters 8032, 9197, and 9735 noted that regardless of storage method, a vast pipeline infrastructure for CO 2 will need to be built that will have siting, permit, and regulatory chall enges that will add additional time and cost to any CCS project. **Response 6.3 -**  **173:** The EPA recognizes that some new EGUs may not be located in the vicinity of EOR formations and may need to transport captured CO 2 to saline aquifer or other non
- EOR sequestration sites
. Potential sequestration sites are located throughout the United States , and construction of CO 2 pipelines is adequatel y demonstrated . The EPA has addressed comments on storage in the Section 6.3 topic titled Geologic Sequestration
. State and federal agenci es have several decades of experience with CO 2 pipeline permits and the EPA anticipates that ex isting processes will continue to support future needs for siting and construction of new CO 2 pipelines. With respect to the timing of siting and construction of new CO 2 pipelines, construction of new EGUs is anticipated to be limited for the foreseeable future, and any new EGUs proposed would6
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need to be planned prior to siting and construction, and the EPA anticipates that the CO 2 pipelines needed to transport ca ptured CO 2 from new EGUs could be planned, sited, and constructed within a similar timeframe as the timeframe for planning, siting, and constructing the new EGU itself

. Therefore the EPA does not anticipate that CO 2 pipeline siting and construction will represent a substantial barrier for affected EGUs
. **Comment 6.3 -**  **174:** Commenter 9201 cited a study that that the U.S. and Canada will need more than 35,000 miles of additional natural gas transmission pipelines (both mainline and laterals) through 2035 to serve anticipated gro wth in natural gas demand, and that about three fourths of the incremental growth in demand will arise from the power sector doubling its consumption as a result of EPA policies including CO 2 NSPS rules for new and existing power plants. Commenter 9201 noted that the EPA did not consider or evaluate the impacts on land use and other environmental values from natural gas pipeline construction to supply increased demand

— including new natural gas power plants. **Response 6.3 -**  **174:** Siting and construction of propo sed interstate natural gas pipelines is subject to certification b y FERC. FERC has established and implements procedures for environmental reviews of proposed natural gas pipelines under Federal NEPA regulations and FERC’s implementing regulations
. NEPA re views of proposed natural gas pipelines include consideration of land use and other environmental impacts of construction and operation of the proposed pipeline. Proposed intrastate natural gas pipelines are subject to permitting and environmental reviews under state regulations
. Therefore, the land use impacts of any natural gas pipelines proposed to support growth in natural gas demand would be subject to project
- specific environmental reviews including consideration of land use impacts
. FERC conducts env ironmental reviews of proposed natural gas pipelines during the course of the natural gas pipeline certification process, which takes an average of fourteen to sixteen months
. **Safe Drinking Water Act ’**  **s Underground Injection Control (UIC)**  **Program and Resou rce**  **Conservation and Recovery Act Comment 6.3**  **- 175:**  Commenters 9425 and 9666 stated concerns with monitoring of CO 2 geologic sequestration wells. The commenters noted the Class VI program requires extensive monitoring and fifty ye ars of post
- closure site care as a default which will add significant cost to CCS. Commenter 9666 also stated the concern that State program administrators could lengthen the site care responsibility indefinitel y . Commenter 9426 asserted that a default of 50 years of post - closure site care is too long and adds significant additional costs. The commenter further stated that program administrator s could further lengthen the site care responsibility indefinitel y, posing a significant potential obstacle to CCS deploy ment. **Response 6.3 -**  **175:** This rule does not change the requirements for site closure of Class VI wells that were established in the Class VI Rule. Site c losure is defined b y regulation (40 CFR 146.81) as the time at which the Class VIinjection well owner or operator is released from post
- injection site care responsibilities. Under the Class VI UIC regulations, following cessation of injection, the operato r must conduct comprehensive post
- injection site care to show the position of the CO 2 plume and the associated area of elevated pressure to demonstrate that neither poses an endangerment to USDWs

– also having the practical effect of preventing releases of CO 2 to the atmosphere. Post
- injection site care includes appropriate monitoring and other needed actions6
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(including corrective action). The default duration for the post
- injection site care period is 50 ye ars, with flexibility

for demonstrating that an al ternative period is appropriate if it ensures non
endangerment of USDWs. For example, following the operational period for its project, Archer Daniels Midland plans a post
- injection site care period of 10 ye ars. 28 Under the Class VI regulations, the owner o r operator of a GS site is released from Class VI related post
- injection site care responsibilities upon site closure. See generall y preamble section V.N.1. The EPA’s cost estimates account for the requirements of the UI C Class VI program, and GHGRP subpart RR, including operational and post
- injection site care monitoring, which are components of the UIC Class VIrequirements, and subpart RR. Based on DOE/NETL studies, the EPA estimated that the total CO 2 transportation, storage, and monitoring cost associated with EGU CCS would comprise less than 5.5 percent of the total cost of electricity in all capture cases modeled. The studies also show that post
- injection site care, which includes monitoring, account s for between 15 and 22 percent of total storage costs. 29 The monitoring costs do not add significantl y to the overall cost of CCS. **Comment 6.3 -**  **176:** Commenters 9423, 9425, 9426, 9666 stated concerns with liability
. Commenter 9425 acknowledged that the EPA has established new Class VI regulations under the UI C Program for geologic sequestration wells that address some of the uncertainties in the regulatory

framework, including site characterization, design and construction requirements for wells, operating and post
- injection monitoring, testing of well integrity and financial responsibility
. H owever, the commenter stated that the proposal does not address liability which remains an impediment to broad deplo ym ent of CCS. Commenter 9666 stated that limitation of liability would most likely

require congressional action and it is unlikely the EPA could have addressed this issue effectively by rule without additional authority from Congress. The commenter noted this as another indicator that CCS is not an available technology for ne w EGUs. Commenter 10033 stated that from the perspective of CCS technology itself, although several projects have been successful, these projects have been too small and few in number to provide confidence that carbon sequestration projects will be protective of underground sources of drinking water at the large injection volumes and long time frames that would be found at a commercial power plant
. Commenter 9472 stated that the EPA did not address two ty pes of significant challenges operating CO 2 storage facilities in saline formations face. First, the existing regulations for CO 2 injection in saline formations, permitted as Class VI injection wells under the EPA's UI C program, pose practical barriers to project development including the 50 ye ar post - injec tion site care monitoring period. Second, the long
- term liability framework for injected CO 2 remains uncertain in many areas of the country and limits the opportunity to store CO 2 in saline formations in those regions. This period has the potential to exce ed the lifetime of organizations involved in the original injection program, adding contractual and legal challenges to the development of a CO 2 injection operation. The commenter also noted that while the full breadth
28 http://www.epa.gov/region5/water/uic/adm/
. 29 NETL , Cost and Performance Baseline for Fossil Energy Power Plants, Volume 1a: Bituminous Coal (PC) and Natural Gas to Electricity (July 2015) at 45; NETL , Carbon Dioxide and Transport and Storage Costs in NETLStudies, DOE/NETL
- 2013/1614 (March 2 013) at 27.6
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of considerations will vary b y site and project, they impact the feasibility

of integrating CCS at a power plant, and must be sorted out prior to the beginning of CCS operations because subsurface storage must be operational at all times for a CCS project. **Response 6.3 -**  **176:** The EPA has addressed comments regardi ng liability in the Section 6. 3 topic titled Li ability and post
- injection site care monitoring elsewhere in this topic titled Safe Drinking Water Act’s Underground Injection Control (UI C ) Program and Resource Conservation and Recovery Act
. Li mitation of liability is not a significant impediment to this rule . The EPA has issued Class VIpermits for six wells under two projects. Both permit applicants addressed siting and operational aspects of GS (including issues relating to volumes of the CO 2 and nature of the CO 2 injectate), and included monitoring that helps provide assurance that CO 2 will not migrate to shallower formations. The permits were based on findings that regional and local features at the site allow the site to receive injected CO 2 in specified amounts without buildup of pressure which would create faults or fractures, and further, that monitoring provides earl y warning of any changes to groundwater or CO 2 leakage. The permitting of these projects illustrates that permit applicants were able to address perceived challenges , including liability . These permits demonstrate the EPA’s view that these projects are capable of safel y and securel y s equestering large volumes of CO 2 -- including from steam generating units
-- for long
- term sto rage since the EPA would not otherwise have issued the permits. Furthermore, as shown in preamble section V. M , monitoring studies conducted at EOR and saline sites in the U.S. and internationally have demonstrated that large injection volumes can be safel y injected. **Comment 6.3 -**  **177:** Commenter 10033 stated that while EPA ’ s Class VI rules on carbon sequestration promulgated under the UIC program address many of the potential causes of drinking water contamination, the commenter continues to be concerned with some of the rule ’ s provisions that were included over the strong objections of the drinking water community . For example, commenter noted that the “ injection depth waiver” process allowed by the Class VI rule has many limitations that could result in degradation of USDW (underground sources of drinking water). According to the commenter, repeated requests to clarify and limit injection depth waivers to protect USDW have so far gone unanswered and several expected guidance documents, such as the guidance on injection depth waivers, have not yet been publicl y released. The commenter and commenter 10786 stated that to their knowledge, there has never been a single Class VI UI C permit issued any where, and only

a few applications have been submitted. The commenter concluded that although the foundation for a regulatory s ys tem exists, it is not ye t a mature process and should not be relied upon at a large scale before it has been full y proven. **Response 6.3 -**  **177:** Comments regarding the final Class VI rule requirements related to injection depth waiv ers are outside the scope of this rulemaking. This rule does not change the existing injection depth waiver process, which was established by the Class VI rule. See 75 FR 77254 (December 10, 2010). In the time since the commenter submitted comments , the EP A has issued six Class VI permits for two projects: an Archer Daniels Midland ethanol facility in Decatur Il linois and the FutureGen Industrial Alliance project. It would not have done so, and under the regulations could not have done so, without demonstrations that CO 2 would be securel y confined.6
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**Comment 6.3 -**  **178:** Commenter 9596 stated that although the recent promulgation of rules under the Resource Conservation and Recovery Act (RCRA) and the Safe Drinking Water Act (SDWA) for underground C O 2 injection wells may remove a certain amount of regulatory uncertainty, it has created new concerns in the oil and gas exploration industry over the regulatory

impact of accepting CO 2 from EGUs in EOR operations. With respect to the RCRA con ditional exc lusion rule, EPA made clear that that rule was not intended to affect the RCRA regulatory status of CO 2 streams that are injected into wells other than UI C Class VI wells, including UIC Class II wells used for EOR. See 79 CFR 355 (Jan. 3, 2014). **Response 6.3 -**  **178:** In respons e to inquiries and concerns, similar to those of Commenter 9596, directed to EPA’s Underground Injection Control Program, on April 23, 2015, the EPA’s Director of the Office of Ground Water and Drinking Water issued a memorandum to its regional UI C Program Directors reflecting the principle that injection of anthropogenic CO 2 for enhanced recovery

through Class II wells does not force transition of these wells to Class VI wells

– not during the well’s active operation and not when EOR operations cease
. See section V.N
. 5 .a of the preamble for a summary of the memorandum. **Comment 6.3 -**  **179:** Commenter 10786 stated that the NSPS is not in accord with SDWA’ s provisions for delegated State Class II programs, including with respect to the increased risk anal ys is under section 144.19. Unless taking place within the context of an existing Class II permit (presumabl y issued by a State agency), none of these collateral inquiries regarding existing CO 2 - EOR operations is envisioned by or authorized under SDWA and its governing regulations. In a State with primacy over its Class II program, all relevant assessments and decisions under 40 C.F.R. Section 144.19 are in the exclusive domain of the relevant State Class II regulator. Indeed, the Transition Guidance later seems to concede as much, n oting that relevant considerations will have to be addressed in specific Class II permits. Transition Guidance, p. 6. **Response 6.3 -**  **179:** The EPA encourages Class II and Class VI UI C Program Directors to work together to address the potential need for transition fro m Class I I to Class VI permits. Additionally , the EPA believes that the best implementation approach is for states to administer both the Class II and the Class VIUI C programs. Nothing in this final rule changes the pro visions of SDWA or the authority of the state s to administer Class II permits. **Comment 6.3 -**  **180:** Commenter 10786 stated that the Section 144. 19 confirms that NSPS is not a “logical outgrowth” of the originall y proposed rule. The c ommenter noted that the E PA’ s interpretation of 40 C.F.R. Section 144.19 advanced in the Transition Guidance and implicitly adopted b y the NSPS provides post
- hoc confirmation that this final regulatory provision is not a “ logical outgrowth ” of EPA ’ s original proposal. Itwas not until the EPA released the Transition Guidance, as implicitly

in corporated thereafter b y the NSPS, that industry was made aware that the Agency

is now reading section 144.19 as authorizing forced conversions to Class VI(and perhaps at the Class VI Director ’ s discretion). The positions in the NSPS are in direct conflic t with both section 144.19 and the Agency ’ s prior statements regarding how EOR was to be treated on these matters.6
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**Response 6.3 -**  **180:** The commenter is mistaken. EOR wells across the United States are currentl y permitted as UIC Class II wells. CO 2 storage associated with Cla ss II wells is a common occurrence, and where injected through Class II
- permitted wells for the purpose of oil or gas - related recovery CO 2 storage can occur in a manner protective of underground sources of drinking water
. See also previous response. **Comment 6.3 -**  **181:** Commenter 9423 stated the disincentives created by EPA for use of captured CO 2 in EOR activities is further exacerbated b y EPA ’ s recent Draft UIC Program Guidance on Transitioning Class II Wells to Class VIwells that gives broad discretion to the EPA to d etermine when an existing Class II EOR well should be regulated and permitted as a Class VI geosequestration well. According to the commenter, the uncertainty of whether a Class II EOR well would be required to meet Class VI geosequestration well requirements as well as the cost, time, and long
- term liability to transition a well from Class II to Class VI will be an additional significant disincentive for EOR well operators to accept utility
- produced CO 2 . Commenter 9423 stated that the Class VI UIC regulations as adopted require a determination as to whether or not the primary

purpose of the injection of CO 2 is enhanced recovery . I f the answer is yes, the well remains a Class II well. If the answer is no, then a determination must be made as to whether risk s to underground drinking water sources have increased
. Commenters 9731 and 10786 stated that if CO 2 is to be a viable commercial product for use in EOR, the EPA must be mindful of the consequences of other significant regulations. For example, the UI C Cl ass VI rule will mandate a conversion from the Class II wells currently used for CO 2 injection, which will create additional costs with a number of regulatory and legal uncertainties and challenges. Commenter 10786 stated that long
- term storage with EOR wi ll require an understanding of state legal and regulatory frameworks and how businesses can conduct operations under Class VI that is not present in the NSPS
. Several commenters (9197, 9596, 9780) stated that the need to transition from Class II injectio n wells to Class VIwells under draft EPA guidance could further discourage EOR operators from accepting CO 2 from EGUs for GS. **Response 6.3 -**  **181:** On April 23, 2015, the EPA issued a memorandum from the Director of the Office of Ground Water and Drinking Water to regional UI C Program Directors in its regional offices , and summarized in section V.N
. 5 .a of the preamble, that makes clear that the commenters’ concerns are misplaced. The EPA recognizes the widespread use of EOR and the expectation that injected CO 2 can remain underground. The memorandum reflected these principles: 30

 Geologic storage of CO 2 can continue to be permitted under the UI C Class II program.

30 “Key Principles in EPA’s Underground Injection Control Program Class VI Rule Related to Transition of Class II Enhanced Oil Recovery or Gas Recovery

Wells to Class VI”, April 23, 2015. Available at: http://water.epa.gov/ty

pe/groundwater/uic/c lass6/upload/class2eorclass6memo.pdf6
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 Use of anthropogenic CO 2 in EOR operations does not necessitate a Class VI permit.  Class VIsite closure requirements are not required for Class II CO 2 injection operations.  EOR operations that are focused on oil or gas production will be managed under the Class II program. If oil or gas recovery is no longer a significant aspect of a C lass II permitted EOR operation, the key factor in determining the potential need to transition a EOR operation from Class II to Class VI is increased risk to USDWs related to significant storage of CO 2 in the reservoir, where the regulatory tools of the C lass II program cannot successfully manage the risk. Either Class VI or Class II wells may be used for th e purpose of complying with this rule
. This rule does not require Class II wells to transition to Class VI
. **Comment 6.3 -**  **182:** Commenters 9472 and 10098 stated that chan ging well class is a major business decision carrying many long
- term financial and regulatory obligations and would likely require an EOR operator to obtain additional property or other legal rights, all of which create significant uncertainty and material ly impact an EOR
- to - geologic storage operator's business model. The commenters further asserted that if the source of CO 2 can contribute to an Agency decision that a Class II well needs to be re
- permitted as a Class VI well, then EPA's Class II to VIGuidance has created a disincentive to using CO 2 from a new coal
- fired EGU. Taken with the RCRA conditional exemption, the Class II to VI Guidance and the proposed NSPS requirement for an EOR operator to comply with Subpart RR reporting requirements create a strong set of disincentives for accepting a CO 2 stream from an EGU subject to the NSPS when other CO 2 sources are available. Commenter 10786 discussed the permitting delay s and regulatory risks associated with forcing the operation to convert to Class VI , wh ich may preclude timely

access to oil. **Response 6.3 -**  **182:** These comments are misplaced
. No change in well class would result from the standards of performance adopted pursuant to section 111(b). On April 23, 2015, the EPA’s Director of the Office of Ground Water and Drinking Water issued a memorandum to its regional UIC Program Directors reflecting the principle that geologic storage can continue to be permitted under the UI C Class II Program and the of anthropogenic CO 2 in EOR operations does not necessitate a Class VI permit
. See section V.N
. 5 .a of the preamble for a summary of the memorandum. The memorandum is available at: http://water.epa.gov/ty

pe/groundwater/uic/class6/upload/class2eorclass6m emo.pdf
. With respect to the RCRA conditional exclusion, see previous response. **Comment 6.3 -**  **183:** Commenter 10786 stated that the underl yi ng but unstated premise of the NSPS is that approved State
- based Class II programs are somehow ineffective at preventing injections that endanger USDWs ; however , all approved State
- based Class II programs already have been determined b y the Agency to be effective at meeting that goal. **Response 6.3 -**  **183:** The commenter is mistaken that the premise of the NSPS is that Class II programs are ineffective at protec ting USDWs. Geologic storage of CO 2 can continue to be permitted under the UI C Class II program. EOR wells across the United States are currently permitted as UIC Class II wells
. CO 2 storage associated with Class II wells is a common occurrence, and where injected through Class II
- permitted wells for the purpose of oil or gas
-6
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related recovery CO 2 storage can occur in a manner protective of underground sources of drinking water. **Comment 6.3 -**  **184:** Commenters 8974, 10033 and 10393 stated that CCS should continue to be considered an experimental technology at this time because CCS could pose significant risks to drinking water sources if rushed prematurel y to commercial scale. Commenter 10033 stated that it is quite possible that rushing CCS to commercial scale without adequate research and safeguards could make large amounts of US drinking water permanentl y unsuitable for use as community

water suppli es through altering the aquifer’ s chemistry
. Commenter 10393 noted that their combined municipal utility has an obligation to prot ect existing and future drinking water resources located in deep saline aquifers, in addition to providing reliable, affordable and environmentally

responsible electricity. **Response 6.3 -**  **184:** The EPA appreciates that drinking water resources must be protected . The EPA ’s UI C Program requirements

– for well Classes I through VI (inclusive of Class II enhanced recovery injection wells)

– are designed to ensure that USDWs are protected regardless of formation ty

pe . See Preamble at Section V.N .1
. In short, the UI C Class VI rule was developed to facilitate GS and ensure protection of USDWs from the particular risks that may be posed by large scale CO 2 injection for purposes of long
- term GS. The Class VIrule establishe d technical requirements for the permitting, geologic site charact erization, area of review (i.e., the project area) and corrective action, well construction, operation, mechanical integrity testing, monitoring, well plugging, post
- injection site care, site closure, and financial responsibility for the purpose of protecting USDWs
. UI C Class II regulations issued under section 1421 of SDWA provide minimum federal requirements for site characterization, area of review, well construction (e.g., casing and cementing), well operation (e.g., injection pressure), injectate sampl ing, mechanical integrity testing, plugging and abandonment, financial responsibility , and reporting. Class II wells must undergo periodic mechanical integrity testing which will detect well construction and operational conditions that could lead to loss o f injectate and migration into USDWs. Section 1425 of SDWA allows states to demonstrate that their Class II program is effective in preventing endangerment of USDWs. These programs must include permitting, inspection, monitoring, record
- keeping, and reporting components. The comment that these injection technologies are not available at commercial scale is misplaced
. See Preamble section s V.M and V.N . The EPA has issued six Class VIinjection well permits under the Class VI requirements , including for injec tion of anthropogenic CO 2 from a coal
- burning steam electric facility
. **Comment 6.3 -**  **185:** Commenter 6948 stated that for a CCS survey of the 50 states no state has ye t received delegation of the Class VI UIC, although one state has an application pending for delegation of th e program. **Response 6.3 -**  **185:** The EPA encourages states to apply for primacy

for all well classes, including Class VI. The EPA is in the process of reviewing North Dakota’s application for primacy and believes that the best implementation approach is for states to administer both the Class II and Class VI UIC programs
. The process of approving primacy for a state to implement the regulations for specific classes of injection wells is not a delegation, rather it is an approval6
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by a rule
- making process required by the Safe Drinking Water Act and outlined in the UI C regulations. **Comment 6.3 -**  **186:** Commenter 8032 noted that Class VIinjection wells will have to be used since there are not sufficient Enhanced Oil Recovery sites for all of the power generation facilities that will have carbon capture sy stems. These sites also may not be close to the power generation facilities making them infeasible. Class VI injection wells will have to be carefully designed or there could still be a release of CO 2 in to the atmosphere which will be counterproductive, costly and dangerous. Class VI wells must be designed to handle the unique nature of CO 2 including the relative buo yancy of CO 2 , its mobility

in the subsurface, its corrosive nature in the presence of water, and the large injection volumes anticipated at these sites. **Response 6.3 -**  **186:** The EPA agrees that it is important to ensure that CO 2 is safely stored , does not impact USDWs and is not released to the atmosphere
. Under SDWA and its Underground Injection Control Program, the EPA established minimum Federal requirements to ensure that geologic sequestration (Class VI) wells are appropriately sited, constructed, tested, monitored, and closed to ensure protection of drinking water
. The UIC Class VI regulations contain monitoring requirements to protect underground sources of drinking water, including a requirement that Class VI owners or operators develop, implement and maintain a comprehensive testing and monitoring plan, which includes testing of the mechanical integrity of the injection well, ground water monitoring, and tracking of the location of the injected CO 2 , using direct and indirect methods. Permittees are also required to perform post
- injection monitoring and site care to track the location of the injected CO 2 and moni tor subsurface pressures in relation to USDWs
. **Comment 6.3 -**  **187:** Commenters 9666, 9780, 10098, 10239 and 10660 asserted that the EPA has ignored significant legal and logistical barriers to geologic sequestration by focusing solely

on federal regulations under the UI C program, GHG Reporting Rule, and RCRA. Commenter 8966 stated that geologic sequestration is subject to state and local laws that are likely to confound operators unless national legislation is available to address property rights and other legal constraints. C ommenters 9666 and 10098 stated that the proposed rule assumes there is a full infrastructure and regulatory

framework in place even though it may take years to put into place. Commenter 10098 then stated that the anal ys is of the legal issues surrounding geologic sequestration, consisting of Class VI well permits, reporting requirements, and RCRA exemptions, is myopic. The commenters then discussed the potential barriers to obtaining contracts for offsite land acquisition, funding, timing of available tran sportation infrastructure, and developing a site for secure long term storage without state or federal eminent domain as natural gas pipelines have. Commenters 10098 and 10239 provided examples of permitting decisions rejecting CCS in part because it was not clear that the applicant could obtain the necessary rights of way

in part due to the lack of proven geology favorable for long
- term storage and other uncertainties.6
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Commenter 10137 stated that there are uncertainties surrounding whether subpart RR woul d constitute waste disposal. The commenter further stated that it appears that subpart RR is inconsistent with ty

pical oil and gas leases if subpart RR converts a hydrocarbon recovery operation into a waste disposal site, because typical leases come to an end and the property reverts to the owner following oil and gas completion. Commenters 10137 and 10786 also noted that the underl yi ng mineral leases pursuant to which EOR operators are authorized to conduct oil recovery operations are granted for the purpo se of hydrocarbon recovery and do not authorize the lessee to convert the owners ’ property into a waste disposal site. Commenter 10786 stated that declaring some CO 2 streams to be a “ solid waste ” under RCRA will make that CO 2 stream unsuitable for injectio n and associated long
- term storage in Class II mineral recovery operations, which the NSPS fails to acknowledge. Two commenters (9731, 9666) stated that compliance with subpart RR will transform an EOR operation from a resource recovery operation/maximization into a waste disposal operation. **Response 6.3 -**  **187:** The EPA has addressed the issues related to state an d local laws in the Section 6. 3 topic titled Other CO 2 Transport and Geologic Sequestration Legal and Regulatory Issues
. With respect to injection
- related permitting, i n the time since the commenter submitted comments Class VIpermits have been issued to two applicants by the EPA. Both applicants, Archer Daniels Midland (ADM) and FutureGen Alliance, addressed siting and operational aspects of GS (including issues relating to the perceived barriers mentioned by the commenter) in their permit applications. The fact that these applicants pursued permits indicates that they regarded any potential property rights issues as resolvable
. Anal ys es of other (non
- injec tion related) permitting decisions with respect to application of CO 2 capture and transport were conducted on a site
- specific basis and considered site
- specific factors in the anal ys is and were conducted under a different set of criteria than required under the CAA. Eminent domain issues are addressed in the Section 6. 3 topic titled Geologic Sequestration Property Rights
. Reporting under subpart RR does not cause an activity to become a waste management activity
. In the preamble for the Final Rule for RCRA Conditional Exclusion of CO 2 as a Hazardous Waste in January

2014, the EPA stated that sending CO 2 streams to Class VI wells for purposes of GS does constitute solid waste disposal . The EPA also noted that should CO 2 be used for its intended purpose as it is injected into UIC Class II wells for the purpose of EOR/EGR, it is EPA’s expectation that such an injection process would not generall y be a waste management acti vity , and that in any

case, the rulemaking did not alter the regulatory status quo of anthropogenic CO 2 injected for EOR (which has been done for decades without RCRA obligations being considered to impact or impede those operations). **Comment 6.3 -**  **188:** Commenter 9683 asserted that the proposed rule does not recognize the l egal and regulatory

structure needed for CCS, therefore impeding CCS's availability
. **Response 6.3 -**  **188:** The EPA believes that the Safe Drinking Water Act (SDWA), Resource Conservation and Recovery Act (RCRA) and Clean Air Act (CAA) will provide the necessary regulatory

frame work while ensuring environmental protection and the permanence of CO 2 storage . The specific protections offered under these regulations are addressed elsewhere in this section and in preamble section V.N.6
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**Comment 6.3 -**  **189:** Commenter 9666 summarized West Virginia Chamber of Commerce survey of the state laws, regulations, and CO 2 which found that states do not have adequate regulatory mechanisms in place to support CO 2 sequestration. The survey found that no state has yet received delegation of the Class VI Underground Injection Control ( “UI C ” ) program related to underground CO 2 injection; only 5 states have addressed what property rights must be secured for the geologic storage of CO 2 in pore space; only 7 states have developed any streamlined procedures for acquiring pore sp ace; only 4 states have developed programs addressing the mitigation of the long
- term post - closure liabilities that are associated with facilities that store CO 2 in geologic formations; and only 12 states have provided any streamlined process for the siting or construction of pipelines used to transport CO 2 . Commenters 10033 and 10618 stated that to date, the EPA has not issued a single final Class VI permit and o nly

a handful of states are pursuing primacy . The commenter further discussed if a permit is obtainable given the area required to accommodate the CO 2 storage volume associated with a coal
- based generation unit. With regard to the permit process, the commenter discussed the time required to prepare an application as well as process and issue a permit. Commenter 10618 cites an example of a 2011 permit application still under technical review to support the statement that the regulatory process is likel y to b e prohibitive. Commenter 10033 also asserted that at a minimum, there should be several years of successful administration of Class VI permits and associated commercial demonstration
- scale projects before the EPA or any other agency considers requiring the implementation of CCS technology on a wider scale. Commenter 10618 states that with regard to the EPA Class VIinjection well monitoring and care requirements, a number of uncertainties during and beyond a 50 years post - injection period must be addressed including transfer of liability after closure, financial responsibility requirements and duration, and post
- closure monitoring requirements and duration. **Response 6.3 -**  **189:** Commenter 9666 is correct that no state has yet received primary enforcement authority (primacy) for the Class VI UI C program. However, the EPA is in the process of reviewing North Dakota’s application for primacy and believes that the best implementation approach is for states to administer both the Class II and Class VI UIC programs
. The EPA encourages states to apply for primacy

for all classes, including Class VI
. In the time since the commenter submitted comments , the EPA has issued six final UI C Class VI injection well permits for two projects
. The fact that these applicants pursued and received per mits indicates that they

were able to resolve any

issues related to the project area or “Area of Review” (referred to by

the commenter as “the area required to accommodate the CO 2 storage volume ”) . The EPA believes that the regulatory framework currentl y i n place, and the experience gained from the recent permit application reviews, permitting, and demonstration Under the Class VIregulations, the owner or operator of a GS site is released from Class VI related post
injection site care responsibilities upon site closure. **Comment 6.3 -**  **190:** Commenter 9426 stated that specific implementation regarding the permitting of Class VI CO 2 storage wells is also uncertain and unquantified, as regulatory agencies are just now beginning to address specific requirements regarding how these permits can be issued.6
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**Response 6.3 -**  **190:** The EPA has issued six final UI C Class VI injection well permits for two projects and has developed a series of technical guidance documents and tools to provide information and possible approaches for addressing various aspects of permitting , constructing, operating , monitoring and closing a Class VI injection well. **Comment 6.3 -**  **191:** Commenter 10618 stated that uncertainties regarding the extent of EOR exemption from RCRA, such as RCRA applicability when the EOR process ends or if the process becomes solel y a geologic storage operation, could actuall y discourage the use of anthropogenic CO 2 for EOR operations. **Response 6.3 -**  **191:** In January 2014 the EPA issued the Final Rule fo r RCRA Conditional Exclusion of CO 2 as a Hazardous Waste in order to facilitate the deplo ym ent of geologic sequestration. The rule establishes a set of conditions under which CO 2 streams injected into UI C Class VIwells are excluded from the RCRA subtitle C regulations’ definition of hazardous waste. In the preamble to the rule, the EPA explained th at sending CO 2 streams to Class VIwells for purposes of GS is considered solid waste disposal, since the CO 2 stream is being “discarded” (see RCRA section 1004 (27)). However, that rule also creates a regulatory exclusion from classification as a hazardou s waste, so no RCRA subtitle C regulatory obligations are triggered when the CO 2 stream is managed in accordance with the conditions
. With respect to beneficial use (rather than disposal in Class VIwells) of captured CO 2 , the RCRA conditional exclusion ru le does not alter the regulatory status quo . The EPA also stated in the preamble that should CO 2 be used for its intended purpose as it is injected into UI C Class II wells for the purpose of EOR/EGR, it is EPA’s expectation that such an injection process w ould “not generall y be a waste management activity .” **Comment 6.3 -**  **192:** Commenter 10098 discussed EPA ’ s determination that conditionally exempted captured CO 2 streams that are injected into Class VIwells, not those injected into Class II wells are a RCRA solid waste. The c ommenter suggested that CO 2 injected into a Class II well for EOR could, in some situations, be considered a waste management activity and creates uncertainty

and a significant disincentive for operators utilizing CCS
- derived CO 2 for EOR purposes. Commente r 9734 also stated that there is regulatory uncertainty

surrounding the underground sequestration of CO 2 due to EPA ’ s determination that sequestered carbon is a solid waste. Furthermore, the commenter suggested that the informal “ safe harbor” for traditional EOR may only appl y to the practice of injecting natural CO 2 , not captured CO 2 streams. Therefore, if an oil and gas operator wants to use a CO 2 stream from a new coal
- fired EGU for EOR operations and avoid RCRA rules, the commenter stated that it may need to persuade the permitting agency that its EOR operations are not waste management activities or perform RCRA hazardous waste anal ys es on all accepted CO 2 streams. The commenter stated that no standardized anal ys es exist for this material, so an EOR operator would need to develop them. The commenter also asserted that if a CO 2 stream tests hazardous, the EOR operator needs contractual rights to reject and return the non
- conforming CO 2 stream. **Response 6.3 -**  **192:** As just stated, these concerns are not borne out by actual experience
. The RCRA subtitle C regulations have not been an historic impediment to use of anthropogenic CO 2 for EOR, and nothing the EPA has said in this rulemaking or the RCRA rulemaking6
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conditionally

excluding CO 2 sequestered in Class VI inje ction wells alters the present status quo
. The EPA stated in the preamble of the Final Rule for RCRA Exclusion that should CO 2 be used for its intended purpose as it is injected into UI C Class II wells for the purpose of EOR/EGR, it is EPA’s expectation th at s uch an injection process would not generall y be regarded as a waste management activi ty . **Comment 6.3 -**  **193:** Commenters 10098 and 10239 asserted that if geologic storage is a form of waste management, as the EPA contends it is, then even incidental leakage of this CO 2 stream could form the basis for RCRA liability and result in citizen suits. The commenter stated that the operator would not be covered b y the RCRA conditional exemption if the CO 2 stream was injected into a Class II well. **Response 6.3 -**  **193:** The status of captured CO 2 used for EOR in Class II is unaltered as a result of the conditional exclusion for CO 2 disposed in Class VI wells, and likewise unchanged b y any thing in the standards adopted pursuant to section 111 (b)
. Class II wells have been injecting anthropogenic CO 2 for decades under this existing regulatory structure without RCRA obligations being considered to impact or impede those operations. **Comment 6.3 -**  **194:** Commenter 10618 stated that uncertainties regarding the extent of EOR exemption from RCRA, such as RCRA applicability when the EOR process ends or if the process becomes solel y a geologic storage operation, could actuall y discourage the use of anthropogenic CO 2 for EOR operations. **Response 6.3 -**  **194:** The EPA’s recent RCRA conditional exclusion rule applies only to CO 2 streams that are injected i nto UI C Class VI wells (among other conditions). In the final rule preamble, the EPA discussed its view that supercritical CO 2 streams injected into UI C Class VI wells for purposes of geologic sequestration are RCRA “solid waste.” 79 FR 354
- 55 (Jan. 3, 201 4). However, that rule was not intended to , and does not affect the regulatory status of CO 2 streams that are injected into other well classes, including UI C Class II wells. I d. at 355 . The EPA stated that, should CO 2 be used for its intended purpose as it is injected into UI C Class II wells for the purpose of EOR/EGR, it is EPA’s expectation that such an injection process would not generall y be a waste management activity, and that interested persons should consult with the relevant regulatory

authority . I d
. Use of anthropogenic CO 2 for EOR is long
- standing and has flourished in all of the ye ars that EPA’s subtitle C regulations (which among other things, define what a solid waste is for purposes of those regulations) have been in place
. The subtitle C regu latory

program consequently

has not been any

impediment to use of anthropogenic CO 2 for EOR
. Thus, the EPA views the commenter’s concerns as exaggerated, and not supported by experience
. **Greenhouse Gas Reporting Program Comment 6.3**  **- 195:**  Commenter 9664 stated that they do not agree with EOR operators that have asserted that requiring compliance with the reporting and monitoring, reporting, and verification (MRV) plan requirements of subpart RR would result in operators avoiding the purchase of captured CO 2 . The commenter stated their belief that it is not inconsequential that available sources of naturall y mined CO 2 are declining, and that there is significant demand for anthropogenic CO 2 . Therefore, it is unlikely that existing operators would prefer to go out of6
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business rather than access the market for anthropogenic CO 2 , simply because of the need for better reporting of the amounts of CO 2 managed in EOR activity . The costs of opting into subpart RR by

an existing EOR operator with a Class II permit are simply not significant, particularl y when compared to the potential revenue from the sale of the produced oil, as provided b y EPA calculations in the Energy Information Administration (EIA) for subpart RR rules. **Response 6.3 -**  **195:** The BSER determination and regulatory impact analy sis for this rule relies on GS in deep saline formations. 31 However, the EPA also recognizes the potential for sequestering CO 2 via EOR and allows the use of EOR as a compliance option. The EPA agrees with the commenter’s assertion that subpart RR re quirements will not result in EOR operators avoiding the purchase of CO 2 from affected EGUs. The cost of compliance with subpart RR is not significant enough to offset the potential revenue for the EOR operator from the sale of produced oil for CCS project s that are reliant on EOR. First, the costs associated with subpart RR are relativel y modest, especiall y in comparison with revenues from an EOR field. In the economic impact analy sis for subpart RR, the EPA estimated that an EOR project with a Class II permit would incur a first year cost of up to $147,030 to develop an MRV plan, and an annual cost of $27,787 to maintain the plan; the EPA estimated annual reporting and recordkeeping costs at $13,262 per year. 32 Monitoring costs are estimated to range from $ 0.02 per metric ton (base case scenario) to approximately $2 per metric ton of CO 2 (high scenario). Using a range of scenarios (that included high end estimates), these s ubpart RR costs are approximately

three to four percent of estimated revenues for an average EOR field, indicating that the costs can readil y be absorbed. 75 FR 75073. Furthermore, there is a demand for new CO 2 by EOR operators, even beyond current natural sourc es of CO 2
. For example, in an April 2014 study , DOE concluded that future development of EOR will need to rel y on captured CO 2 . 33 Thus, the argument that EOR operators will obtain CO 2 from other sources without triggering subpart RR responsibilities, which assumes adequate supplies of CO 2 from other sources, lacks foundation. In addition, the Internal Revenue Code section 45Q provides a tax credit for CO 2 sequestration which is far greater than subpart RR costs. 34 Section 45Q(a)(1) allows a credit of $20 per metric ton of qualified CO 2 that is captured b y the taxpayer at a qualified facility , disposed of by the taxpayer in secure geological storage, and not used by the taxpayer as a tertiary injectant. Section 45Q(a)(2) allows a credit of $10 per metric ton of qualified CO 2 that is captured b y the taxpayer at a qualified facility , used by the taxpayer as a tertiary injectant in a qualified enhanced oil or natural gas recovery

project, and disposed of b y the taxpayer in secure geological storage. The section 4 5Q credit for calendar ye ar 2015 is $21.85 per metric ton of qualified CO 2 under section 45Q(a)(1) and $10.92 per metric ton of qualified CO 2 under section 45Q(a)(2).
31 The EPA anticipates EOR projects may be early GS projects because these formations have been previously we ll characterized for hydrocarbon recovery, likely already have suitable infrastructure (e.g., wells, pipelines, etc.), and have an associated economic benefit of oil production. 32 Subpart RR costs are presented in 2008 US dollars. 33 “Near Term Projections of CO 2 Utilization for Enhanced Oil Recovery”. DOE/NETL
- 2014/1648. April 2014. 34 http://www.irs.gov/irb/2009
- 44_IRB/ar11.html and http://www.irs.gov/irb/2015
- 26_IRB/ar14.html.6
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**Comment 6.3 -**  **196:**
. Commenters 9664 and 9514 stated that as proposed, EPA ’ s rule text does not impose any

additional requirements on the affected facility to demonstrate that the CO 2 has in fact been transferred to a facility that is compliant with subpart RR, that would be incorporated for example into its PSD and Title V permi ts for the facility . The requirement that the emitting EGU assure that captured CO 2 is managed at an entity subject to subpart RR of the GHG reporting rules is exclusively an element of enforcement of the EGU standard. Commenters 9514 and 9664 requested revisions to 40 CFR 60.46Da(h) &(i) (concerning reporting and recordkeeping requirements). The commenters recommended amending 40 C.F.R. section 60.46Da(h)(5) in order to clearl y establish an enforceable requirement that owners and operators of projects inj ecting CO 2 underground that are permitted under UI C Class II and that receive CO 2 captured from EGUs to meet the proposed performance standard will also be required to submit and receive approval of a subpart RR MRV plan and report under subpart RR. The c ommenters interpreted that the EPA means, by using the term “ GS ” in the regulatory text, to refer to any kind of sequestration, whether b y i njection into a Class VIpermitted well or by injection for enhanced oil recovery via a Class II permitted well. How ever, the commenters noted the term “ GS ” is a defined term in the Safe Drinking Water Act UIC program context that is limited to CO 2 injection for the primary purpose of long
- term containment from the atmosphere, and does not encompass CO 2 injection for th e primary purpose of enhanced oil recovery , even where incidental long
- term containment of the injected CO 2 occurs as a result of that EOR activity
. As a result, the commenters provided the following suggested revisions: “ If yo ur affected unit captures CO 2 to meet the applicable emissions limit, your affected unit must use either (i) onsite or offsite GS, pursuant to a permit issued under Class VI of the Safe Drinking Water Underground Injection Program, and that reports in accordance with the requirements of 40 C.F.R. Part 98, subpart RR, or (ii) send the captured CO 2 for use in enhanced recovery of oil or natural gas, through injection permitted under Class II of the Safe Drinking Water Act Underground Injection Program for that purpose and that reports in accordance with the requirements of 40 C.F.R. Part 98, subpart RR. ” Additionally , the commenters stated that it is a necessary part of the documentation of the achieve ment of the emissions standards that such reporting must become a condition of the Title V permit for the facility
. **Response 6.3 -**  **196:** The final rule requires that any affected EGU unit that captures CO 2 to meet the applicable emissions limit must transfer the captured CO 2 to a facility that reports under GHGRP subpart RR, where sequestration is part of the compliance path. In order to provide clarity on the requirement, the EPA reworded the proposed language under §60.5555(f) to use the phrase “If your affected unit captures CO 2 ” in place of the phrase “If yo ur affected unit employ s geologic sequestration”. Thi s revision is not a change from the EPA’s initial intent. The EPA disagrees that the rule does not provide enforceable reporting and recordkeeping requirements related to the amount of CO 2 that is being sent b y an EGU to a facility that is compliant with subpart RR. The revisions being finalized at § 98.427(d) specificall y provide that EGUs that are capturing CO 2 and sending the CO 2 to a facility that is subject to subpart RR “ must retain re cords of CO 2 in metric tons that is transferred to each subpart RR facility”
.6
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See preamble section XII. Implications for PSD and Title V Programs of the preamble for further discussion on PSD and Title V permits. **Comment 6.3 -**  **197:** Commenters 9664 and 9514 asserted that the EPA must add provisions to require any EGU meeting the standard through long
- term containment in a subsurface geological formation (either through GS or in enhanced oil recovery), to provide documentation showing that the volume of captured CO 2 necessary t o achieve the standard has been injected onsite to a facility permitted under the UIC program and reporting under subpart RR, or transferred to a facility that is permitted under the UIC program and reports under subpart RR. Commenters 9664 and 9514 sugge sted the following amendments to Subpart PP reporting requirements at 40 CFR 98.426 to reflect EPA ’ s intent that captured CO 2 will be permanentl y sequestered:

“ Section 98.426 Data reporting requirements. * * * * (h) If you capture a CO 2 stream from an elec tricity generating unit that is subject to subpart D of this part you must transfer the captured CO 2 to a facility or facilities subject to subpart RR of this part, and you must: (1) Report the facility

identification number associated with the annual GHG report for the subpart D facility , (2) Report each facility

identification number associated with the annual GHG reports for each facility to which CO 2 is transferred, and (3) Report the annual quantity of CO 2 in metric tons that is transferred to each facility
. ” **Response 6.3 -**  **197:** The EPA disagrees with the commenter’s suggested changes to 40 CFR Part 98 subpart PP. The suggested change would require all EGUs who capture CO 2 – new, modified, and existing

– to send all of the cap tured CO 2 to a facility subject to 40 CFR Part 98 subpart RR (Geologic Sequestration of Carbon Dioxide). The EPA believes that the current language in 40 CFR Part 98 is appropriate because the GHGRP covers not only EGUs that are subject to the NSPS, but al so existing EGUs . It also allows EGUs to send some captured CO 2 to other end uses. **Comment 6.3 -**  **198:** Commenter 9766 stated the EPA has ample authority to establish monitoring and reporting requirements under Section 111 and therefore is not restricted only to the existing Greenhouse Gas Reporting Program to ensure proper monitoring and reporting of the disposition or fate of CO 2 once transferred from an affected EGU. **Response 6.3 -**  **198:** The EPA agrees that it has the authority to establish reporting requirements under Section 111 for EGUs
. However, the EPA believes that the existing UI C and GHGRP requirements help ensure that sequestered CO 2 will remain in place, and provide the monitoring mechanisms to identify

and address potential leakage using SDWA and CAA authorities.6
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**Comment 6.3 -**  **199:** Commenter 1637 stated that there are onl y requirements that the source report under the GHG reporting rule 40 CFR 98 subpart RR if it is disposed onsite or subpart PP if disposed offsite. This reporting provision only requires a report of where it goes. It could all go to a facility

that simply

releases it to the atmosphere without any penalty to anyone. A requirement to dispose of it o nly to a facility

that is injecting the CO 2 and reporting under subpart RR should be plainly stated. **Response 6.3 -**  **199:** The EPA does not agree with the commenter’s interpretation of the requirements in the rule but does agree generall y with the commenter’s conclusion that th e final rule requires all affected units to send captured CO 2 to a facility that is compliant with subpart RR of the GHGRP. **Comment 6.3 -**  **200:** Commenter 9664 found EPA ’ s intention to require any new fossil fuel
- fired boilers or IGCC employing CCS to meet the standard to sen d captured CO 2 only to a facility

that reports under subpart RR is reasonable and stated that the EPA properl y relies on the subpart RR MRV plan to verify

that the CO 2 captured from an affected unit is injected underground for long
term containment. The commenter stated that for long
- term containment occurring incidental to or in addition to EOR operations, a UI C Class II permit and the CAA subpart RR rules establish a similar framework and that since in the near term it is highly likel y that EOR will be used to isolate captured anthropogenic CO 2 from atmospheric release. It is therefore important for the EGU operator subject to this rule, be able to demonstrate that captured CO 2 is sent either to a Class VI GS facility

or to a Class II EOR facility reporting under subpart RR. The commenter further stated that EOR using mined natural CO 2 presents the same risks of CO 2 to atmospheric release, as does the use of captured CO 2 from a power plant, and for that reason, and because there are no significant ec onomic or technical impediments to requiring all EOR activity to report using subpart RR, the commenter urges the EPA to revisit the UU v. RR distinction, in the context of its reporting rules, and require RR reporting for all enhanced oil recovery activity permitted under UI C Class II. **Response 6.3 -**  **200:** The EPA appreciates the commenter’s shared view that rel yi ng on subpart RR to verify

that the CO 2 captured from an affected unit is injected underground for long
- term containment is reasonable . The EPA agrees, and the final rule requires, that regardless of the class of well, Class II or Class VI , any facility receiving CO 2 from an EGU that is capturing CO 2 to meet the standards of this rule must comply with subpart RR requirements. The EPA does not agree with the commenter’ s suggestion to require all EOR facilities to report under subpart RR, and the comment is beyond the scope of this rulemaking in any case. Should the EPA be deemed to be required to answer the comment, the EPA maintains that the current subpart UU and subp art RR monitoring and reporting requirements are appropriate
. **Comment 6.3 -**  **201:** Commenter 10618 stated that reporting tools upon which the EPA is rel yi ng have never been used. According to the commenter (10618), for calendar year 2012, onl y two facilities submitted any

inf ormation to EPA ’ s GHGRP for carbon injection activities. Both of these facilities have been granted research and development exemptions for GHG reporting, and both of them reported only the volume of GHGs received at the facility under subpart UU, not6
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the detailed information required b y subpart RR. The commenter (10618) continued that there were no estimates of the amounts of GHGs actually successfull y sequestered, and neither facility has developed the kind of monitoring protocols required under subpart RR. Similarly , commenter 10095 stated the EPA cannot ignore that no injection site, of any size to date, has demonstrated the injection, storage, and monitoring of CO 2 under subpart RR requirements. According to the commenter (10618), the remaining faciliti es listed in EPA ’ s reporting tool are only subject to subpart UU, and are onl y required to report volumes of “ new ” CO 2 received at the facility , not the amounts that are used in, recovered, and recycled through EOR or other operations, nor any amounts that may be emitted from those operations. As a result, the commenter stated that no useful information about the actual amounts of CO 2 in recovered oil and gas, or emitted to the surface in connection with an EOR operation, has ever been submitted to the EPA
. Based on this information, the commenter (10618) concluded that the EPA has no basis for its assumptions regarding the ability of EOR operators to successfully design a monitoring program that would meet the requirements of subpart RR. One commenter (9666) stated that none of the 1,000 million metric tons of CO 2 injected to date have been subject to subpart RR. About 120 million have been reported to the EPA since the reporting rules took effect beginning in 2011, all of which has been r eported under subpart UU and not a single ton has come under the subpart RR rules. There are no approved MRV plans for CO 2 injection in EOR operations for reporting under subpart RR. Hence, rather than being “ adequatel y demonstrated ” , the subpart RR rules and procedures are unused, uncertain and unworkable for EOR operations. **Response 6.3 -**  **201:** The EPA disagrees that subpart RR is unworkable. First, subpart RR is built upon an understanding of the mechanisms b y which CO 2 is retained in geologic formations, which are well understood and proven. See Preamble section V.N.3. Second, i nternational e xperience with large scale commercial GS projects has demonstrated through extensive monitoring programs that large volumes of CO 2 can be safel y injected and securel y s equestered for lon g periods of time at volumes and rates consistent with those expected under this rule. This experience has also demonstrated the value and efficacy of monitoring programs to determine the location of CO 2 in the subsurface and detect potential leakage throu gh the presence of CO 2 in the shallow subsurface, near surface and air. These projects have demonstrated that comprehensive monitoring can be accomplished at saline and EOR sites. With respect to EOR, and as discussed in Preamble section V.N.3, CO 2 from th e Great Plains Synfuels plant in North Dakota has been injected into the Wey burn oil field in Saskatchewan Canada since 2000. Over that time period the project has injected more than 16 million metric tons of CO 2 , with extensive monitoring by

U,S. and inte rnational partners which has demonstrated that no leakage has occurred. The EPA also notes that the DOE has created a network of seven Regional Carbon Sequestration Partnerships (RCSPs) to deploy large
- scale field projects in different geologic settings ac ross the country to demonstrate that GS can be achieved safely , permanentl y, and economicall y at large scales. InApril 2015, DOE announced that CCS projects supported by the department have safely

and permanentl y stored 10 million metric tons of CO 2 . 35

35 http://energy .gov/articles/milestone
- energy- department
- projects
- safel y- and
- permanently
- store 10
- million
- metric
- tons6
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**Comment 6.3 -**  **202:** One commenter (10095) noted that the EPA references the geologic storage opportunities in Canada and Dakota Gasification sy nthetic natural gas plant ’ s utilization of EOR in the Wey

burn oil field in Saskatchewan, Canada. According to the commenter, if the E PA intends to require any reporting, much less subpart RR, the EPA must elaborate on how it intends to enforce reporting requirements in other countries or eliminate these potential storage opportunities and plants from the Agency ’ s anal ys is. **Response 6.3 -**  **202:** The co mmenter appears to misunderstand the discussion of the Great Plains Sy nfuels plant in North Dakota and Wey burn oil field in Saskatchewan, Canada, which provides an example of how geologic sequestration has been demonstrated
. CO 2 from Dakota Gasification has been injected into the Wey burn oil field in Saskatchewan Canada since 2000. Over that time period the project has injected more than 16 million metric tons of CO 2 . It is anticipated that approximately

40 million metric tons of CO 2 will be permanently sequestere d over the lifespan of the project. Extensive monitoring by U.S. and international partners has demonstrated that no leakage has occurred. **Comment 6.3 -**  **203:** One commenter (10618) stated that it appears that 85 facilities listed as being subject to subpart UU required no “ n ew ” CO 2 (i.e., not the amounts that are used in, recovered, and recycled through EOR or other operations, nor any amounts that may

be emitted from those operations) for their operations during the entire ye ar, leading one to question the availability

of EO R opportunities for the large amounts of CO 2 that would be captured at even a single, partially

controlled coal
- fired steam generating unit. Based on this information, the commenter (10618) concluded that the EPA has no basis for its assumptions regarding the availability

of sequestration at EOR operations. **Response 6.3 -**  **203:** 40 CFR Part 98 Subpart UU requires the reporting of the amount of CO 2 received for injection
. The data element referenced by the commenter was previously determined to be confidential business informatio n ( CB I) at the facility level . 77 FR 48072 (August 13, 2012) Therefore the data is not made available on a facility- by
- facility basis
. The amounts reported b y facilities are CBI and not zero. According to data reported to the GHGRP, approximately

60 million metric tons of CO 2 were supplied to EOR in the United States in 2013. 36 **Comment 6.3 -**  **204:** Commenter 9196 stated that the proposed rule relies heavil y on the potential for power plants to sell CO 2 to EOR operators as a means of defraying the tremendous costs of CCS, however, EOR operators are signaling that the subpart RR requirements in the proposed rule may be prohibitive. Broad coalition of groups, from EOR operators to electric power providers, has raised c oncerns about EPA ’ s plans. The commenter requested that the EPA address the following concerns:
a. Please explain in detail the new requirements for EOR operators that would accept CO 2 from power plants?

36 Greenhou se Gas Reporting Program, data reported as of August 18, 2014.6
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b. Have you spoken with any groups potentiall y imp acted b y the new subpart RR reporting requirements? How have you taken their concerns into consideration?
c. Would reporting under subpart RR potentially trigger the transition of an EOR well from Class II to Class VI under the UIC program
- as EPA draft guidance suggests? d. A significant part of EPA's economic justification for the proposed rule relies on the assumption that the CO 2 from power plants will be a valued commodity used in EOR operations
. How do the economics of the proposed rule change if this is no longer an option?
e. Can you commit that EPA will not use reporting under subpart RR to push any EOR operations into Class VI
. **Response 6.3 -**  **204:** The EPA does not agree with the commenter’s statement that the proposed rule relies heavily

on the potential for power plants to sell CO 2 to EOR operators. EOR facilities may facilitate earl y mover projects, but the proposal and final rule rel y on CO 2 being sent to deep saline formations, as indicated b y the discussion in the preamble and the Regulatory Impact Analy sis. The EPA also offers the following responses to the commenter’s questions. a. Under the rule, any facility receiving CO 2 from an EGU that is capturing CO 2 to meet the standards of this rule must comply with the existing requirements of subpart RR. b. Subpart RR of the Greenhouse Gas Reporting Program is not new
. Rather, the regulations promulgating Subpart RR were finalized in 2010
. The EPA reviewed and responded to public comments as part of the rulemaking that promulgated the Subpart RR requirements
. As part o f the notice
- and
- comment process of this rule, the EPA has reviewed and considered public comment on the proposal
. c. Reporting under subpart RR does not trigger the transition of a Class II well to a Class VI well. See preamble section V.N. 5 .a. d. Facilities using carbon capture are doing different things with the captured CO 2 , ranging from EOR to storage to using it for food products. While it is true that selling captured CO 2 for EOR can generate revenue and help offset the costs of capturing carbon, this do es no t mean plants can only build in areas near EOR
. Inestimating costs for the proposed rule, the EPA considered various scenarios. See the Regulatory Impact Anal ys is for more discussion on the scenarios which the EPA considered and their estimate impact s. In estimating impacts, and in assessing costs for purposes of determining if partial CCS is BSER adequately demonstrated, the EPA relied conservatively on the case where CO 2 would be sent to a deep saline GS formation. Therefore, the commenter is simply incorrect in stating that EPA’s economic justification for the rule relies on the assumption that the CO 2 from power plants will be used in EOR operations. e. An EOR project may

be permitted as UIC Class II and report under Subpart RR
. The regulatory

provisions regarding transitioning from UI C Class II to UIC Class VIare set6
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forth at 40 CFR 144.19
. Reporting under Subpart RR of the Greenhouse Gas Reporting Program is not one of the factors specified in 40 CFR 144.19(b)
. **Comment 6.3 -**  **205:** One commenter (1 0034) stated that the information collected through the GHGRP can be used to measure some of the agency's anticipated outcomes. **Response 6.3 -**  **205:** The EPA agrees with the commenter that the information collected through th e GHGRP can help measure and track some of the EPA’s anticipated outcomes . The EPA is finalizing changes to the reporting requirements of subpart PP of the GHGRP to help track these outcomes. **Comment 6.3 -**  **206:** Commenter (4733) stated that the EPA issued subpart RR to complement the UI C Class VI Rule. Compliance with subpart RR will allow GS operators to provide proof of sequestration, eliminating another barrier to CCS. Similarly, commenter 9035 stated that the EPA has provided a pathway for demonstrating the geologic storage of CO 2 utilized in EOR by meeting certain requirem ents of the Underground Injection Control Program and the Greenhouse Gas Reporting Program. **Response 6.3 -**  **206:** The EPA agrees that subpart RR complements the UI C Class VI regulations
. The EPA also agrees that subpart RR will provides a mechanism for demonstrating the efficac y of GS, including in conjunction with EOR. **Comment 6.3 -**  **207:** Commenter 9666 stated the reporting obligations under subpart RR are poorly defined, and may

discourage CO 2 injection facilities from accepting CO 2 generated b y sources subject to the proposed NSPS, particularly EOR facilities, which are not currently required to report under subpart RR. According to the commenter, because no entity has reported data to the EPA under subpart RR, there is lingering uncertainty as to what would be required from a subpart RR monitori ng, reporting, and verification plan. O ther commenters (9201, 9683, 10036, 10098, 10137, 9731, 10095) also expressed concerns with the potential uncertainty and risks compliance with subpart RR creates for EOR operators. One commenter (10098) opined that requirements to comply with subpart RR opined that this is problematic because there are no standards governing what may constitute an incomplete or otherwise unacceptable MRV plan, nor any timeline for approval, creating a completel y open ended and undefined regulatory framework. **Response 6.3 -**  **207:** The EPA does not agree that the reporting obligations under subpart RR are poorly defined. There are clearl y defined reporting requirements outlined in 40 CFR Part 98.446. As part of these requir ements, the EPA has provided flexibility to reporters in regards to annual monitoring reports (40 CFR 98.446(a)(12)); the EPA views this as a way to balance the burden in reporters as each sequestration site is unique as opposed to a uncertain requirement. There are also clearly

defined requirements for what must be included in a complete and acceptable subpart RR MRV Plan . The EPA identified all required components in a subpart RR MRV Plan in 40 CFR Part 98.448(a). In outlining these requirements, EPA’s a pproach allows for site
- specific flexibility

for MRV plans and does not prescribe particular monitoring technologies. The approach also allows the owner or operator to leverage the site characterization, risk6
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assessment, and/or monitoring required b y other authorities as the foundation for demonstrating compliance with the MRV plan requirements of 40 CFR Part 98, subpart RR. The evaluation criteria and what would result in approval for a subpart RR MRV Plan are highly f lexible. While the EPA recognizes th at this may be mistaken as uncertainty, the geology and other conditions among facilities conducting GS vary . To provide more clarity for reporters, the EPA provided information in the General TSD of the Subpart RR final rule (Docket ID EPA
HQ
- OAR
- 2009
- 092 6) on the technical evaluation of MRV plans, including illustrative examples describing the types of information that may be included in the MRV plan to fulfill the regulatory

requirements at 40 CFR 98.448. In regards to the comment that asserted that there is not a timeline for approvals MRV plans, the EPA does not agree. 40 CFR 98.448(b) outlines a clear timeline for MRV Plan submissions, reviews, and iterati ons between the EPA and reporters (e.g., specifyi ng the number of day s allowed for each step in the process)
. All of these components of subpart RR results in a clearl y defined regulatory framework for accounting for GS. **Comment 6.3 -**  **208:** Commenter 10137 noted all decisions (about subpart RR MRV plans) are open to liti gation by

any “ interested person ” under Part 78 litigation procedures, and hence, prior to closing financing to allow construction to begin, the developer of a new power plant seeking to implement carbon capture and storage as the compliance tool for meeting the new standards is unlikely to be able to obtain a commitment from an EOR operator to become subject to undefined and open
- ended requirements that may extend decades into the future. **Response 6.3 -**  **208:** The commenter is correct that subpart RR MRV Plan final decisions may be appealed to EPA’s Environmental Appeals Board by an interested person per the requirements under Part 78. However, the EPA does not agree that this process prevent s EGUs from obtaining a commitment from EOR operat ors. W ithout the administrative appe als process, the reporters’ and interested person’s only option becomes litigation, which the EPA be lieves would be more disruptive and costly , and delay implementation of MRV plans further. Additionally, while the EPA anticipates that many early geologic sequestration projects may be sited with EOR projects, this rule relies on CO 2 being sent to deep saline formations. Therefore, the EPA does not foresee the commenter’s assertion as a potential deterrent to the overall compliance with this rule. **Comment 6.3 -**  **209:** One commenter 10098 stated that once approved, the MRV plan must be maintained under the rule for a duration determined by the EPA, and not the EOR operator. Further, the commenter noted that subpart RR provides that operational changes
- even the drilling of a new injection well that had not previously been identified
- can start the whole MRV approval process over again. **Response 6.3 -**  **209:** Under subpart RR, the EPA has provided clear requirements regarding the length of time for which a GS facility must report and maintain an MRV plan under subpart RR. Under subpart RR facilities may discontinue reporting when they can demonstrate through monitoring and modeling that the injected CO 2 is not expected to migrate in the future in a manner likel y to result in surface leakage or when the f acility has closed pursuant to its Class VI6
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permit, which is sufficient evidence to ensure to the EPA that there is no risk of CO 2 leakage to the surface. In setting these requirements, the EPA can ensure it has access to accurate and complete data that represents the amount of CO 2 sequestered at a GS site. An MRV plan may

require revision and resubmittal if a material change was made to monitoring and/or operational parameters that was not anticipated in the original plan, if there has been a change in the permit class of the reporter’s UI C permit, if the reporter is notified by the EPA of errors in their MRV plan or annual monitoring report, or if the reporter chooses to revise their MRV plan for any other reason . The EPA anticipates that MRV plan resubmis sions will be a result of isolated changes to the MRV plan, hence the review and approval process and timeframe will be reflective of that. **Comment 6.3 -**  **210:** Commenter 10095 questioned how the EPA would deal with instances of non - compliance if CO 2 complying with subpart RR is comingled in a pipeline with CO 2 that is not complying with subpart RR, given that NSPS requires CO 2 from an EGU to comply with subpart RR of the mandatory GHGRP. **Response 6.3 -**  **210:** If inj ection occurs offsite, the rule requires captured CO 2 to be transferred to a facility that reports in accordance with GHGRP Subpart RR
. The hypothetical raised b y the commenter ( CO 2 being transferred in a common pipeline) would not in itself cause non compliance with the NSPS. **Liability Comment 6.3**  **- 211:**  Commenters 9381, 9425, and 9666 stated that, to date, the insurance industry has provided only

short
- term policies that cover a few years of CCS operations with limited options for renewal, potentially making financing of full
- scale CCS projects very difficult
. According to the commenters, at this time there is no guarantee that there will be sufficient insurance coverage available to manage risks associated with long
- term storage of CO 2 . Commenter 9683 asserted that, although insurance may be available during the operation and p ost - injection site care phase, commercial risk management instruments are not available for post - closure liabilities
. Similarly , Commenters 9780 and 10239 stated that there are unanswered questions regarding long
- term - liability and insurance. **Response 6.3 -**  **211:** In general, the risks associated with geologic sequestration of CO 2 are expected to be highest during the operational phase of the project, when the commenter notes that insurance or other financial mechanisms for risk management would likely be available
. The risks are then expected to decrease over time
. The 2010 Report of the Interagency Task Force on Carbon Capture an d Storage discusses how scientific research has concluded that there is substantial evidence that CO 2 will remain in place for extended periods if the injection site is chosen properl y, injection operations are conducted according to regulations, the site is monitored adequatel y, and post - injection and closure operations are conducted appropriatel y. 37 The EPA ’s existing regulations for geologic sequestration provide a framework to assure the safety and efficacy of GS, which can help assure lenders considering financing sequestration

37 Report of the Interagency Task Force on Carbon Capture and Storage (August 2010), page 72.6
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facilities
. Although the commenters focus on the use of insurance to cover long
- term liabilities, there are other financial mechanisms that could cover post
- closure liabilities
. Furthermore, first mover projects are in operation and have been able to obtain needed financing
. **Comment 6.3 -**  **212:** Commenters 9407 and 10052 stated that legal and finan cial liability associated with geologic sequestration is uncertain, increasing the level of risk associated with implementation of CCS. Commenter 9666 stated that the current federal and state regulatory framework continues to create significant uncertainties as to how risks to human health or private property in the event of leakage will be managed, and how liability will be allocated in the event of a leak
. Commenters 9197 and 9596 noted that experts and stakeholders have raised significant questions abo ut the long
- term feasibility

of sequestering large amounts of CO 2 underground and who will be liable for upsets or adverse changes to the reservoir of stored CO 2 . Commenter 10086 stated that many liability issues need to be resolved before CCS can be deeme d adequately demonstrated, including (1) who is liable for the captured CO 2 , (2) when does ownership of and liability for CO 2 transfer during the capture, transport, and storage process, and (3) what are the ramifications if the transportation and storage components fail. Commenter 9666 also stated that repositories located across state lines will introduce jurisdictional questions
- particularl y as CO 2 plumes migrate. According to Commenter 9666, legal precedent addressing such complex subsurface issues does not exist. CO 2 - derived liabilities are not fully

defined and there is little basis for resolving disputes. The commenter noted that the legal frame work which exists has evolved from oil and gas rights and application of EOR may

not apply to larger CO 2 disposal rates and the timeframe for monitoring CO 2 from sequestration covered under the proposal. **Response 6.3 -**  **212:** The 2010 Report of the Interagency Task Force on Car

bon Capture and Storage discusses how present scientific research has concluded that there is substantial evidence that CO 2 will remain in place for extended periods if the injection site is chosen properl y, injection operations are conducted according to regulations, the site is monitored adequately , and post - injection and closure operations are conducted appropriatel y . At the Federal level, the EPA develop ed the UI C Program to regulate the underground injection of fluids in a manner that ensures protecti on of USDWs. Although the regulations for Class VI and Class II injection wells are designed to ensure protection of USDWs from endangerment, the practical effect of these complementary technical requirements is that they also prevent releases of CO 2 to th e atmosphere. These requirements decrease the likelihood of the events of concern raised b y the commenters, including leakages, upsets, adverse changes to the reservoir, and plume migration
. Furthermore, EPA’s regulations provide required actions for remediation in the event of a leak, ensuring minimal impact on human health and the environment in the surrounding area . The EPA has concluded that the UI C requirements will protect human health and the environment from potential risks associated with CO 2 streams and prevent migration of sequestered CO 2 both to underground sources of drinking water and to the atmosphere over the long
- term .6
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**Comment 6.3 -**  **213:** Commenter 9666 stated CCS presents a unique problem because the underground storage of CO 2 might affect the flow and location of groundwater and the disruption of on
- site groundwater wells, especiall y those used by public water s ys tems, might expose the owner of the CCS operations to liability
. Commenter 10023 stated that CO 2 storage raises numerous permitting and regulatory issues, including liability related to groundwater effects
. **Response 6.3 -**  **213:** The EPA does not believe that this presents a unique problem or an insurmountable challenge
. Similar to other commercial operations that create risks to human health or the environment, geol ogic sequestration of CO 2 will need to be p erformed in a manner that does not endanger USDWs . The EPA ’s UI C program, promulgated under the authority of the Safe Drinking Water Act, establishes a risk management framework to protect underground sources of drinking water through requirements ensuring that geologic sequestration wells are appropriatel y sited, constructed, tested, monitored, and closed . The EPA has concluded that the UI C requirements will protect human health and the environment from potential risks associated with CO 2 streams . **Comment 6.3 -**  **214:** Commenter 8966 stated the realm of liability is particularl y broad due to recognition among experts that much more investigation is necessary to understand the effects of carbon sequestration on health and groundwater quality . Yet, the commenter stated, th e proposed rule provides no indemnification or transfer
- of
- title safeguards, nor makes any effort to clarify the bounds of potential liability . The commenter noted that this liability may be a barrier to CCS development. The commenter also stated because o f this uncertainty, new facilities implementing CCS would likely be required to install multiple monitoring wells to ensure the integrity of the reservoir. The commenter referenced the AEP Mountaineer Plant, noting that for a commercial
- scale CCS sy stem, m onitoring costs are likel y to be great, corresponding to the greater potential liability

associated with storage of millions of tons of CO 2 underground
. **Response 6.3 -**  **214:** Defining the scope of liability or limiting liability

through indemnification or transfer
- of

- title at sequestration facilities is beyond the scope of this rulemaking . The EPA does not believe that lack of a liability limit is a major impediment to near
- term deploy ment of CCS, as stated in the 2010 Report of the Interagency Task Force on Carbon Capture and Storage
. With respect to AEP’s experience with the Mountaineer demonstration project, notwithstanding difficulties, the company was able to successfull y dig wells, and safel y inject captured CO 2 . Moreover, the company i ndicated it fully expected to be able to do so at full scale and explained how. 38 The EPA notes further that a monitoring program and its associated infrastructure (e.g., monitoring wells) and costs will be dependent on site
- specific characteristics, such as CO 2 injection rate and volume, geol ogy , the presence of artificial penetrations, among other factors. It is thus not appropriate to generalize from AEP’s experience (especiall y given that the site was a retrofit to an existing source, not initially sited with sequestration in mind) , and ass ume that other sites will require the same number of wells for site characterization or injection. In this regard,

38 See AEP FEED Study at pp. 36
- 43. The company likewise explained the monitoring regime it would uti lize to verify containment, and the well construction it would utilize to guarantee secure sequestration. Id. at pp. 44
- 54.6
- 133

we note that the ADM and FutureGen permits for Class VIwells involved far fewer injection wells than AEP references. 39 **Comment 6.3 -**  **215:** Commenter 9666 stated that assigning responsibility for seismic disruption damages caused b y carbon injection may be difficult because of scientific uncertainty and lack of legal precedent. The commenter noted that in the case of natural seismic action leading to future CO 2 le akages, assigning liability based on fault may

be impossible and lead to difficulty in handling any resulting damages. **Response 6.3 -**  **215:** EPA’s UI C regulations help ensure that CO 2 injection activities will not result in significant seismic activity
. The permitting process i dentifies risks and eliminates unacceptable sites prior to injection
. The regulations specify criteria for site selection and monitoring that must be met before a site can be considered suitable for CO 2 injection
. See Preamble section V.N.1. **Comment 6.3 -**  **216:** Commenters 942 3, 9426, 10036, and 10618 stated that among the legal and regulatory

issues that must be overcome before CCS technology for EGUs can move forward is the current lack of clarity surrounding long
- term stewardship and liability for stored CO 2 . Commenters 9407 and 10952 stated that the proposal and supporting information in the rulemaking docket lacks information that the EPA has considered key legal issues that need resolution, such as long term liability . The commenter references the administration's task force report on CCS projects as previously identified concerns that should be addressed. Similarly , Commenter 10043 stated that the EPA does not know the long
- term effects or the risks of storing large amounts of CO 2 underground and asserted that the uncertainty associated with this long
term liability

creates an immeasurable risk. Commenter 9683 cited a 2011 National Coal Council report to the Secretary of Energy that stated that “The management of long
- term liability risks is a critical consideration for CCS projects
. In terms of supporting the broad deplo ym ent of CCS across the coal based generation fleet, uncertainty

regarding long
- term liability remains a challenge.” Commenter 9396 cited a 2013 Congressional Rese arch Service anal ys is of the status of CCS, noting “ liability, ownership, and long
- term stewardship for CO 2 sequestered underground are issues that would need to be resolved before CCS is deployed commercially
. ” The commenter also stated that a key issue in the siting of the FutureGen post combustion capture and storage demonstration project was the extension of liability

coverage b y the State of Illinois for claims associated with underground storage, however, such liability extensions by

state government s appear to be a thing of the past, leaving private entities uncertain as to how to resolve future legal liability
. Similarly, Commenter 9597 stated that CCS is challenged b y long
- term storage concerns regarding indemnification of potential releases of sto red materials.

39 The FutureGen UIC Class VI injection well permits (four in total) require nine monitoring wells. http://www.epa.gov/r5water/uic/f uturegen/. The Archer Daniels Midland UIC Class VI injection well permit issued in September 2014 (CCS2) requires five monitoring wells and the Archer Daniels Midland UIC Class VI injection well permit issued in December 2014 (CCS1) was permitted with two mo nitoring wells. http://www.epa.gov/region5/water/uic/adm/.6
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Commenter 8349 stated U.S. Congress has not yet considered or taken any action on the long term liability

issues associated with long term storage of CO 2 . Commenter 9666 asserted that only four States have developed any additional programs to address long
- term care. **Response 6.3 -**  **216:** The EPA notes that liability issues have not proved impediments to issuing of Class VI permits to date, as illustrated by the various permits issued to Archer Daniels Midland and FutureGen. EOR with anthropogenic CO 2 likewise has been conducted successfully for decades without such issues proving an insurmountable obstacle
. See also responses immediately

above
. In addition , there are compliance alternatives to the promulgated standards that do not involve sequestration, so that th e standard can be satisfied in any case. **Comment 6.3 -**  **217:** Commenter 10618 stated that the Class VIUI C regulation should not be misconstrued as having addressed all barriers to the geologic sequestration of CO 2 . The commenter cited a 2014 Congressional Research Service rep ort discussing EPA's authority to protect underground sources of drinking water but not other major issues such as the long
- term liability for injected CO 2 , regulation of potential emissions to the atmosphere, and legal issues if the CO 2 plume migrates und erground across state boundaries. **Response 6.3 -**  **217:** The EPA agrees with the commenter that the Class VI UI C regulations did not address all barriers to commercial deplo ym ent of geologic sequestration of CO 2 . For example, to address other barriers, the EPA promulgated GHG Reporting Program Subpart RR and the conditional exclusion from RCRA Subtitle C of CO 2 streams that are s equestered in a Class VIwell
. Specific responses to the three example barriers raised b y the commenter are discussed in detail in other responses within this section
. **Comment 6.3 -**  **218:** Commenter 9683 asserted that a key concern for power generators is the applicability

of CERCLA to the CO 2 generated at their facility and transferred to a third party . Commenter 9683 stated that generators were particularl y concerned because CERCLA applies a joint, strict, and several liability scheme
. Furthermore, the Commenter noted that in the UI C Class VIproposed rule the presence of materials other than CO 2 in CO 2 injectate could cause the material to be considered a “hazardous s ubstance,” the term, according to the commenter, that triggers liability

under CERCLA
. **Response 6.3 -**  **218:** The EPA acknowledges that although CO 2 itself is not listed as a hazardous substance under CERCLA, the CO 2 stream injected into a geologic sequestration well could c ontain a listed hazardous substance or may mobilize substances in the subsurface that could react with ground water to produce listed hazardous substances
. Whether such substances may result in CERCLA liability from a GS facility

depends entirel y on the co mposition of the specific CO 2 stream and the environmental media in which it is stored (e.g., soil or ground water)
. However, CERCLA exempts from liability under CERCLA section 107, 42 U.S.C. 9607, certain “Federall y permitted releases” as defined in CERCLA, 42 U.S.C. 9601 (10), which would include the permitted injectate stream as long as it is injected and behaved in accordance with the permit requirements
.6
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**Other CO**  **2 Transport and Geologic Sequestration Legal and Regulatory Issues**  **Comment 6.3 -**  **219:** Commenters 6948, 9 426, and 10137 stated that legal and regulatory barriers must be addressed to complete the development of CCS and allow for it to be commercially viable
. Focusing on the long
- term storage aspect of CCS, Commenters 10024 and 10088 stated that many legal and regulatory

impediments exist
. Commenters 9426 and 10243 asserted that site specific non
- technical issues including permitting, public acceptance, property rights of pore space, pipeline siting and construction, interstate transport and safety, liability, and long
- term closure issues must all be addressed b y the EPA before CCS can be deplo yed. Commenter 10095 listed several legal issues, including pore
- space ownership and long
- term storage liability as discussed by

the Interagency

Task Force on CCS, and pro vided an example highlighting the gaps, uncertainties, and inconsistencies that may be problematic for projects in states without such laws and for projects that would span multiple states. Commenter 10618 asserted that undeveloped regulatory

and legal con siderations may alone prohibit the development and adequate demonstration of CCS projects, citing several assessments that recognize developmental challenges related to legal and regulatory issues, and a survey

of all 50 states and their readiness to regul ate CCS. **Response 6.3 -**  **219:** Legal and regulatory barriers described by

the commenters were thoroughl y discussed by

the Interagency

Task Force on Carbon Capture and Storage, which concluded that such challenges were surmountable . The EPA notes that issues of individual proper ty rights and liabilities will involve site
- specific resolution if and when they arise in particular proceedings
. These issues have not proved impediments to the Class VIprojects pursuing GS , as illustrated b y the cases of Archer Daniels Midland and FutureGen . The EPA has responded specifically to each of the legal or regulatory

issues raised by

the commenters elsewhere in this Section 6. 3 ; see the topics titled Geologic Sequestration Property Rights, CO 2 Transport L egal and Regulatory Issues, Safe Drinkin g Water Act ’ s Underground In jection Control Program and Resource Conservation and Recovery Act , Greenhouse Gas Reporting Program , Li ability, and Other CO 2 Transport and Geologic Sequestration Legal and Regulatory I ssues . **Comment 6.3 -**  **220:** Commenter 9780 supports EPA ’ s determination that EGU responsibility for captured CO 2 ends once the EGU has ensured that the storage or EOR project operator reports under subpart RR, because EGUs should only be responsible for emissions over which they have control. **Response 6.3 -**  **220:** This rulemaking in cludes a numeric emissions standard and a requirement that the emitting EGU assure that captured CO 2 is managed at an entity subject to the GHG reporting rules. **Comment 6.3 -**  **221:** Commenter 8022 stated that the proposed rule is flawed because it requires CO 2 capture only an d does not mandate or regulate sequestration, which the commenter characterized as the onl y component of CCS that might reduce CO 2 emissions generated b y a new source. **Response 6.3 -**  **221:** As already noted , this rulemaking includes a numeric emissions standard and a requirement that the emitting EGU assure that captured CO 2 is managed at an entity subject to the GHG reporting rules. See also preamble section V.N
.6
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**Comment 6.3 -**  **222:** Commenter 10083 stated that there is no precedent for regulating activity beyond the facility

generating CO 2 , nor are the facilities at which sequestration is likely to occur subject to this rule
. The commenter noted that it is significant that parties (e.g., CO 2 sequestration facility

operators), who are responsible for handling the CO 2 after it has been turned over by

the CO 2 generator, are not subject to the rule because it is not practical or practicable for the generator to account for the CO 2 after the generator has turned it over to a third party
. **Response 6.3 -**  **222:** The final standard of performance requires the EGU to transfer the captured CO 2 to an entity

reporting under subpart RR where sequestration is part of the compliance path
. **Comment 6.3 -**  **223:** Commenters 9407, 9600 and 10097 asserted that although the proposal does not seek to regulate or address offsite facilities where transport and sto rage would take place, these components are required to augment the BSER or otherwise captured CO 2 could be subsequently

emitted offsite. Similarly, Commenter 9201 stated that the EPA failed to properl y account for the entirety of the sy stem by focusing o n carbon capture and omitting an account of the transportation and storage components of CCS. Therefore, the commenter asserted that EPA ’ s proposed NSPS is incomplete and cannot be considered BSER. Unless the EPA considers transportation and storage, the c ommenter stated that the NSPS is an arbitrary and capricious application of CAA section 111(b). **Response 6.3 -**  **223:** As already noted , this rulemaking includes a numeric emissions standard and a requirement that the emitting EGU assure that captured CO 2 is managed at an entity subject to the GHG reporting rules. See also preamble section V.N. **Comment 6.3 -**  **224:** Commenter 9683 stated that the proposed rule makes possible the circumstance that a coal
- fired power plant that must run for an area to maintain compliance with ele ctric reliability

requirements, which are binding and enforceable by FERC under the Federal Power Act, could be forced to violate the proposed rule if it was unable to sequester CO 2 due to a leak at the onl y available geologic sequestration facility
. Comme nter 9683 notes that the House Committee on Energy

& Commerce is considering legislation that could address this issue, but the Commenter notes that the legislation under consideration leaves the generating facilities at risk
. The commenter stated that the proposed rule would not encourage CCS unless other laws and regulations are concurrentl y amended to resolve this potential situation
. Commenter 10095 stated that if third parties are willing to accept CO 2 from CCS operations at EGUs, power generators will need to enter into a contract with a third party that would receive the CO 2 and take responsibility for ensuring continuous storage, and under such arrangements, the EGU would be dependent on a third party for both operations and compliance. The commenter added that if the third party cannot or will not accept the CO 2 , the EGU would likel y be forced to shut down, and thus, the risk of contract breach could jeopardize the ability of the EGU to meet electrici ty

demand. According to the commenter the lack of an established mechanism for these ty

pes of legal issues is further evidence of the complexities of relying on CCS when electricity

production is at stake.6
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Commenter 9197 stated the proposed rule does not adequatel y consider the potential for downstream outages to impact EGUs’ ability to consistently

meet the proposed NSPS
- an issue that would not affect the demonstration projects or industrial facilities on which the EPA relies because these facilities can simply shut down when sequestration is not available. According to the commenter, the EPA has not addressed the possibility that a CO 2 pipeline, EOR operator, or geologic sequestration well operator could experience technical or other difficulties that would prevent these third parties from taking a regulated EGU’s CO 2 . Commenter 10095 described the Final Determination of Compliance for HECA's proposed polygen facility , which specifies HECA’s proposed GHG BACT anal ys is for its CO 2 Recovery and Vent Sy stem that includes the ability to vent captured CO 2 during periods when compression, transportation, or the delivery s ys tem is unavailable due to cold gasification block startup, CO 2 compressor or pipeline unplanned outages, or third party CO 2 off
- take issues
. T he commenter urged EPA to consider how these ty pes of risks can impact compliance with the proposed rule
. **Response 6.3 -**  **224:** The EPA believes that the rule provides sufficient flexibility to avoid the compliance issues described by the commenters
. In the event that there i s a malfuncti on condition, the EGU would not be immediately required to shut down or be required to shut down within a certain specified period of time. EGUs that are unable to export their captured CO 2 emissions could continue to operate without capturing their CO 2 emissions in accordance with the terms of their operating permits and in accordance with numerical CO 2 emissions limit to which the facility

is subject
. **Comment 6.3 -**  **225:** Commenter 10083 discussed the difficulties associated with deplo yi ng CCS in the West, such as complexity and time to obtain permits, complexity and costs of assessing storage suitability , and costs of covering liability risks related to transport and injection. **Response 6.3 -**  **225:** The EPA has responded to the issue of permits in the Section 6. 3 topic titled Safe Drinking Water Act’s Underground Injection Control (UI C) Program and Resource Conservation and Recovery Act , geologic sequestration assessment in the Section 6.3 topic titled Geologic Sequestration , and liability in the Section 6. 3 topic titled Li abi lity . The EPA notes that issues of liability

will involve site
- specific resolution if and when they arise in particular proceedings
. **Comment 6.3 -**  **226:** Commenter 9731 stated that the commenter opposes any efforts that would make CO 2 - EOR more costly or burdened b y an unworka ble regulatory

framework. **Response 6.3 -**  **226:** The EPA believes that the Underground Injection Control (UI C) Class VI rule and Subpart RR of the GHG reporting rules do not place an excessive burden on EOR operators . The existing framework offer s an integrated and complementary set of regulations that ensure an appropriate level of verific ation and accounting of CO 2 . **Comment 6.3 -**  **227:** Citing a Congressional Research Service report, Commenter 9423 stated that legal and regulatory

uncertainties may

make broad community

acceptance of CCS a challeng e.6
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According to commenter 9666, public opposition to permitting CO 2 storage sites due to safety related concerns has occurred recentl y in Europe
. The commenter concluded that public acceptance can be a major issue at any proposed site
. **Response 6.3 -**  **227:** Public awareness an d support have been widel y recognized as critical components in the development of new energy infrastructure, including CCS deploy ment . E fforts have been made to design strategies for successful outreach to the public
. For example, under the DOE Regional C arbon Sequestration Partnerships, DOE has been engaging with local communities to educate and inform them about planned pilot and demonstration projects in their areas. DOE’s Best Practices for Public Outreach and Education for Carbon Storage Projects pres ents lessons learned through the planning and implementation of CCS projects, as well as best practices for community engagement. **Comment 6.3 -**  **228:** Commenter 9426 stated that without a strong price signal for CO 2 , only public funding will possibly advance CCS and funding i s highl y uncertain. **Response 6.3 -**  **228:** As discussed in the proposal, the 2010 Interagency Task Force on CCS report recognized that, as an alternative to a strong price signal for CO 2 , a regulatory framework that promoted CCS was a mechanism for encouraging the commercial deploy ment of CCS (79 FR 1480)
. This rule is an important component in developing that framework, which could, even in the absence of a strong price signal for CO 2 , advance CCS
. **Comment 6.3 -**  **229:** Commenter 8949 stated that an environmental and cost impact assessment of the development and implementation of a CCS regulatory structure, either at the federal or state level, should be included in the agency ’s decision making process. **Response 6.3 -**  **229:** In its regulatory impact analy sis, the EPA determined that identifying partial CCS as the BSER for coal
- fired power plants would not have adverse impacts on the power sector, national electricity prices, or the energy

sector . Furthermore, this rule relies on existing regulatory

frameworks under the UIC Program and GHG Reporting Program. **Comment 6.3 -**  **230:** Commenter 1 0618 asserted that the EPA should have listed a new source category that includes all of the affected facilities necessary to effectivel y control CO 2 emissions rather than rel yi ng on the existing source category described under Subpart Da
. The commenter st ated that EPA’s assertion that it is regulating the same source categories currentl y regulated under Subpart Da is inaccurate because those sources do not include the CO 2 transport and sequestration or end use processes necessary to segregate the captured CO 2 emissions from the atmosphere
. Furthermore, Commenter 10618 disagreed with EPA’s reliance on the GHG Reporting Program to track the captured CO 2 that is geologicall y sequestered as a means of avoiding redefining the source category . The Commenter stat ed that without an effective method to establish an enforceable standard for sequestration, such as requirements for successful sequestration and a better reporting tool, EPA ’ s proposal to require capture and reporting of CO 2 emission s is ineffective and arbitrary
.6
- 139

**Response 6.3 -**  **230:** The EPA disagrees with the commenter ’s assertion that it is not regulating the same source categories currently regulated under s ubpart Da because those sources do not include the CO 2 transport and sequestration or end use processes necessary to segregate the captured CO 2 emissions from the atmosphere. The subpart Da requirements for criteria pollutants similarly do not include requirements for transportation and storage of particulate matter, SO 2 scrubber residuals. We have described separate requirements for transportation and storage of captured CO 2 in the preamble section V.N. and elsewhere in this response to comments document . The EPA also disagrees with the commenter’s assertion that there i s no effective method to establish an enforceable standard for sequestration
. Separate regulatory requirements exist under SDWA’s UIC program that regulate the entities involved in geologic sequestration of carbon dioxide
. And the current rule requires that the emitting EGU assure that captured CO 2 is managed b y an entity subject to the GHG reporting rules
. The primary intent of the requirement that the emitting EGU make this assurance is to account for captured CO 2 that is geologicall y sequestered
. See the Section 6. 3 topic titled Greenhouse Gas Reporting Program and preamble section V.N .2 for discussion related to the GHG Reporting Program. **Comment 6.3 -**  **231:** Commenter 9407 stated that there are geographic locations where insufficient EOR and deep well sequestration infrastr ucture prohibits NSPS compliance, but where coal
- fired plants are required to satisfy local needs
. The commenter asserted that the proposal is unlawful because the requirements prohibit source locations where CCS infrastructure is unavailable, despite the location ’ s need for a reliable grid source or economic development. **Response 6.3 -**  **231:** A few states do not have geologic conditions suitable for GS, or may not be located in proximity

to these areas. Where GS capacity is unavailable, electricity demand in those areas can be served by coal
- fired power plants built in neighboring areas with GS. For other of those areas, coal
- fired power plants are either not being built due to state law restrictions , or other available compliance alternatives exist allowing a new coal
- fired power plant meeting the promulgated NSPS to be sited. The EPA has also noted compliance alternatives that will allow affected new facilities to meet the final standard without the use of CCS technologies

– notably by using natural gas co
- firing. **Comment 6.3 -**  **232:** Commenter 8743 argued that EPA’s description of legal prece dent regarding the absence of a requirement under CAA section 111 that a New Source Performance Standard be able to be met b y every new source in the source category misconstrues legislative intent
. Commenter 8743 states that the legal precedent that the EPA relies on, which relates to attaining National Ambient Air Quality Standards, to justify

this assertion is misplaced and cannot be properl y applied to the emissions standards for CO 2 for which no ambient air quality standard or distinct air quality

related value exists
. Commenter 8743 concludes that the EPA has overstepped by disadvantaging large geographical areas that are technically and economically

precluded from CCS, which the commenter believes the E PA acknowledges b y tryi ng to argue that there is no requirement that a New Source Performance Standard be able to be met b y every new source in the source category
. **Response 6.3 -**  **232:** The EPA believes that a new steam generating affected source could meet the promulgated standard and be located anywh ere in the country
. There is available sequestration capacity in most areas of the country, and there are alternative way s a new EGU6
- 140

could meet the standard, not involving sequestration, should a new source decide to locate in an area where these sequestration opportunities are unavailable
. See Portland Cement Ass’n v. EPA , 665 F. 3d 177, 191 (D.C. Cir. 2011), holding that the EPA could adopt section 111 standards of performance based on the performance of a kiln ty pe that kilns of older design would have great difficulty satisfying, since among other things, there were alternative methods of compliance available should a new kiln of this older design be built
. The court also noted that it was highl y unlikely that such a new kiln wo uld ever be constructed and that the EPA could consider this in adopting a standard of performance reflecting a different ty pe of kiln design
. Similarly here, there is significant doubt that a new steam generating unit would be sited in one of the few area s without ready access to sequestration or EOR opportunities (and commenters have supplied no information indicating that such a possibility actually exists)
. Finally , the promulgated standard of performance can be met without capturing CO 2 or sequestering it, using alternative means of control which have no associated geographical constraints
. 

### 6. **3 .**  **6 CCS Is/Is N**  **ot BSER Comment 6.3**  **- 233:**  Commenters 7977, 8032, 8501, 8949, 8973, 9194, 9197, 9318 9422, 9505, 9590, 9596, 9600, 9678, 9683, 10033, 10036, 10050, 10051, 10087, 10618 disagreed with the choice of partial CCS as BSER. Commenters 8973 and 9318 strongl y objected to EPA's consideratio n of "partial CCS" as BSER for new coal plants and new integrated coal gasification/combined cycle (IGCC) plants, as the same technological immaturity , accessibility , and transportation arguments (used for full CCS) can certainl y be made for these units. In addition, the commenter stated that the cost
effectiveness of partial CCS
-- particularl y if involving permanent geologic sequestration and not temporary

enhanced oil recovery

(EOR)
-- is entirely

unproven and not commerciall y available, regardless of type. Commenters 7977, 8501, 9197, 9683, 9677, 10033, 10050 10137, noted that CCS was not adequatel y demonstrated, citing feasibility and costs as additional problems. Commenter 9678 recommended that the EPA adopt standards that are achievable using state
- of
- the
- art technologies. Commenter 10134 stated that the EPA did not properly evaluate the two options of highl y efficient generation technologies and efficiency measures in comparison to CCS. Commenter 9194 noted the need for vendor performance guarantees. C ommenter 10134 stated that the EPA did not properly evaluate the two options of highly efficient generation technologies and efficiency measures in comparison to CCS. Commenters 9422, 9596, 10051 recommended that the EPA reconsider CCS as BSER, and issue a new proposed rule. Commenter 7977 stated that the selection of CCS as BSER for coal
- fired EGUs is arbitrary and capricious. Commenter 10089 provided general support for the proposed rule as a step in the right direction to reduce the greenhouse gas emiss ions of the electric power sector, suggested that CCS may not be BSER, given the cost impacts.6
- 141

**Response 6.3 -**  **233:** First, partial post
- combustion CCS is demonstrated at commercial scale, and has been operated successfully at the Boundary

Dam facility

since October 2014. Permanent sequestration in Class VI deepwells is likewise demonstrated. See preamble section V.N. Vendors are providing guarantees for CCS. See preamble section V.F. The EPA carefull y considered the issue of compliance costs, and based its cost estimates on updated costs reflecting recent vendor quotes and performance information and application of the Shell Cansolv amine scrubbing process that is currentl y being used at the Boundary Dam Unit #3 project. Based on this most up
- to - date information, the EPA adjusted the final standard of performance to 1 ,400 lb CO 2 /MWh from the 1 ,100 lb CO 2 /MWh proposed
. The EPA’s anal ys is of why the cost of this standard are reasonable under section 111 (a) is found in sections V.H and I. of the preamble to the final rule. **Comment 6.3 -**  **234:** Commenters 4814, 7977, 9426, 9590, 10043, 10047, 10135, 10466, 10929 stated that CCS is developin g but is not is not technologicall y or economically viable at this time, and thus should not be a basis for a standard. Commenter 4814 summarized work developing CCS technologies. The commenter noted that these projects are bringing CCS closer to economic and commercial viability over the next decade. **Response 6.3 -**  **234:** These comments were unduly negative. CCS is clearl y technically viable as it is being implemented now. For example, the Boundary Dam Unit #3 facility

is operating successfull y at full scale. The EPA has al so determined that a new unit can utilize partial CCS to meet the final standard of performance at reasonable cost. The EPA has also issued six Class VI permits for underground injection. See generally preamble section V. **Comment 6.3 -**  **235:** Commenter 9678 stated concern that EPA's determination that partial CCS is BSER for coal and IG CC units is flawed and will not survive judicial review. According to the commenter, EPA has not shown that CCS for coal units is adequately demonstrated and relies on arbitrary presumptions in reaching its conclusion and these inadequacies in EPA's analy sis may make the proposed standard vulnerable to remand on judicial review, which would delay the promulgation of the rule and the associated benefits of having a final rule in place. To ensure t hat the rule is legall y defensible, the commenter recommended that EPA establish a standard for coal and IGCC units that is not based on CCS, but is instead based on other adequately demonstrated emissions control technologies. **Response 6.3 -**  **235:** According to commenter 95 05, the agency's BSER determination will not survive judicial review, as it is contrary to the statutory

text and a wealth of evidence, and is not supported by

reasoned decision
- making. The commenter stated section 111 of the Clean Air Act does not permit EPA to force an experimental technology through an NSPS, although this is precisel y what the proposal attempts to do. Accordingl y, the commenter recommended EPA reverse its determination that CCS is the BSER for the proposed NSPS. Partial CCS is an adequat ely demonstrated control technology . See preamble section V.D. The EPA does not believe that basing a standard on performance of “capture and CO 2 compression technologies [that ] have commercial operating experience with demonstrated ability for high reli ability” is arbitrary

and capricious. See NETL (2015) at p. 36. See also statement of Alstom6
- 142

senior Vice President for Power and Environment Policies Joan MacN aughton (August 4, 2011): “The technology

works. ” See : www.alstom.com/Global/US/Resources/Documents/Press%20Releases/PR_JMacN_CCSbriefing _FINAL.pdf **Comment 6.3 -**  **236:** Commenters 9725, 10050 stated that the EPA has used estimates from hy pothetical IGCC and SCPC units with CCS, not actual operating experience. The commenters stated that the EPA's approach is unprecede nted, unlawful and a stunning departure from over 40 ye ars of regulatory

history that relies upon actual emission data from representative units operating with adequately demonstrated technology
. Commenter 10039 stated that the EPA cannot attribute all new coal fired generation as unequivocall y base load for purposes of justifying CCS as technically feasible for this source, and not include intermediate (load following) and peaking units. Partial CCS is demonstrated at commercial scale in this industry ( Boundary

Dam, in particular), and (for pre
- combustion, should this be pursued) in a related, transferrable context (Dakota Gasification). These are not hy pothetical facilities. EPA’s cost estimates reflect the most up
- to date information available: recent vendor quotes and performance information and application of the Shell Cansolv amine scrubbing process that is currentl y being used at the Boundary Dam Unit #3 project
. The EPA does not unequivocally attribute all new coal
- fired generation unequivocall y as base load units for the purpose of justifying CCS as technically feasible. The EPA does believe, given current and projected market conditions, that a project developer would be most likely

to build a new unit for the purposes of providing high capacity factor, base load generation. Still, the EPA has shown that the promulgated standard is achievable for an affected EGU using the BSER under a range of operating conditions and that the 12
- month average is indicative of, and accommodating for, variable op erations (and excursions). In confirmation, as shown in the Technical Support Document, actual 12
- month averages of two recent highl y efficient SCPC are close to those projected here. **Response 6.3 -**  **236:** . See preamble section V.J and New Steam Achievability Technical Mem orandum (July

2015). **Comment 6.3 -**  **237:** Commenter 10618 stated that EPA's position on the feasibility and adequate demonstration of CCS in the proposed rule are in many way s contradictory to its assessment of the technology

in the PSD and Title V Permitting Guidance for Gree nhouse Gases document. The commenter provided numerous excerpts from the document in which EPA suggests that CCS be considered in a BACT analy sis and that CCS will likely not apply because it is not technicall y feasible and/or because it is not cost
- effective
- both reasons also support the conclusion that CCS has not been adequatel y demonstrated. The commenter concluded if the level of development is insufficient to generall y apply CCS as BACT, it is also insufficient to support the determination that CCS is the BSER. **Response 6.3 -**  **237:** With regard to the commenters who stated that a BSER for EGUs that is based on partial CCS would be inconsistent with BACT determinations in previous GHG PSD permits, it is important to recognize that a BACT determination is a case
- by
- case anal ys is and that technological capabilities and costs evolve over time. Thus **,** language from an historic6
- 143

guidance document, providing context for case
- by
- case application rather than for national rulemaking, hardl y has determinative effect here. Moreover, the commenters quote selectively from that guidance. In fact, the 2011 GHG Permitting Guidance states that “although CCS is not in widespread use at this time, EPA generall y considers CCS to be an ‘available’ add
- on pollution control technology for facil ities emitting CO 2 in large amounts and industrial facilities with high
- purity CO 2 streams.” GHG Permitting Guidance at 35. The Guidance goes on to note that CCS may

not be available at modified sources, or in other specific circumstances. Id. at 36 (“Whil e CCS is a promising technology , EPA does not believe that at this time CCS will be a technicall y feasible BACT option in certain cases....EPA recognizes the significant logistical hurdles that the installation and operation of a CCS system presents and that sets it apart from other add
- on control that are typicall y used ... Logistical hurdles for CCS may include obtaining contracts for offsite land acquisition ..., the need for funding..., timing of available transportation infrastructure, and developing a site fo r secure long term storage. Not every source has the resources to overcome the offsite logistical barriers necessary to apply CCS technology to its operations, and smaller sources will likel y be more constrained in this regard”); id. at 42
- 3 (noting that C CS may

be expensive in individual instances and thus eliminated as a control option for that reason under step 4 of the BACT analy sis, noting further that revenues from EOR may offset other costs). See also UARG v. EPA , 134 S.Ct. 2427, 2448 (2014) (noting that EPA’s GHG Permitting Guidance states that carbon capture is reasonabl y comparable to more traditional, end
- of

- stack BACT technologies, and that petitioners do not dispute that)**.** See generall y, preamble section XII.C. As explained at preamble section V.I.5, in determining that partial CCS is BSER for new fossil fuel steam electric plants**,** EPA has carefully considered the issue of logistics (including cost estimates for land acquisition, transportation, and sequestration) and costs generall y. Nor would new plants face the same types of constraints as modified or reconstructed sources in a BACT determination, since a new source has more leeway in choosing where to site
. Moreover, the GHG Permitting Guidance considered BACT determinations for all typ es of sources, not just those for which EPA has determined in this rule that partial CCS is the best sy stem of emission reduction, and the concerns voiced in the Guidance thus must be considered in that broader context. **Comment 6.3 -**  **238:** Commenter 10618 stated that EPA's evaluation of each of the four factors in the BSER determination is flawed due to:

 a series of premature, inaccurate conclusions on the development, demonstration, and performance of advanced generation and CCS technologies; **Response:** The EPA disagrees. See preamble sections V.D and E. See also NETL (2015) p. 36 characterizing CCS as a technology with “commercial operating experience with demonstrated ability for high reliability”.

 minimal consideration and an abrupt dismissal of widely
- acknowledged barriers to CCS becoming a technically

feasible and adequatel y demonstrated control option; **Response:** See previous response.6
- 14 4

 an inadequate consideration of the lessons learned from actual projects and the conclusions reached b y major public and private assessments of CCS development; **Response :**  T he “major public and private assessments” that were mentioned largel y referred to full, rather than partial CCS (see preamble section V.F ) . The EPA has carefully considered lessons learned. It is for this reason that th e agency sought out and utilized the most recent cost information on post
- combustion CCS, basing its cost estimates on those from vendors supplying the technology in commercial use at the Boundary Dam #3 facility . See also preamble section V.I .2. indicati ng consistency of NETLcost estimates with those of other leading experts in the field, as well as with those of recent industry

cost estimates.

 an inconsistent use of criteria to perform the BSER anal ys es and to inform the Administrator's judgment within this proposal and compared to other rulemakings; **Response:** See Portland Cement v. Ruckelshaus , 486 F. 2d at 389 (NSPS are judged on their own merits, not by

comparison with NSPS established by EPA for other source categories).

 an inadequate evaluation o f the impacts to all sources within the source category ; and use of underl yi ng energy

policy goals that do not allow for an objective evaluation of BSER in accordance with the Clean Air Act. **Response:** the commenter is mistaken. The NSPS is justified, and may only be justified, by the statutory

criteria set out in section 111 (a). **Comment 6.3 -**  **239:** Commenter 9664 stated EPA correctly bases the level of the proposed standard for new subpart Da fossil fuel
- fired boilers and IGCCs on the application of partial carbon capture and sequestration as the Best Sy stem of Emission Reduction. According to the commenter, EPA's careful consideration of the cost, energy , and non
- air quality , environmental impacts of CCS satisfy

the statutory

requirements for the Agency to balance these required statutory factors in designating a CAA section 111 BSER. Commenter 101008 stated that EPA has given sufficient consideration to the statutory factors in making its BSER determination. The commenter referenced several court decisions to support thei r argument. The commenter noted that in determining that partial CCS is BSER for coal
- fired power plants, EPA appropriately weighed the efficacy

of achieving emission reductions as its prime consideration. The commenter added that in its BSER analy sis, EPA ruled out highl y efficient coal
- fired generation without CCS in part because that technology alone would not result in significant reductions of CO 2 . According to the commenter, CCS is by far the most effective process available for reducing carbon pollut ion from new coal
- fired power plants, and this factor thus weighs highl y in favor of EPA's BSER determination. Commenter 9514 stated EPA is justified in setting CCS as the BSER for new fossil fuel
- fired boilers and IGCCs. According to the commenter, CCS p rovides significant emissions reductions and co
- benefits, CCS sy stems are available for fossil fuel boilers and IGCCs and the6
- 145

technologies have been utilized in industrial applications for decades, and the costs are reasonable and can be accommodated b y in dustry
. Commenters 8020, 8939, and 8967 stated that using partial CCS strikes a good balance between economics and the environment, and that the technology will help to prevent significant amounts of C02 from being emitted into the atmosphere. **Response 6.3 -**  **239:** The EPA largel y agrees with these comments, although the final standard of performance strikes a somewhat different balance than str uck in the proposal, albeit using the same methodology
. **Comment 6.3 -**  **240:** Commente rs 8501, 9194, 9201, 9426, 9671 , 10618 disagreed with the difference in the way

that CCS was or was not determined to be BSER for subpart Da and subpart KKKK units. Commenters 9194, 9201, 9426, 9671, 10618, stated that CCS is currently inappropriate as BSER for both gas
- fired and coal
- fired EGUs. Commenters 8995, 9194, 9201, 9426, 9671, 10039, 10618, 10876 stated that many of the reasons the EPA cites for rejecting full or partial CCS technology as BSER for natural gas
- fired stationary combustion turbines are equall y applicable to I GCC and fossil fuel
- fired boilers, yet the Agency

reaches a different conclusion for the two sources. Commenter 10039 noted that the EPA errs b y sayi ng CCS is feasible at coal fired units regardless of dispatch order despite its acknowledgement that load follo wing may (and likely

will) adversel y affect the efficiency and reliability of a unit with carbon capture s ys tems. Commenter 8501 stated that there is little evidence to support a distinction between coal
- based generation to NGCT for the technical challenge s and costs for CCS, and stated that the EPA fails to distinguish why

CCS is not BSER for a natural gas
- fired plant. Commenter 10618 discussed the differences in discussions of CCS as applied to subpart Da and subpart KKKK units, noting that there was very limited discussion about broader industrial CCS experience in the BSER anal ys is for NGCTs, but there was for coal
- based generation. The commenter stated that the literature review was unevenl y applied to the two source categories. The commenter stated that large
- scale demonstration projects have not yet occurred for either of the two source categories. Commenter 10618 stated that although the Econamine capture s ys tem that has been used b y NGCC processes has ye t to be demonstrated on a single coal
- based gen erating unit, EPA assumes in its cost analy sis for the BSER that new pulverized coal units with CCS will be equipped with the Econamine sy stem. Commenter 9201stated that the way the EPA has weighed the factors to determine that CCS is BSER is unreasoned an d an abuse of discretion.6
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Commenter 10017 stated that there is a significant difference in the reductions required in CO 2 emissions between subparts Da and KKKK. **Response 6.3 -**  **240:** A discussion of the EPA’s final rationale regarding CCS as a component of BSER for combustion turbines is provided in the final preamble at section IX.C. 4. **Comment 6.3 -**  **241:** Commenter 9600 stated that the EPA has not documented its extrapolation of technology

performance in other industries to that for coal
- based generation. The commenter stated that as a result, there is no reasonable basis to conclude that carbon capture is technically available at a reasonable cost for use as BSER in the immediate future and perhaps not available as a BSER for many years to come. **Response 6.3 -**  **241:** First, post
- combustion CCS is demonstrated at commercial scale at a source (Boundary

Dam) that is a full
- scale, full y integrated coal
- fired EGU. No inter
- industry transfer of technology

is at issue. Pre
- combustion CCS (should a source consider that alternative compliance pathway) is likewise demonstrat ed at full commercial scale. See preamble section V.E.2.a for wh y this same technology and performance is transferable to an IGCC generating electricity. **Comment 6.3 -**  **242:** Commenter 10618 stated that the EPA's consideration of emission reductions is flawed because the agency uses ambiguous criteria to determine emission reductions. The commenter stated that the EPA fails to fully consider the magnitude of emission reductions that may

be achieved from highl y efficient processes alone, and utilizes loose, qualitative statements on CCS related emission reductions. The commenter stated that the EPA provides no information on the baseline used to assess emission reductions and provides no information on the ty

pes of criteria considered in determining "significant" and "meaningful." **Response 6.3 -**  **242:** See preamble section V.K quantifying the difference between a highl y efficient SCPC and a highly efficient SCPC meeting the standard of performance based on the BSER. See also RIA chapter 5 quantifying the benefits of that difference in performance and showing that those benefits exceed regulatory costs under a range of assumptions
. **Comment 6.3 -**  **243:** Commenter 4710 stated that the EPA has chosen to disregard DOE and OMB statements and documents that do not support CCS readiness, economics or feasibility
. **Response 6.3 -**  **243:** Those statements referred to full CCS, not partial CCS. DOE’s latest statement regarding CCS reliability (“demonstrated ability

for high reliability”) is found at p. 36 of its July 2015 NETL study
. **Comment 6.3 -**  **244:** Commenters 9195, 9201, 10036, 10239, 10395 noted that the EPA has chan ged BSER in this proposal from the determination of BSER in the 2012 proposal. Commenters 10239, 10395 stated that the EPA has provided no rational explanation for the change. Commenter 9195 asked for the basis for the change.6
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Commenter 10239 stated that nothing has changed since 2012 to make CCS BSER, and noted that the EPA does not cite any new information or new projects in this rulemaking that were not available to it in the 2012 proposed rule. The commenter stated that there is no rational basis for the EPA to reverse course and conclude that CCS is adequatel y demonstrated and is BSER for coal
- fired EGUs without some new data or evidence of changed conditions. The commenter stated that such a conclusion is fundamentally at odds with the most basic pri nciple of administrative law that, when an agency changes its position, it must supply a reasoned analy sis for doing so. **Response 6.3 -**  **244:** The EPA indicated in its 2012 proposal that CCS was a feasible technology option for new power plants in the original proposal, so muc h of this comment rests on a mistaken premise. See 77 FR at 22414
- 417. The agency withdrew the 2012 proposal largel y in response to industry

comment that future new fossil
- fuel fired steam electric capacity (i.e. coal
fired) was possible and therefore th at separate standards for utility boilers and IGCC, on the one hand, and NGCC unit s on the other, was warranted. 79 FR at 1432. The EPA did not find that CCS was the BSER in that 2012 proposal because the proposed standards were for a combined category that included both NGCC units and steam generating units. In the current action, the EPA proposed and is finalizing separate standards of performance for both stationary combustion turbin es and steam generating units, with separate BSERs for each. With respect to CCS, among the developments that have occurred since the 2012 proposal are the successful operation at commercial scale of post
- combustion CCS and issuance of six permits for deep well injection of captured CO 2 , as well as more recent cost information reflecting operating experience. The EPA has fully articulated its basis for the final standard reflecting an adequatel y demonstrated BSER, and this extended discussion amply indicat es wh y EPA is adopting a different assessment than found in the 2012 proposal. See preamble section V. **Comment 6.3 -**  **245:** Commenters 9001, 9428, 9595, 9601, 10238, 10358, 10387, 10501 stated that although CCS holds promise for the future, the technology for electric generation today remains both costly

and unproven. **Response 6.3 -**  **245:** See preamble section V. **Comment 6.3 -**  **246:** Commenters 10083, 10606 asked that regional impediments to CCS be considered, particularl y the lack of good CO 2 sequestration sites. **Response 6.3 -**  **246:** See preamble section V.M. **Cost Comment 6.3**  **- 247:**  Commenter 9666 stated that EPA's attempt to calculate the cost of CCS is inadequate, as there are no commercial units operating to provide experience from which to validate designs that were developed for small
- scale. The commenter noted that although no c ommercial
- scale CCS project has been completed at a coal
- fired or IGCC unit, and thus no reliable indicator of the full cost of CCS at this scale exists, some cost information is available for the Kemper County

I GCC unit, which is scheduled for completion in 2015. According to the commenter, during the course of Kemper County' s construction, the project's costs have escalated from an estimated $2.4 billion in 2010 to $5.5 billion at the latest estimate in 2014,6
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representing several successive cost increases
. The commenter recommended a more robust approach for determining casts would be to solicit price quotes for power generation equipment in the present economic and fuel price environment; employing several sources of such data (e.g., not a single proprie tary database); and conducting a rigorous peer review. Commenter 9666 also stated that due in part to a lack of relevant operating experience, CCS remains exorbitantly

costly to install and operate. The stated the uncertainty surrounding the actual cost of an y IGCC project incorporating CCS presents another hurdle to financing and constructing these units. According to the commenter, developers will find it difficult to obtain financing due to their inability to predict the actual cost of any I GCC project i nvolving CCS. The commenter stated that the costs of CCS are so high and uncertain that the proposed IGCC standard will effectivel y prohibit the construction of any new Subpart Da IGCC unit. The commenter also stated in addition, at all of the commercial
- s cale projects that have been proposed, the CCS sy stem is justified in the fundamental business case for the project because the separated CO 2 stream will be used directl y b y another industrial process, such as enhanced oil and gas recovery . According to th e commenter, such opportunities are limited and only a few earl y projects would be able to take advantage of these opportunities. Commenter 9033 also stated that it is unaware that any supplier of this technology is ready or able to offer commercial guarantees for such full
- scale s ys tems of carbon capture. The commenter noted that all utility generators require extensive performance guarantees and warranties which cannot be offered without proper demonstration at scale. According to the commenter, all the p rojects that form a basis for the EPA rule would require extensive revenue sources from niche market opportunities like EOR and chemicals and large federal subsidies, none would stand alone on a common commercial basis which would in turn mean that no new coal burning plant could be permitted or financed. Hence the commenter noted it is unlikely that such sy stems will be available prior to the EPA obligatory eight
- ye ar review of this proposed NSPS. Commenter 9486 stated they are not certain that an accurate costing estimate can be performed at this time given the state of CCS technology and lack of full scale implementation at a coal
- fired power plant. The commenter also expressed concerns with U.S. EPA's reasoning that the costs for CCS will decrease as the technology advances. As U.S. EPA stated, the current economics dictate that very

few coal
- fired power plants will be constructed even without the requirement to add CCS. According to the commenter, if there is no market for CCS technologies at coal power plants, the cost will remain high for CCS technologies. The commenter concluded that the unproven full scale costing of CCS makes it extremely difficult, if not impossible, to accurately evaluate and determine the cost impacts of this rule. Commenter 8966 stated the costs of CCS technology are difficult to quantify , in part because there are no examples of currentl y operating commercial
- scale coal
- fired power plants equipped with CCS. The commenter stated however, AEP's experience with installation of a val idation
scale chilled ammonia
- based CCS system at its Mountaineer Plant is particularly valuable in gaining insight into the potentially massive costs of a commercial
- scale CCS system.6
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Commenter 10100 stated there are no commercial ventures in the United S tates that capture, transport, and inject industrial
- scale quantities of CO 2 solely for the purposes of carbon sequestration. The commenter also stated that commercial
- scale CCS demonstration projects are nascent, and of the five CCS projects that DOE has supported with significant financial incentives, only

one appears to be moving forward. Commenter 10391 stated that although no full
- scale operational CCS system at a coal
- fueled power plant exists in the U.S., EPA convenientl y excluded "first of its kind" costs from its rulemaking consideration. According to the commenter, when evaluating increased costs and risks, pilot CCS and experimental projects are largel y irrelevant because these projects have been government subsidized. Similarly , EPA likely underv alues regulatory

hurdles and risks and overvalues potential revenues from CO 2 waste stream sales for possible use in enhanced oil recovery (EOR) fields. Commenter 9427 stated that instead of focusing on comparative costs for levels of emissions limitations within the Subpart Da source category for justifying a standard level, EPA inappropriatel y focused on comparing the cost of coal
- fired steam generating units using "partial CCS" with costs for another source category or with costs for electricity generati on with technologies that are not even regulated under Section 111 to show that coal with partial CCS is "competitive" with other technologies. According to the commenter, because the construction is not complete and operation has not yet begun on actual p rojects emplo yi ng CCS cited by EPA in its proposal, the actual costs of projects are completely unknown at this time. Commenter 9505 stated none of the pilot projects described in the proposal activel y capture CO 2 from plant exhausts or store CO 2 in the ground, and because CCS is not operational at these pilot projects, there is no data about continuous operations, commercial scalability , or costs. Hence, the commenter stated, these experimental projects cannot form the basis for a finding that the technolo gy

is available. Commenter 9666 also stated the cost of CCS at smaller demonstration facilities cannot be reliably scaled up to inform predictions about the cost of CCS at commercial units. Indeed, all that is known about the cost of CCS is that it is exor bitantly high. The commenter also stated EPA's estimate of the baseline cost of coal fired power generation is incorrect, which also skews its assessment of the proposed standard's relative cost. Commenter 10043 stated that because CCS is neither commercially available nor proven at the appropriate scale or size needed b y the four pilot projects, the EPA's cost analysis, upon which the EPA based its conclusion that CCS technology has been adequatel y demonstrated, is highl y questionable. The commenter also n oted that EPA is contradictory in foretelling reductions in the capital costs of CCS because of research, development and implementation of the technology while also estimating that no new coal
- fired power plants will be constructed **Response 6.3 -**  **247:** Commenter 9666 refers to the cost overruns at the Kemper facility . The Kemper site undoubtedl y experienced massive cost overruns, but did so for reasons that are not generall y applicable, and which cannot legitimately be used as a basis for assessing costs for other facilitie s. For example, as documented in detail in the April 15, 2014 Independent Monitor’s Prudency

Evaluation Report (“Independent Monitor’s Prudency Evaluation Report for the Kemper County IGC C Project”, prepared b y Burns and Roe Enterprises for Mississippi Public Utility

Commission staff), at least partl y in an effort to obtain an annual tax credit, the6
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project team chose to adopt “a compressed schedule which led to a just
- in
- time approach to engineering, design, procurement and construction...”. Report, p. 14. In essence, basic engineering decisions were not made in advance of construction: “By committing to this approach, engineering and design changes which are a normal result of detailed engineering and design were occurring at the same time as, rather than ahead of, construction activities.” Id. p. 6. In BREI’s opinion, “several areas were not adequately addressed, executed or implemented in a reasonable manner. ” These areas include: project planning/scheduling. The development of a risk management program with sufficient detail and look ahead time horizon, the late development of the original integrated EPC schedule with adequate resource loading, commodity cost estimating and monitoring (which controlled the project estimated cost to the certification es timate of $2.4 billion until the original low contingency was depleted), and the implementation of SCS’s and MPCo’s internal procedures and policies (or failure to implement certain policies and procedures), and other areas discussed in this report. All o f the areas listed above which were not addressed, executed or implemented in a reasonable manner raise serious doubt to BREI as to the appropriateness and reasonableness of those actions taken b y MPCo in implementing this Protect.” Report, pp. 14
- 15. More over, the Report indicates all issues with cost related to the gasification unit, not to carbon capture and sequestration. Commenter 9666 also urges that costs reflect CCS used at full commercial scale, and that costs should not be extrapolated from smal l scale designs. Commenters 10391, 10043 and 9505 made a similar comment. The EPA has carefull y considered comments that costs should be assessed reflecting technolog ies being used at full commercial scale. For the final standard, the EPA made particular use of the most recent NETL cost estimates for post
- combustion CCS, which reflect up
- to - date vendor quotes and incorporate the post
- combustion capture technology

– the S hell Cansolv amine
- based process

– that is being utilized at the Boundary Dam Unit #3 facility
. The same commenter indicates the substantial uncertainty for IGCC projects incorporating CCS. The BSER for the final rule is a highl y efficient SCPC using parti al CCS, not I GCC. See preamble section V.H. for EPA’s cost anal ys is of the BSER. Regarding the issue of vendor guarantees (commenter 9033), see preamble section V.F. A number of commenters (e.g. 9486, 10043) posed a purported chicken
- egg type of issue: ho w can there be learning b y doing when new coal
- fired plants aren’t being constructed. EPA addresses this issue in preamble section V. I.4. Commenter 9666 and others maintain that because CCS is such an uncertain technology, there will be hurdles to financi ng. Although the EPA does not accept the commenters’ characterization of the technology (see e.g preamble section V.F. (vendor guarantees)), but has based estimates of financing costs on “high
- risk financial assumptions”. NETL(2015) at p. 18. The EPA h as carefully

studied both AEP’s comments, its reports on the Mountaineer effort, and the FEED study it prepared (commenter 8966). AEP especiall y singled out its difficulties in siting monitoring wells and otherwise siting a sequestration site. As explain ed in preamble section V.I.5, this site
- specific experience reflects an individual siting challenge which may not6
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be generally

applicable. For example, none of the Class VIpermits issued to date by EPA required the number of monitoring wells as at the Mo untaineer site. Commenter 9427 questions the use of the LCOE metric. This issue is addressed in preamble section V.I.1. The commenter also stated EPA's estimate of the baseline cost of coal fired power generation is incorrect, which also skews its assessme nt of the proposed standard's relative cost. The EPA used DOE/NETL estimate s for the baseline cost of coal fired power generation and believes that they

are reasonable estimates of the cost of a new coal
- fired power plant. DOE/NETL stated “[T]he cost esti mates for plant designs that onl y contain fully mature technologies, which have been widel y deplo ye d at commercial scale (e.g., PC and NGCC power plants without CO 2 capture), reflect nth

- of
- a - kind (NOAK) on the technology commercialization maturity spectrum.” Further, the final BSER is a highl y efficient supercritical PC unit implementing partial CCS to meet a standard of 1,400 lb CO 2 /MWh
- g. The AEP John W. Turk facility is an example of a highl y efficient supercritical PC. In comments of AEP (p. 76), AEP represented the cost of the Turk facility as $2,885/kW. The DOE/NETL estimates for such a facility is $2,842/kW (NETL , 2015

– for a plant using bituminous coal). This close agreement is another validation of the NETLcost methodology
. **Comment 6.3 -**  **248:** Commenter 9033 suggest ed that in setting economic criteria for technology , EPA consider the "typical commercial power plant" which will not have federal subsidies and will likely

not have access to chemical or EOR revenue. According to the commenter, EPA needs to recognize that both chemicals and EOR are niche opportunities and not available to most power plants. The commenter added that even in the most optimistic cases, people forecast EOR has consuming perhaps 100 million tons of CO 2 (including current natural CO 2 ) and chemic als are in the low millions of tons when compared with the billions of tons required to be reduced. Commenter 10095 stated EPA cannot rel y on revenues from EOR activities, government subsidies, or regulatory

programs to defray

the cost of partial CCS and that EPA fails to acknowledge that these activities and policies are not widely available, impermanent, not guaranteed, and subject to significant political uncertainties **Response 6.3 -**  **248:** The EPA is not relying on EOR revenues in its cost analy sis. This is a conservative a

pproach to assessing costs, given that new coal plants are being sited to take advantage of such opportunities. See preamble section V.H.8. **Comment 6.3 -**  **249:** Commenters 10098 and 10239 stated that EPA has pointed to no evidence that any CCS
- enabled power plant has been fully funded by

a private entity , undercutting EPA's conclusion that CCS actually "can be accommodated by the industry ." According to commenter 10098, every

CCS project identified in the proposed rule is receiving significant government grants, loan guarante es, and other subsidies, a point that EPA concedes but states that it does "not consider such government subsidies to mean that the costs of CCS would otherwise be unreasonable. Commenters 10098 and 10239 also noted that CCS cannot be accommodated b y the i ndustry

as evidenced by

many examples of the rejection of CCS as BACT on cost grounds and the failure of CCS projects for various economic reasons.6
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Commenter 10952 also stated that there is no basis to conclude that industry is "accommodating" the costs or can accommodate the costs as onl y three projects are planned or under construction. The commenter also noted that since none are operational, it is impossible to conclude that their technical configurations are capable of meeting the duty cycle demands placed on base
- load EGUs. The commenter referenced EPA's first proposal in which a ten ye ar timeline and the need for ten up and running demonstration projects, noting that this timeline was lacking from the current proposal. According to the commenter, ab sent any explanation accompanying the proposal, and there is none, here EPA is making nothing short of a guess, a guess that is in clear conflict with its earlier determinations and conclusion, the hallmark of arbitrary rulemaking. The commenter also stat ed that the proposal fails to address how CCS projects would be financiall y viable without such federal funding, specifically EPA must address what alternative financing means outside federal grant monies are available to support an EGU CCS project where C CS is inordinately

costly and an unproven commercial technology
. Commenter 10098 stated that EPA's assertion that the costs of CCS can be accommodated b y the industry lacks any factual basis, as EPA relies solely on facilities that have received significant government subsidies for construction and there is no guarantee that such subsidies will be available in the future. The commenter also stated that the proposed rule not only fails to acknowledge EPA's current position against counting such subsidies, as discussed in EPA's NSR Manual, it provides no explanation of why a change in position is warranted. According to the commenter, EPA must provide a reasoned anal ys is as to why it is now abandoning its current, well
- established position that tax credits or other government subsidies for a pollution control should not be included in cost anal ys es. Commenter 10029 also stated that the Clean Air Act does not permit the EPA to offset costs by relying on general subsidies available to an industry . The commenter referenced 42 CAA Section 111(a)(1), and stated that under that section , the EPA must tak[e] into account the costs of achieving such reduction (i.e. the standard of performance), not the net costs (after accounting for subsidies) of constructing and operating the stationary source. Commenter 7977 stated that EPA's conclusion that "a section of the industry is already accommodating the costs" of CCS is based on demonstration projects that receive DOE financial assistance. According to the commenter, that financial assistance was available due to legislation that was passed to stimulate the economy during a recession by

increasing spending in a specific time period , and it is unreasonable to conclude that the costs of CCS are not exorbitant under circumstance s when such funds are limited and will not be available indefinitely
. **Response 6.3 -**  **249:** Itis not surprising that most CCS project s that have been identified are receiving or have received government support of some form. Prior to this final action, there was no requirement that any EGUs reduce GHG emissions. In a 2011 press release 40 , Alstom Senior Vice President for Power and Environment Policies Joan MacNaughton was quoted as saying, “The Validation Plant at Mountaineer demonstrated the ability to capture up to 90% of the carbon dioxide from a stream of the plant’s emissions. The technology works. But without clear policies in place outlining options for cost recovery, power generators are hard
- pressed to invest
40 www.alstom.com/Global/US/Resources/Documents/Press%20Releases/PR_JMacN_CCSbriefing_FINAL.pdf6
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in its continued refinement.” Similarly , AEP Chair man and CEO Michael Morris was quoted in an AEP press release 41 on the Mountaineer Project being put on hold

– “But as a regulated utility, it is impossible to gain regulatory approval to recover our share of the costs for validating and deploying the techn ology without federal requirements to reduce greenhouse gas emissions already in place. ” The EPA did not consider potential cost reduction from government subsidies when evaluating the reasonableness of costs for the final standard of performance. **Comment 6.3 -**  **250:** Comment er 9514 stated that EPA properl y determined that the costs of partial CCS can be accommodated by industry . According to the commenter, EPA's conclusion is supported by

the broadly
- maintained prediction that, due to current and predicted economic conditions , very

few new coal
- fired power plants will be built in the future, if any . The commenter stated that the costs of the partial CCS standard
- approximately a 20 percent increase

- on a few new coal
- fired plants can easil y be accommodated by industry . The c ommenter stated that the proposal will have little impact on consumer electric prices and given that so few plants will be built, from an industry
- wide perspective the costs of meeting the standard based on full CCS are not exorbitant. Commenter 10106 stated that while there may be some additional incremental costs for Wisconsin relative to some other states as a result of a requirement to implement CCS, these costs are also not at a level which would prohibit an operator from constructing a new power plant. According to the commenter, since electrical generation and service provision are highly regulated in the State of Wisconsin
- including the presence of regulated monopolies for energy utility companies
- no competitive advantage or disadvantage will be incurred for regulated entities within the state as a result of such a requirement. Furthermore, the commenter stated, interstate cost differences induced as a result of the proposed NSPS are not qualitatively different than those corresponding to other r ules
- for example the recently upheld Cross
- State Air Pollution Rule. **Response 6.3 -**  **250:** The EPA largel y agrees with these comments. **Comment 6.3 -**  **251:** Commenter 9774 stated that EPA's NSPS anal ys is of CCS does not account for the cost and issues related to transporting CO 2 to proven carbon s equestration sites. The commenter referenced the EPA estimate that the equipment costs necessary for removing CO 2 at a 550MW supercritical coal generating unit is approximately $267 million, whereas a recent BACT analy sis by

the Wisconsin DNR yielded costs of approximately $405 million for construction of a CO 2 pipeline to the closest potential sequestration site. The commenter provided additional information that CO 2 sequestration costs for Wisconsin utilities resulted in an estimate of $550 million to $1 billion capital cost for a pipeline network that would be required to serve Wisconsin coal
- fired generation. The commenter noted that these presented costs do not include the additional costs associated with operating CO 2 pipelines, and EPA must also addre ss the difficulties, logistics and significant additional expense of placing pipelines and facilities in urban areas.

41 https://www.aep.com/newsroom/newsreleases/?id=17046
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Commenter 10095 stated that in the CCS cost estimates that incorporate EOR opportunities, EPA assumes that an EGU is only responsible for the costs of transmitting the captured CO 2 to the facility's fence line where the point of sale occurs and the EGU will avoid CO 2 transmission, storage, and monitoring costs. The commenter disagree d and provides the example that the Kemper County Energy Fa cility, which is uniquely situated in close proximity to EOR opportunities, constructed a 61 mile CO 2 pipeline to transact with third party CO 2 off
- takers and reduce third party- related risks. The point of transaction occurs at two locations along the 61 m ile pipeline
- Pachuta and Heidelburg, Mississippi. The cost incurred b y Mississippi Power to construct this pipeline was $108 million. Considering the Kemper County Energy Facility's proximity to EOR opportunities and the ability to transact with two CO 2 of f
- takers along a single pipeline, the commenter stated that the cost incurred by future projects will almost certainl y be higher. According to the commenter, EPA needs to reevaluate its cost estimates with consideration of pipeline construction costs incurred by the EGU even when en gaging in relativel y close EOR opportunities. Commenter 7977 noted that the NETL costs exclude transportation costs of CO 2 , which could significantl y increase the cost estimate for new sources implementing CCS technology. Ac cording to the commenter, Section 111(a)(1) of the CAA requires that EPA account for the "costs of achieving such reductions" and since EPA is proposing that CCS is the BSER for coal
fired EGUs, EPA must account for the cost of transporting CO 2 . The commenter also stated the proposed regulation relies on the expected ty pical pipeline distance to be 50 miles to possible geologic sequestration sites, however, according to the commenter, this distance underestimates the actual distances that may be necessary

f or the transmission of CO 2 . The commenter continued that EPA is required to comprehensively evaluate the impact of all associated transportation costs via pipelines, including availability and acquisitions of right
- of
- way for new pipelines, capital and ope rating costs, and actual length of transmission pipelines. Additionally , the commenter stated other costs, including the performance of expensive seismic studies, must be accounted for prior to a regulated entity being able to store CO 2 long
- term. Commenter 9773 stated EPA's analysis of CCS is problematic in that it does not account for the cost to transport CO 2 from utility plants to proven sequestration sites located more than 50 miles away . According to the commenter, since Wisconsin does not have even a single proven sequestration site, transporting CO 2 out - of
- state for sequestration is the only option. And the cost of such transport would be substantial. The commenter referenced an analy sis by Wisconsin using DOE cost methods which determined that a pip eline network from Wisconsin to the Illinois Basin (the nearest potential sequestration site) would cost between $550 million to $1 billion. The commenter stated that such an investment would be cost
- prohibitive and have a real and detrimental effect on Wi sconsin ratepayers. The commenter suggested that to address this issue, when setting the NSPS, EPA must first fully consider and quantify the costs of transporting CO 2 from where existing coal
- fired generating units are currently operating to proven seques tration sites. **Response 6.3 -**  **251:** See preamble section V.I.5. The EPA’s cost estimates do in fact include costs associated with transportation and storage of CO 2 . For transport, costs reflect pipeline capital costs, related capital expenditures, and O&M costs. Sequestration cost estimates reflect the cost of site screening and evaluation, the cost of injection wells, the cost of injection6
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equipment, operation and maintenance costs, pore volume acquisition expense, and long term liability protection. These sequestration costs reflect the regulatory requirements of the Underground Injection Control Class VIprogram and GHGRP subpart RR for geologic sequestration of CO 2 in deep saline formations
. We expect that when CO 2 is sold for EOR applications, the buyer rather than the EGU operator will likely bear those costs. However, for the purposes of the cost analy sis, the transportation, storage and monitoring (TS&M) costs are included for both EOR and non
- EOR applications, recognizing that this likely slightly overstates the cost to the operator in circumstances where CO 2 is sold for EOR. The EPA’s cost estimates for transportation and sequestration thus cover all aspects commenters claimed the EPA disregarded. Potential GS formations are widel y available in the United States. The E PA recognizes that geologic conditions to support CO 2 storage may not exist in all regions of the country . Where such capacity

is unavailable, electricity demand in those areas can be served by coal
- fired power plants built in neighboring areas with geolog ic availability with generated electricity being supplied via transmission line, see Figure 1 of TSD on geographic availability, or the CO 2 can be transported to available GS sites via pipeline. For other of those areas, coal
- fired power plants are either not being built due to state law prohibition s against building such units, or other available compliance alternatives exist allowing a new coal
- fired power plant meeting the promulgated NSPS to be sited. There are alternative means of complying with the f inal standards of performance which do not necessitate use of partial CCS, so any siting difficulties based on lack of a CO 2 repository

would be obviated. **Comment 6.3 -**  **252:** Commenter 9472 stated that EPA ignores the technical and permitting challenges of CO 2 storage and therefore fails to assess fully the costs of CCS. The commenter discussed technical concerns with EOR and saline storage and stated that EPA failed to consider several aspects of CO 2 storage that limit the feasibility of utilizing CCS at a co al
- fueled power plant. **Response 6.3 -**  **252:** See preamble section V.I.5. **Comment 6.3 -**  **253:** Commenter 9666 discussed several concerns with the use of costs associated with the resale of captured CO 2 for use in EOR. The commenter stated EPA cannot rel y on the potential resale of captured CO 2 for u se in EOR to reduce the expected cost of its CCS mandate given the uncertainties facing EOR operators. According to the commenter, EOR operators are concerned that the proposed rule's requirement for EOR operators that purchase CO 2 from EGUs to have to rep ort emissions under the more stringent requirements of Subpart RR of 40 C.F.R. part 98, rather than Subpart UU with which they currentl y compl y, "will create regulatory uncertainty and risk that will result in EOR operators avoiding the purchase of CO 2 that is subject to those rules." The commenter also stated that instead of benefiting financiall y from capturing CO 2 emissions, EGUs would likely have to pay

EOR operators to take the CO 2 , which removes any cost justification that EPA ascribes to CCS based o n EOR. Furthermore, the commenter stated that EPA admits that resale for EOR is "non
- economical" or unavailable for some locations in which new Subpart Da units may be built, therefore the cost of CCS with resale for EOR does not represent the cost of inst alling CCS on new units throughout the country , and should not be considered in determining the proposed NSPS.6
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Commenter 9426 stated that the EPA has only estimated the cost of IGCC units with partial CCS associated with EOR, and this is insufficient for setting a standard to appl y to PC units or to any unit that is not using EOR, or for any unit seeking to store CO 2 in saline geological formations. Commenter 9197 disagreed with EPA assumptions that EOR is widely available and that EOR operators will pay

significant premiums for CO 2 from regulated EGUs. According to the commenter, EOR sites are not available in many parts of the country, while in others there may be significant infrastructure barriers (in particular, the need to construct new pipelines ) that will substantially

raise the costs of using this sy stem of emission reduction. The commenter also stated there is a real possibility that EOR operators will not accept CO 2 from EGUs due to the uncertainty and risk of reporting under Subpart RR relat ed to MRV plans, and the burdens inherent in transitioning from a Class II well to a Class VIwell under EPA's proposed Underground Injection Control Program policy
. **Response 6.3 -**  **253:** See preamble section V.I.5. The BSER determination and regulatory impact anal ys is for this rule relies on GS in deep saline formations
. However, the EPA also recognizes the potential for sequestering CO 2 via EOR and allows the use of EOR as a compliance option
. The EPA disagrees that GHGRP subpart RR requirements will result in EOR operators avoiding the purchase of CO 2 from affected EGUs. The cost of compliance with subpart RR is not significant enough to offset the potential revenue for the EOR operator from the sale of produced oil for CCS projects that are reliant on EOR. First, the costs associated with subpart RR are relatively modest, especially

in comparison with revenues from an EOR field. Inthe economic impact anal ys is for subpart RR, the EPA estimated that an EOR project with a Class II permit would incur a first ye ar cost of up to $147,030 to develop an MRV plan, and an annual cost of $27,787 to maintain the plan; the EPA estimated annual reporting and recordkeeping costs at $13,262 per year. 42 Monitoring costs are estimated to range from $0.02 per metric ton (base case scenario) to approximately $2 per metric ton of CO 2 (high scenario). Using a range of scenarios (that included high end estimates), these s ubpart RR costs are approximately three to four percent of estimated revenues for an average EOR field, indicating that the costs can readil y be absorbed. 75 FR 75073. Furthermore, there is a demand for new CO 2 by EOR operators, even beyond current natural sources of CO 2
. For example, in an April 2014 study , DOE concluded that future development of EOR will need to rel y on captured CO 2 . 43 Thus, the argument that EOR operators will obtain CO 2 from other sources without triggering subpart RR responsibilities, which assumes ad equate supplies of CO 2 from other sources, lacks foundation. In addition, the Internal Revenue Code section 45Q provides a tax credit for CO 2 sequestration which is far greater than subpart RR costs. 44 Section 45Q(a)(1) allows a credit of $20 per metric t on of qualified CO 2 that is captured b y the taxpayer at a qualified facility , disposed of by the

42 Subpart RR costs are presented in 2008 US dollars. 43 “Near Term Projections of CO 2 Utilization for Enhanced Oil Recovery”. DOE/NETL
- 2014/1648. April 2014. 44 http://www.irs.gov/irb/2009
- 44_IRB/ar11.html and http://www.irs.gov/irb/2015
- 26_IRB/ar14.html.6
- 157

taxpayer in secure geological storage, and not used by the taxpayer as a tertiary injectant. Section 45Q(a)(2) allows a credit of $10 per metric ton of qualifi ed CO 2 that is captured b y the taxpayer at a qualified facility , used by the taxpayer as a tertiary injectant in a qualified enhanced oil or natural gas recovery

project, and disposed of b y the taxpayer in secure geological storage. The section 45Q credit for calendar ye ar 2015 is $21.85 per metric ton of qualified CO 2 under section 45Q(a)(1) and $10.92 per metric ton of qualified CO 2 under section 45Q(a)(2)
. **Comment 6.3 -**  **254:** Commenter 7893 stated that it is critical to understand that the option to sell captured CO 2 to EOR operations does not exist for Interior coal
- fired plants because there is no nearb y oil or gas production. According to the commenter, the extremely high costs of partial CCS for new coal
- fired facilities would not be offset by EOR. Commenter 495 stated the EPA has not demonstrated the availability or feasibility

of CCS in areas that will be most affected b y the Proposed Rule, as the Midwest and other areas of the country have limited access to EOR sites, which directly impacts the co st of implementing CCS. The commenter also noted that EPA assumes the market for EOR will not become oversaturated if the Proposed Rule moves forward as there are a limited number of EOR sites and all of them are congregated in small portions of the county . The commenter noted that EPA estimates that transporting CO 2 will cost in the range of $1 to $4 per ton, however, according to the commenter, pipelines are not inexpensive or eas y to construct, and it is unclear whether the EPA's estimate includes the co sts of right
- of
- way s, pipeline construction, permitting delays, and length of transportation, among others. Commenter 840 stated the pipelines and storage needed to support safe sequestration of CO 2 does not exist in many

areas of the country

and require s ubstantial public planning and investment. According to the commenter, electric customers cannot shoulder this burden alone and CCS fails to satisfy

the Clean Air Act's requirement for being achievable at a reasonable cost. Commenter 10667 stated the prop osed rule indicates, that the sale of captured CO 2 for Enhanced Oil Recovery

(EOR) offers the opportunity to defray a portion of the CCS costs, however, unfortunatel y, this option does not even exist for interior coal
- fired plants due to the lack of nearb y oil or gas production activities. The commenter provided areas of Alaska where EOR operations exist, noting that the captured CO 2 would have to be shipped to one of those areas since there is no pipeline (also, the closest is 500 miles away). Thus, the co mmenter stated that leaves high costs of partial CCS for new coal fired facilities economicall y and logisticall y impractical and without any benefit from EOR. Commenter 9427 stated EOR, the single geologic storage option that is potentially realistic at present, is only

accessible to a limited geography and faces significant regulatory hurdles and risks. According to the commenter, EPA's cost estimates significantl y underestimate costs, including because they

unreasonabl y exclude "first of its kind" costs and overestimate any cost mitigating effect of EOR. **Response 6.3 -**  **254:** The EPA reiterates that the BSER determination and regulatory impact anal ys is for this rule relies on GS in deep saline formations
. However, the EPA also recognizes the potential for sequestering CO 2 via EOR and allows the use of EOR as a compliance option
.6
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In estimating impacts of the rule, the EPA relied on NETL studies referenced in Section V.I.2 of the preamble , which base transport costs on a generic 100 km (62 mi) pipeline and a generic 80 kilometer pipeline
. For transport, costs reflect pipeline capital costs, related capital expenditures, and O&M costs. See preamble section V.I.5. Pipeline capit al costs include materials, direct labor, right
- of

- way acquisition, surveying, engineering, supervision, contingencies, allowances for funds used during construction, administration and overheads, and regulatory filing fees. 45 See preamble section V. M .5 regarding the availability of CO 2 pipelines and elsewhere in this Chapter 6 regarding feasibility of GS in A laska. **Comment 6.3 -**  **255:** Commenter 10098 stated that EPA has no basis to assume that all CO 2 captured can be sold to a willing buyer. The commenter stated that EPA has provided no anal ys is of the market for CO 2 , including where EOR is being used, whether supplies of CO 2 are actually in demand, or a comparison of the cost of drawing from a natural CO 2 reservoir versus purchasing captured CO 2 . The commenter also indicated that there is a contradiction between the proposed rule and EPA's assumptions for purposes of PSD permitti ng in which EPA has repeatedly

rejected the assumption that the owner or operator of a coal
- fired power plant can sell captured CO 2 for EOR and that those speculative sales should be included in CCS cost estimates. Commenter 10239 also stated concern with the deduction of a portion of CCS costs based on the assumption that EGUs employing CCS technology will sell their captured CO 2 for EOR. According to the commenter, this is factuall y incorrect and inconsistent with the EPA's position in PSD BACT determinations and the GHG Guidance that a facility could not count on the availability

of EOR when assessing the feasibility of CCS technology . The EPA offers no rational basis for reversing the Agency's prior position that there is no guarantee at the time of planning or even construction that EOR will be available to offset a portion of the costs of CCS technology
. **Response 6.3 -**  **255:** The EPA reiterates th at the BSER determination and regulatory impact anal ys is for this rule relies on GS in deep saline formations
. However, the EPA also recognizes the potential for sequestering CO 2 via EOR and allows the use of EOR as a compliance option
. The EPA is assessin g costs conservativel y b y not including any revenues from EOR, even though new plants may

well avail themselves of EOR opportunities (e.g. Boundary Dam and Kemper). **Comment 6.3 -**  **256:** Commenter 9664 stated that revenue generated b y the sale of captured CO 2 for use in EOR further reduces costs associated with the standard. The commenter references anal ys is performed by

CATF in support of the Agency's 2012 proposal that showed that revenue from the sale of captured CO 2 for EOR lowers b y 12 percent the LC OE of applying a standard roughl y equivalent to that currentl y proposed. According to the commenter, EPA may take into account b yproduct revenue associated with a system of emissions reduction, in considering the costs associated with a standard reflecting that s ys tem. The commenter stated that while the D.C. Circuit has yet to address directl y whether EPA may take b yproduct revenue associated with the choice of BSER into account in evaluating the costs of a performance standard, the court has held that the agency retains broad a

uthority to weigh all of the statutory factors in a

45 Carbon Dioxide Transport and Storage costs in NETL Studies (DOE
-NETL
- 2013/1614), p. 11.6
- 159

BSER determination, noting that questions of costs and benefits must be addressed taking a long
term perspective. The commenter then referenced the 2012 cost anal ys is for the new fuel econom y standards fo r light
- duty vehicles providing additional discussion, and concluded that it is well reasoned
- wholly logical and appropriate
- for EPA to consider revenue streams from the co - production of CO 2 (from the sale by the regulated power plant of captured CO 2 t o an EOR operator for use and long
- term containment in depleted oil or gas fields, e.g.) in evaluating the costs of a standard for which the underl yi ng BSER includes carbon capture technology . The commenter also states that although EOR sales are not now a vailable every

where, it is expected that any new coal fired subpart Da unit would locate so as to take advantage of such revenue offsets to the cost of applying control technology to meet the standard. According to the commenter, EOR operations in the U.S. can accommodate and provide long
- term containment for substantial volumes of CO 2 as well as the cost
- offsetting revenue attendant to the sale of the anthropogenic CO 2 by

the EGU operator. Commenter 9035 stated it is crucial that power companies are enabl ed to sell captured carbon to CO 2 - EOR operators and that EPA continue to recognize a pathway for demonstrating the geologic storage of CO 2 through EOR projects. Commenter 9514 stated that while they do not intend their comments to endorse the practice of EOR, section 111 allows a broad consideration of costs, including the sale of byproducts, and EPA may properl y take the possibility of EOR sales into account when evaluating the costs of the proposed performance standard. The commenter cited See Sierra Club v. Costle, 657 F.2d at 330. ("[S]ection 111 . . . gives EPA authority when determining the best technological sy stem to weigh cost, energy , and environmental impacts in the broadest sense over time."). Commenter 10108 stated EPA has considered revenues from compliance measures when conducting cost anal ys es in past rulemakings, and referenced the 2012 rulemaking revising the NSPS for oil and gas facilities, in which EPA considered revenues from increased recovery of natural gas when evaluating the cost
- ef fectiveness of measures to reduce VOC emissions and in a 2012 regional haze FIP in which the Agency adjusted its proposed cost calculations to take into account fl y ash sales that could be continued through more
- efficient technology . As a result, the commenter stated that EPA's discussion of costs reasonabl y includes the potential EOR revenues from CCS even though it does not rel y on EOR revenues in arriving at the $110/MWh cost figure it deems reasonable. According to the commenter, the cost of CCS with co al is reasonable even without EOR and the availability of non
- EOR carbon sequestration sites is widespread in the United States, noting that almost all existing large sources of CO 2 are located within 50 miles of a possible sequestration site
. **Response 6.3 -**  **256:** Revenues fro m by
- product sales can be relevant in assessing costs under section 111 (a). See New York v. Reilly , 969 F. 2d 1147, 1150
- 52 (D.C. Cir. 1992). However, the EPA is (conservativel y) not considering such potential revenues here in its assessment of costs. S ee preamble section V.E.8. **Comment 6.3 -**  **257:** Commenter 9772 stated the viability of using CO 2 for EOR is "site and situation
- specific" and depends on a number of factors: location, geologic characteristics of the location, state of development and depletion of the target f ield, the amount of CO 2 required and a number of infrastructure investments, including pipeline construction. The commenter6
- 160

referenced a study from the Global CCS Institute which noted, "total CO 2 costs (both purchase price and recycle costs) can amount to 25% to 50% of the cost per barrel of oil produced. As such, operators have historically strived to optimize and reduce the cost of its purchase and injection wherever possible." Commenter 9486 questioned, in the context of using captured CO 2 for EOR, what the net reduction of CO 2 would actuall y be given the proposal, and what the net cost would be for that reduction. The commenter stated that this rule, as it is currently structured, shifts the cost of CO 2 emissions from one fossil fuel secto r to another and the net decrease in CO 2 emissions would not be cost effective under the BSER requirements. **Response 6.3 -**  **257:** The EPA is not basing its cost assessment on utilization of EOR. **Comment 6.3 -**  **258:** Commenter 9678 stated that EPA has also not adequately addressed the regulations an d guidelines that are applicable to EOR. Specificall y, the commenter noted that EPA's Draft Underground Injection Control (UIC) Program Guidance on Transitioning Class II Wells to Class VIWells could have a substantial impact on EPA's determination of BSE R by affecting both the availability of CCS and the relative cost of CCS. The commenter discussed that if the guidance serves to decrease the availability of EOR for sequestration of EGU
produced CO 2 , then this could have a substantial impact on EPA's asse ssment of the availability and cost of partial CCS. The commenter also discussed that EPA has failed to note in the Proposed Rule that there are significant differences in the regulatory requirements that apply

to Class II versus Class VI wells, including different levels of financial responsibility (for corrective action, post
- injection site care and remedial response), reporting requirements, and post - injection site care and site closure. The commenter concluded that EPA must more fully assess the multipl e barriers that still exist to long
- term geological storage of CO 2 and the impact of these barriers on the projected availability of partial CCS and the costs of the Proposed Rule, before it may

determine the level of a NSPS based on the use of CCS technol ogy . Commenter 9425 stated EPA should not rely on the potential resale of captured CO 2 for use in EOR to reduce the expected cost of its proposed CCS mandate. According to the commenter, many EOR operators are concerned that the proposed rule's requirement for EOR operators that purchase CO 2 from EGUs to have to report emissions under the more stringent requirements of Subpart RR of 40 CPR Part 98, rather than Subpart UU with which they currently comply , will create regulatory

uncertainty

and risk. The co mmenter stated that EGUs may have to pay

EOR operators to take the CO 2 which would remove any cost justification that EPA ascribes to CCS based on EOR. The commenter also stated that EPA admits that resale for EOR is "non
economical" or unavailable for som e locations in which new coal units may be built (79 FR 1478), and therefore, the cost of CCS with resale for EOR does not represent the cost of installing CCS on new units throughout the country , and should not be considered in determining the proposed NS PS. Commenter 9596 stated that EOR sites are not available in many parts of the country , while in others there may

be significant infrastructure barriers (in particular, the need to construct new pipelines) that will substantially raise the costs of using this sy stem of emission reduction. The commenter also stated there is a real possibility that EOR operators will not accept CO 2 from EGUs due to the uncertainty and risk of reporting under Subpart RR (in particular, complying6
- 161

with Subpart RR's requirement to prepare and comply with a MRV plan for geologic sequestration of CO 2 ) and the burdens inherent in transitioning from a Class II well to a Class VI well under EPA's proposed Underground Injection Control Program policy. Commenter 9197 stated that even wh ere EOR is available and operators are willing to accept CO 2 from regulated power plants, the added risks to well operators from EPA's policies could significantl y reduce the amount that these operators will pay for captured CO 2 . Therefore, according to th e commenter, it is likely that the costs of implementing the NSPS will be significantl y higher than those cited by EPA in the proposed rule
- especially for EGUs that are located far from viable EOR sites. Commenter 9486 stated that it is common understandin g that EOR can use no more than 20% of the CO 2 expected to be captured b y the full implementation of CCS, and as such, an EOR market with an overabundance of CO 2 available will not generate the same revenue for EGUs from the sale of CO 2 as U.S. EPA estimat es. According to the commenter, without the monetary compensation associated with the sale of CO 2 to oil companies, the cost for CCS becomes even more prohibitive. **Response 6.3 -**  **258:** Commenter 9678 questions whether Class II wells may automatically convert to Class VI b y virtue of reporting under GHGRP subpart RR. Reporting under subpart RR does not trigger the transition of a Class II well to a Class VIwell. See preamble section V.N .5.a. Furthermore, on April 23, 2015, the EPA issued a memorandum from the Director of the Office of Ground Water and Drinking Water to regional UIC Program Directors in its regional offices, and summarized in section V.N.5.a of the preamble, that makes cl ear that the commenter’s concerns with respect to the guidance are misplaced. The EPA is aware that the regulatory

requirements differ for Class II and Class VI wells. The compliance cost estimates for the final rule are based on the more expensive costs for Class VI geologic sequestration. See preamble section V.I.5 and N.1. Commenter 9425 and 9596 stated that EPA should not rely on the potential resale of captured CO 2 for use in EOR to reduce the expected cost of its proposed CCS mandate, and EPA in fac t is not doing so, as noted in other comment responses. However, as explained in preamble section V.N. 5 and elsewhere in this chapter , there are sound, objective reasons to believe that EOR operators will continue to pay for anthropogenic CO 2 . **Comment 6.3 -**  **259:** Commenter 1591 stated that EPA is justifying the costs of CCS on NOAK costs when in fact there is not even a single FOAK plant of commercial scale in operation. According to the commenter, further compounding this error, EPA then improperl y assumes that the other pl ants EPA cites as "under development" (more accuratel y characterized as "under consideration") will use the same technology as the FOAK plants. Commenter 9666 stated EPA incorrectl y assumes that any future Subpart Da unit equipped with CCS would face lower "next
- of
- a - kind" costs rather than the unreasonably high "first
- of

- a - kind" costs incurred b y CCS units currently in development. According to the commenter, the units under development, however, each contain unique CO 2 capture processes and other design elements. The commenter concluded that for these reasons, and other uncertainties that must be6
- 162

resolved (property rights, water, etc.), EPA cannot assume that "next
- of
- a - kind" costs for CCS will necessaril y be lower than "first
- of
- a - kind." Commenter 10098 stated that using NOAK cost assumptions is arbitrary and capricious. According to the commenter, the proposed rule's cost estimates in Table 6 are not those that would actuall y be incurred by a commercial
- scale coal
- fired power plant constructing and operating an experimental, demonstration
- scale CCS unit, as would be required to comply with the proposed rule's emission limitation. Instead, the commenter suggested they are the costs for mature CCS technology

that do "not include the unique cost premiums ass ociated with FOAK plants that must demonstrate emerging technologies and iterativel y improve upon initial plant designs." The commenter explained that the L COE costs relied upon EPA are not the actual costs of complying with the proposed NSPS emission limi tation but the conjectural, estimated costs of constructing and operating CCS at some time in the unspecified future, assuming that there is widespread adoption, and further assuming that there are several successful research and development projects. Co mmenter 9472 discussed how EPA ignores the limitations of the CCS cost estimates in the NETLanal ys is, stating that the substantial uncertainty and potential for significant variations in CO 2 storage costs limit the usefulness of the NETL study in evaluati ng the cost basis for CCS in NSPS. The commenter also suggested that EPA recognize the limited opportunities for learning to date and use higher FOAK cost estimates while appropriatel y noting the uncertainty and limitations of those estimates. Commenter 10 618 stated that the use by EPA of CCS costs that are premised on the conjecture of NOAK projects does not remotely provide reliable, accurate estimates, is irrelevant for use in preforming any objective anal ys is of new generation options, and has the appearance of being nothing more than weak attempt to justify a preconceived BSER outcome that could not otherwise be validated through the use of more reasonable and accurate information. The commenter stated that EPA's cost analy sis fails to demonstrate that CCS is the BSER and cites the following reasons:

 an incorrect assessment of the development status of CCS, which results in using cost estimates for yet - to - be realized more mature nth
- of
- a - kind ("NOAK") type technologies, rather than initial first
- of

- a - kin d ("FOAK") technologies;  a narrow reliance on two reports that are based on dated vendor supplied conceptual designs for CCS and IGCC technologies that have **never** been constructed or proven;  a failure to consider **any** of the costs and lessons learned from a ctual CCS related projects that have been constructed or that are activel y being developed; and  a failure to consider more recent and relevant studies of the cost of advanced coal
- based generation and CCS technologies. Commenter 10618 also stated that EPA 's cost analy sis is flawed due to an incorrect assumption that CCS development has advanced beyond FOAK technologies. The commenter noted that reliable demonstrated FOAK costs for CCS and advanced coal generation technologies, such as IGCC, are not availab le . According to the commenter, the current state of CCS development has been widel y recognized to be at the FOAK deplo yment phase, including b y the Interagency Task6
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Force on CCS. According to the commenter, in regards to IGCC, any cost estimates for futur e projects are speculative at best due to the earl y stage of development. The two IGCC projects under active construction and commissioning in the U.S. are both FOAK processes and have both experienced significant cost escalations throughout their developm ent. The commenter agreed that certain highl y efficient generating technologies are cost effective as evidenced b y the number of projects that are being successfull y completed worldwide. Commenter 10618 stated that reliable baseline costs, performance in formation, and lessons learned from FOAK CCS projects are required before the true scope of cost implications can be understood; however, because CCS development issues are far from being one
- sized
- fits
- all, the completion of multiple commercial
- scale proj ects on coal
- based generating units is critical for informing for any meaningful cost estimate of future NOAK CCS processes. The commenter stated that EPA does not take into account the cost, performance, and other lessons learned from the AEP Mountaineer Plant CCS Validation Project in its reliance on the NETLreport. The commenter stated that the recent experience of CCS and advanced coal
- based generation projects underscores the difficulty of developing reliable costs FOAK technologies, yet alone the si gnificant uncertainty and challenge of being able to assess the cost of future FOAK and especiall y NOAK projects with any degree of accuracy. According to the commenter, this difficulty is highlighted by

the projects that EPA relies upon in the proposed ru le where there is a wide disparity

in costs and where each project is experiencing significant cost escalations. Commenter 10618 stated a number of recent assessments have concluded that CCS for fossil fuel
- fired electric generation currentl y is and will r emain at the FOAK level of development for many years. According to the commenter, these conclusions do not support EPA's use of cost estimates that the agency presumes represent technologies that have matured beyond FOAK projects. The commenter referenced the 2010 DOE/NETLCCS Roadmap which noted that the DOE RD&D effort " involves pursuing advanced CCS technology...so that full
-scale demonstrations can begin by 2020 " in order to " enable broader commercial deployment of CCS to begin by 2030 ." The commenter also referenced the DOE/NETL "Carbon Capture" website discusses the following in the very first paragraph : "

first
-generation CO 2 capture technologies are currently being used in various industrial applications. However, in their current state of developmen t, these technologies are not ready for implementation on coal
- based power plants because they have not been demonstrated at appropriate scale, require approximately one - third of the plant's steam and power to operate, and are cost prohibitive. " The commenter referenced another s eparate NETL report that notes " the definition of the NOAK plant is somewhat arbitrary as well, although it is often taken as the fifth or higher plant. " According to the commenter, the minimal commercial
- scale CCS projects that are actively being developed may be sufficientl y unique as to limit the overall progress of the technology beyond FOAK applications. The commenter also stated that the DOE CCS Roadmap also estimates that commercial
- scale CCS will add 80% to the cost of electricity for a new pulverized coal unit and 35% to the cost of a new IGCC unit and highlights the infancy of the technology

as a potential emissions control option for coal
- based generation, and therefore it is clear from this information that cost estimates for future CCS projects are far from being able to accurately represent NOAK processes.6
- 164

Commenter 10618 stated that for any individual project, the cost estimate will change throughout the phases of development: (i) conceptual design; (ii) front
- end engine ering & design (FEED); (iii) detailed design; (iv) construction; (v) startup & commission; (vi) operational. According to the commenter, as technologies mature, the cost differential between conceptual design and operational cost will become less, and this cost differential for an individual project can vary significantl y across the development cycle, as well as from project to project that employ FOAK technologies. The commenter provided tables that summarize costs of actual CCS projects that have been or that currently are being developed to demonstrate this variability and to highlight the fact that CCS technology is far from advancing beyond a FOAK level of development. Commenter 9780 stated that the following important factors appear to be ignored in th e NOAK cost projections: (1) CCS projects currentl y under construction have experienced significant cost overruns, which are not accounted for in the NETL FOAK cost anal ys is that is the baseline for projecting the nth of a kind costs EPA relies upon; and ( 2) the anal ys is does not reflect the cost premiums associated with earl y plant deplo ym ents, which carry significantly

higher cost and engineering procurement and construction premiums not reflected in the cost analy sis. The commenter provides analy sis of the NETL report, noting that EPA has adopted the cost estimates while omitting several important cost considerations. The commenter also stated that EPA has not justified its assumption that the costs of CCS will decrease more quickly than other costs, and provided additional discussion that there is no reason to believe that substantial new assistance
- driven demonstration projects will be undertaken to drive down costs of CCS on EGUs. Commenter 10239 stated the EPA seeks to reduce the L COE for partial CCS b y using projected NOAK costs when there is currentl y no FOAK example of a commercial
- scale coal
- fired EGU applying any form of CCS. The commenter stated that in the absence of an established technology , it is arbitrary and capricious for the EPA to ignore the unique cost premiums associated with FOAK plants that must demonstrate emerging technologies and iterativel y improve upon initial plant designs. Commenter 10952 noted that that EPA uses a few demonstration CCS projects as FOAK projects to then conclude that next projects can be evaluated at "next commercial offering costs," although it fails to use actual cost data associated with these first project costs. Commenter 10952 stated that EPA cannot reasonably rel y on Table 6 LCOE data that are base d the theory

that as technology

matures with the construction of successive plants, the cost decreases. According to the commenter, for either full or partial carbon capture, technology adjustments, increasing material and labor costs, and unforeseen inter vening factors can significantl y inflate what the proposal describes as L COE for a next commercial offering or a NOAK facility . The commenter stated that the docket contains no information on the methodology

utilized to arrive at the conclusion that "next commercial offering" cost would even approximate the L COE data in Table 6, and why in fact the next commercial offering would not exceed even a FOAK facility . The commenter discussed each of the projects in the EPA analy sis, noting that no facilities cite d as FOAK are completed and most are ye ars away from it, with no operational data available to gauge facility eventual costs, reliability and availability . The commenter presented a table to show capital costs associated with the facilities that EPA cites as FOAK, in addition to the Edwardsport IGCC project, and stated that the cost differentials6
- 165

between EPA's presumed NOAK and FOAK and Edwardsport costs are enormous. According to the commenter, based on actual FOAK costs data, EPA methodology presumes the next - of

- a kind unit L COE would be between 53 to 58 percent of the FOAK unit L COE, and for the Edwardsport facility , one that EPA describes as a successive IGCC technology application, the next - of
- a kind unit L COE would be 67 percent of the Edwardsport faci lity L COE. Based on this anal ys is, the commenter stated that learning by doing cannot provide significant step changes in cost and performance to make carbon capture more economically viable
. Commenter 10029 stated that several billion dollars have been invested into research and demonstration of CCS and yet it has not been commerciall y introduced for its intended purpose of mitigating GHG emissions from fossil fuel powered electric generating units (EGU). The commenter cited a Harvard Belfer Center discussion paper (2009) "Realistic Costs of Carbon Capture" which offers a general range for FOAK plants of $110/t CO 2 avoided (with a range of $90
- 135/t CO 2 avoided) and for NOAK plants costs are expected to be $25
- 50/t CO 2 avoided. According to the commenter, considering that we are likel y several decades away from NOAK economies of scale it is prudent to focus on FOAK avoided carbon costs for near term anal ys is of EGU carbon mitigation. Commenter 9780 also stated that EPA must correct significant flaws with the L COE anal ys is, the largest of which is the use of something less than FOAK costs for a technology that has not been widely developed. The commenter stated that the costs are unreasonable wh en technology is not ye t demonstrated and commercially deployed. According to the commenter, the following important factors appear to be ignored in the NOAK cost projections: (1) CCS projects currentl y under construction have experienced significant cost overruns, which are not accounted for in the NETLFOAK cost analy sis that is the baseline for projecting the nth of a kind costs EPA relies upon; and (2) the anal ys is does not reflect the cost premiums associated with earl y plant deploy ments, which carry

s ignificantl y higher cost and engineering procurement and construction premiums not reflected in the cost analy sis. The commenter discussed additional concerns with the NETL LCOE anal ys is, such as the exclusion of capital cost contingencies. Additionally , the commenter stated that EPA has not justified why the departure from FOAK costs is warranted at this earl y state of CCS development. The commenter also noted that there is no reason to believe that substantial new assistance
- driven demonstration projects will be undertaken to drive down costs of CCS on EGUs Commenter 9734 stated EPA's reliance upon levelized cost does not provide an accurate estimate of actual plant costs. According to the commenter, although levelized costs are a convenient summary measure of the overall competitiveness of different generating technologies, actual plant investment decisions are affected b y the specific technological and regional characteristics of a project, which involve numerous other considerations not taken into account when projecting levelized costs. The commenter stated that EPA has chosen to ignore the unique cost premiums associated with FOAK plants that must demonstrate emerging technologies and iteratively

improve upon plant designs. The commenter then stated that EPA ignores the fact that because the Kemper and Boundary Dam projects are still being developed, it is premature to classify all subsequent plants as NOAK. The commenter provided information on the delay s and cost overruns associated with the Kemper pro ject and the AEP Mountaineer Station project. The commenter concluded that when the true cost of these projects including these cost overruns is6
- 166

taken into account (under a FOAK plant approach), it is clear that IGCC/partial CCS is exorbitantly

expensive and thus cannot meet the definition of a "standard of performance. **Response 6.3 -**  **259:** Commenters maintained that the next plants with CCS would be First
- of
- a Kind (FOAK), and that costs should be assessed on this basis. They thus challenged any assumption that costs would be nth

- of
- a - kind (NOAK). However, the EPA notes here (and elsewhere) that, both in the proposal and in the final, the costs for new sources implementing any level of CCS are assumed to represent the “next
- of
- a - kind” or “next commercial offering”, rather than nth

- of

- a - kind (NOAK). For the final cost estimates, the EPA relied on very re c ent updates to DOE/NETL studies (NETL , June 2015 and July 2015). Those studies stated: “[I ]n all cases, the report intends to represent the next commercial offering and relies o n vendor cost estimates for component technologies (emphasis added, June 2015, p. 20). Importantly , the most recentl y updated reports relied on vendor quotes from Shell Cansolv

– the technology that is currentl y being used in the Boundary Dam project in Canada. The DOE/NETL studies also “ applies process contingencies at the appropriate subsy stem levels in an attempt to account for expected but undefined costs, which can be a challenge for emerging technologies. ” (Ibid, p. 20) The EPA understands that actual costs of new generation projects can deviate from the cost estimates provided in the final preamble. However, many of the factors that can lead to cost deviations for new EGUs utilizing partial CCS would also affect the costs for a new EGU that is not in cluding the equipment needed to implement partial CCS. L ocal labor rates, quality and availability

of local water, local seismic conditions, financing arrangements, weather delay s, availability

and cost of construction materials such as steel and cement, among many other factors, would affect the construction schedule and costs for a new EGU

– with or without CCS. This is the case for any large construction project

– or even home construction. The EPA does not suggest that the next constructed IGCC unit wou ld definitely not suffer from the same non
CCS related issues that contributed to the cost overruns and schedule delays at Kemper and Edwardsport. Howe ver, the EPA does note that IGCC is not a component of the BSER for the final standard for new steam generating EGUs. The final BSER is a highly efficient supercritical PC unit implementing partial CCS to meet a standard of 1,400 lb CO 2 /MWh
- g. The AEP John W. Turk facility

is an example of a highl y efficient supercritical PC. In comments of AEP (p. 76), AEP represented the cost of the Turk facility as $2,885/kW. The DOE/NETLestimates for such a facility is $2,842/kW (NETL , 2015 p. 17

– for a plant using bituminous coal). This close agreement in cost estimates is another indication of the reliability of the N ETLcost projections. Regarding the comment that billion s of dollars have been invested into research and demonstration of CCS and yet it has not been commerciall y introduced for its intended purpose of mitigating GHG emissions from fossil fuel powered electric generating units (EGU). We note that there are several technology providers that offer “commerciall y available” carbon capture technology . The companies have brochures (see brochures of MHI, Shell Cansolv, L inde , etc. in the docket), they

have web sites that promote their products, they sponsor vendor booths at major power sector conferences, etc. As discussed in the preamble, it is often regulatory requirements that promote deploy

ment and advancement of control technologies. The fi rst commercial in stallations of flue gas desulfurization technology on boilers larger than 100 MW in 1968 . The first NSPS for SO2 was promulgated in 1971. By the time of the promulgation of the SO2 NSPS in 1971, only

three commercial scrubber units were operating on power plants in the United States. In1971, onl y one scrubber vendor was in the utility FGD market. By

the end of the6
- 167

1970s, sixteen U.S. firms supplied FGD s ys tems to utilities . There was also a large step increase in patent activity

in SO2 control technology patents following the 1971 SO2 NSPS. (See the TSD on “ History

of Flue Gas Desulf

urization Use in United States: 1970
- 1976 ” available in the rulemaking docket.). Certain commenters (9472, 1591) maintained that because there are no operating plants at commercial scale with CCS, by definition, the next plant would have to be FOAK. Boundary Dam Unit #3 is a full
- scale commercial SCPC utilizing full post
- combustion CCS. Other plants operating, or soon
- to - be operated likewise provide substantial operating experience or other experience which forms a basis for next plants to draw upon . See preamble section V.D. The commenters also ignore the substantial public
- and private
- sector research which will have a positive impact on reducing cost and improving performance of the next CCS plants to be built. See generally

preamble section V.I.2. Other commenters (9666, 10618 , 9472 ) maintained that every new plant will be unique, especiall y with respect to sequestration and also to some extent in choice of capture and co mpression technology , so that almost by definition, these plants will be FOAK. EPA’s cost estimates for sequestration reasonabl y rel y on the very extensive rulemaking record developed for the Class VI regulation, and th is robust record provides cost estim ates which are reasonabl y representative . See preamble section V.I.5 and N . Certain sites may be more challenging, and both AEP and other commenters referred to the AEP Mountaineer demonstration project as an example , where siting of a sequestration site proved feasible but expensive due particularly to the number of monitoring wells needed. This project involved a retrofit to an existing facility (see preamble section V.D.3.b), whereas a new source could making siting decisions which pose less of a chal lenge. The Class VIpermits issued to date, for example, required many fewer monitoring wells than AEP found to be needed. There are also compliance pathway s to meet the final standard of performance which do not involve sequestration if a source is det ermined to site at a location which is unsuitable for sequestration. Inaddition, the EPA does not accept that each compression and capture technology is so unique as to be a new first
- of
- a - kind decision with each deplo ym ent. Both post
- and pre
- combustion carbon capture are well established technologies based on recognized processes which are activel y marketed. See preamble section V.F. For example, Southern Company ’s Mississippi Power has stated that, because the SelexolTM process has been used in industry for decades, the technical risk of its use at the Kemper IGCC facility

is minimized noting that “The carbon capture equipment and processes proposed in this project have been in commercial use in the chemical industry for decades and pose little technology risk.” 46 Commenter 10618 criticized EPA for basing decisions on what it characterized as dated vendor reports. The EPA does not accept the characterization, but has made every effort to obtain the most up - to - date information on cost, in part in respons e to this and similar comments. In particular, cost estimates for post
- combustion CCS reflect cost information from recent vendor quotes of the Shell Cansolv post
- combustion capture process

– the process that is currentl y being

46 Mississippi Power Company, Kemper County IGCC Certificate Filing, Updated Design, Description and Cost of Kem per IGCC Project, Mississippi Public Service Commission (MPSC) DOCKET NO. 2009
- UA
- 0014, filed December 7, 2009.6
- 168

utilized at the Boundary

Dam #3 facility. The EPA has also carefull y monitored the most recent marketing materials and estimates, which, as explained in preamble section V.I.2.c, are corroborative of the NETL cost estimates. A number of commenters (e.g. 9780 , 9374 ) stressed that actual projects have had huge cost overruns, and that these plants should form the basis for cost estimates, not projected, hy pothetical plants as reflected in the NETL estimates. Some commenters (e.g. 9666) maintained that I GCC costs were especiall y speculative. The EPA has carefull y considered this issue. Kemper, an oft
- cited example in the comments, had cost
- overruns not related to CCS (per the report to the Mississippi Public Utility Commission cited in an earlier comment response in th is unit). AEP involved a retrofit to an existing facility, which occasioned costs (especiall y related to siting of monitoring wells) that a new source could avoid at the outset. Boundary Dam ultimately

came in on budget for the capture portion of the pro ject , and has predicted publicall y that costs of a next plant would be 30% less. See also preamble section V.I.3. Commenter 10952 states that there is no information in the record supporting an assumption that next plants to be built would have NOAK costs . This is mistaken. SaskPower Executive Michael Monea has stated publically that the next post
- combustion CCS plant using Shell Cansolv compression and capture process can expect to see at least a 30% reduction in cost , as just noted
. EPA’s cost estimates for post
- combustion partial CCS are based on recent vendor quotes for this Cansolv process. More generall y, these comments assume that learning b y doing, with consequent reduction in costs, simply does not apply

here. The EPA disagrees. The NETL assumpt ion of NOAK is not unique. Technology vendors are currentl y providing cost estimates in the marketplace which not only have the same premise

– that costs for next plants will be less than those of the FOAK plants

– but are lower than the NETL estimates. S ee preamble section V.I.2.c. The NETL estimates are also consistent with techno
- economic models of other established entities, meaning, again, that these other entities likewise are using NOAK cost estimates. See id. section V.I.2.b. Commenter s 9780 and 9666 state that the NETL estimates do not account for capital cost contingencies, which are ty pical for FOAK plants. The commenter is mistaken. The NETL estimates used for the final rule use high
- risk financial assumptions for all CCS cost estimates. NE TL2015 at p. 18. Finally , a number of commenters cite to statements of various non
- industry entities for the proposition that CCS will be unavailable until such dates as 2020. These quotations had a different context, referring to full CCS, or to CCS retrofits. See generall y preamble section V.G.3. **Comment 6.3 -**  **260:** Commenter 10108 stated that EPA's determination that the costs of CCS are reasonable is supported by current experience as well as expected future costs. The commenter stated that the CCS component of SaskPow er's Boundary Dam project, scheduled to come online later this year, is actually 6% under budget. The commenter also stated that SaskPower recently stated that by

2016 other units at the Boundary Dam facility

could be repowered with CCS without government subsidy , and it estimates that the cost of its next carbon capture project will be 20
- 30% lower than Boundary Dam. According to the commenter, this leading case study offers a promising perspective on the present and future costs of CCS, and corroborates E PA's6
- 169

conclusion that "next
- of

- a - kind" CCS facilities, like many other emission control and energy technologies in the past, will experience reductions in cost over time. **Response 6.3 -**  **260:** The EPA agrees that the Boundary Dam experience is indicative that cost of next plants will reflect present operating experience and be substantiall y less as a result. The EPA’s information, obtained from the project developer, likewise is that the CCS portion of the project came in at budget. Boundary Dam Unit 3 (BD3) was recentl y awarded POWER Magazine’s “Plant of the Year” award. (http://www.powermag.com/saskpowers
- boundary
- dam
carbon
- capture - project
- wins
- powers - highest
- award/). In recognizing the Boundary Dam Unit 3 plant, POWER noted that “the SaskPower team has taken what actually con stitutes a giant leap for the coal
- fired power industry”. In the article 47 SaskPower notes that this first
- of
- its
- kind carbon capture plant was finished on budget; challenges associated with the existing power plant were the cause of cost overruns. They also noted that the performance far exceed s the expectations at the project’s inception
. **Comment 6.3 -**  **261:** Commenter 10098 stated that the proposed rule's levelized cost of electricity (L COE) figures are arbitrary and capricious. According to the commenter, EPA's esti mates incorporate a number of errors, including a lack of foundation for its CCS cost estimates, a lack of real
- world construction and operations data and improper assumptions that artificiall y reduced EPA's cost estimates and ignore the higher costs assoc iated with a first
- of
- a - kind technology
. The commenter referenced the source relied upon by EPA in their claim that "partial" CCS, with an emission rate of 1,100 lb CO 2 /MWh, will only add $18 to the cost of electricity for a pulverized coal boiler and note d that the only study relied upon by

EPA that even speaks to the costs of "partial" CCS shows that cost of electricity will increase b y twice as much as the proposed rule's estimate. Therefore the commenter stated that EPA's $18/MWh cost estimate is arbitrary and capricious because it not onl y lacks support, but is clearl y contradicted b y the administrative record. Commenter 10039 stated that US EPA's reliance on US DOE/NETL "Cost and Performance" reports as a basis to justify partial CCS costs as reasonable is misplaced and inappropriate. According to the commenter, US DOE estimates of levelized costs of electricity (L COE) which are used to establish the reasonableness of CCS technology costs make several assumptions for the purposes of their calculations which skew the anal ys is by identifying the low end of the costs of CCS. The commenter stated that US DOE estimat es of LCOE are not universally

applicable as they

are not derived based on national averages or even realistic scenarios, and they

also do not address realistic costs for permitting, insurance, construction, and easement costs of CO 2 pipelines and storage areas because it makes assumptions about locally available storage areas and the sharing of that storage capacity that unrealistically

result in significant underestimation of the cost of a CO 2 storage site on a $/tonne of CO 2 stored perspective. The comme nter stated that the US DOE report utilizes the least cost storage location option of the four to assess L COE estimates despite the fact that two of the four locations have significantl y higher costs. According to the commenter, picking the lowest cost loc ation is

47 “ SaskPower’s Boundary Dam Carbon Capture Project Wins POWER’s Highest Award ”, POWER Magazine, (8/1/2015), Available at: http://www.powermag.com/saskpowers
- boundary
- dam
- carbon
- capture - project
- wi ns powers - highest
- aw ard/6
- 170

arbitrary and capricious as it has no basis in actual EGU siting criteria and does not represent a national average. Therefore the commenter suggested US EPA abandon the US DOE CCS cost anal ys es as they

are arbitrary

and biased estimates of the co st of CCS. Commenter 10952 stated concern with the use of DOE funded demonstration projects in determining the LC OE estimates to reach its BSER conclusion, and questions EPA's focus on NOAK costs provided in Table 6 of the proposal. The commenter stated th at according to the DOE studies of which EPA relies, the margin of error of the derived L COE data ranges from
- 15 to +30 percent, and this wide margin of error makes any chosen LC OE costs within this wide range arbitrary . The commenter noted that for Table 6 costs, EPA has chosen the midpoint from the data extrapolated from these studies for its LCOE predictions, but even at that midpoint level the L COE for SCPC EGU with partial carbon capture is 20 percent above a SCPC EGU without carbon capture, and this increase is well above any level determined to be judicially permissible, as EPA recognizes in Portland Cement 486 F.2d. 387, where onl y a 12 percent capital cost increase was a level considered permissible. The commenter also noted that if the actual LCOE for SCPC with partial capture is 30 percent above the L COE midrange prediction, again a LCOE within the stated margin of error, the resulting partial carbon capture cost would increase the SCPC facility

by 24 percent. The commenter also noted that the Tab le 6 LCOE data, and the proposal overall, do not factor in CO 2 transport and sequestration costs where EOR is not available. Commenter 10952 references a study which concludes that EPA misused the DOE studies to derive CCS cost estimates, and that the DOE studies were intended to be used to derive preliminary

estimates of feasibility

and costs and were never meant to determine actual costs to be used as a basis in a national rulemaking that will dictate the nation's future energy policy . The commenter also stated the DOE reports upon which EPA relies were not peer reviewed and underlying assumptions were not made available for comment in connection with this rulemaking. According to the commenter, these DOE studies were intended to be used to derive prelimi nary

estimates of feasibility

and costs and were never meant to determine actual costs to be used as a basis in a national rulemaking that will dictate the nation's future energy policy
. Commenter 9678 stated that they do not agree with EPA's reliance on L COE estimates in evaluating the cost
- effectiveness of its proposed emission limits and BSER determinations. According to the commenter, L COE provides a useful metric in many contexts, but not for purposes of determining BSER. The commenter stated L COE is an economic tool designed not to discern the costs of various alternative levels of BSER, but rather to evaluate the competitiveness of a technology in the broadest possible terms. The commenter stated that the use of L COE in this rulemaking also departs from past Agency practice, as in previous CAA section 111 rulemakings, EPA considered both the overall costs involved per year and the cost
effectiveness of a CAA section 111 standard in terms of cost
- per - ton of air pollutant removed. Commenter 9666 stated that the problem with the use of the LCOE metric is that it averages the cost of generation over the lifespan of the generating unit and fails to account properl y for significant differences in upfront capital and related financing costs, which are typicall y much higher for coal
- fired units, especiall y with the integration of CCS, than for NGCC facilities. According to the commenter, because corporate decisions on generating technologies will be6
- 171

driven in large part not only by a LCOE metric but by

upfront f inancing and capital constraints, EPA erred b y not factoring these considerations into its cost analy sis. Commenter 9197 stated that based on DOE estimates, the projected cost of electricity from new coal
- fired facilities with CCS is likely to be far highe r than that of most other alternative baseload technologies. According to the commenter, the need to overbuild/oversize sy stems in order to compl y with the NSPS in the context of a 24
- hour duty cycle and the need to rely on third party CO 2 pipeline and sequestration service providers will increase cost estimates. The commenter referenced EPA L COE estimates and DOE EIA estimates for LCOE. C ommenter 7977 referenced a 2013 State of Kentucky Energy and Environment Cabinet anal ys is which concluded the levelized cost of electricity (LCOE) with CCS technology is higher than the LCOE without CCS. According to the anal ys is, estimates indicate that the addition of CCS to either an IGCC or USCPC facility would increase cost per kWh by 40 percent to 58 percent respectiv el y. Commenter 10095 stated that NETL document used as the source for CCS cost assumptions highlights the changing landscape of CCS costs and the need for multiple cost reference points. The commenter stated that EPA did not analyze the full range of the c ost estimate in setting a nationwide BSER and performance standard applicable to all new coal
- fired generation, noting the
- 15 to +30 percent accuracy of the NETL report. The commenter stated that while EPA estimates the capital cost would increase b y 35 p ercent for SCPC to incorporate partial CCS, no previous EPA NSPS proposal has increased the cost of constructing a new affected facility by 35 percent. The commenter presented their own analy sis, in which they conclude that EPA potentially

underestimated the average costs of partial CCS by 23 percent for SCPC. The commenter stated that EPA's LCOE analy sis is flawed as it is based on one source and does not consider the full range of cost estimates. Using the upper range of NETL cost estimates, the commenter argued that generation technologies with partial CCS may be costlier than other new non - fossil, low emitting baseload generation technologies such as nuclear. Commenter 10239 stated the EPA's attempt to justify the proposed standard by comparing the leve lized cost of electricity from new coal
- fired power plants with and without CCS is arbitrary , capricious, and unlawful. According to the commenter, because of the serious defects in the EPA's levelized cost analysis, the Agency has no basis for using the anal ys is to justify the proposed rule. The commenter provided cost information from the 2011 NETLstudy in which partial capture would increase costs by 43.3% and stated that the only evidence from NETL suggests that the costs of partial CCS would be more than twice as high as the EPA's estimate of $18/MWh. In the absence of any supporting evidence to contradict the NETLstudy , the commenter stated that EPA's cost estimate for partial CCS is arbitrary and capricious. Commenter 10239 also stated the EPA lacks an y real
- world data on which to base its cost estimates as there are no commercial
- scale coal
- fired EGUs employing CCS any where in the world. As a result, the commenter argued EPA has no factual basis for projecting levelized cost of electricity

estimates . According to the commenter, it would be arbitrary and capricious to rel y on estimates generated from facilities currently under construction because of the well
documented cost overruns occurring at virtually all of those facilities. According to the commenter, EPA's decision to propose partial CCS creates even more cost
- estimate challenges,6
- 172

as the facilities under construction intend to capture higher proportions of CO 2 . The commenter also stated the EPA offers no rational basis for reversing its prior c onclusions in the GHG Guidance and in comments on PSD permitting decisions that CCS is prohibitively expensive, citing "At present CCS is an expensive technology, largel y because of the costs associated with CO 2 capture and compression, and these costs wil l generall y make the price of electricity from power plants with CCS uncompetitive compared to electricity from plants with other GHG controls." **Response 6.3 -**  **261:** Commenters challenged EPA’s use of both the LCOE metric at all, and certain of the data used to generate the LC OE estimates. Many of these comments are addressed in preamble section V.I.1. In response to comments indicating that capital costs are of special import for SCPC, and more so than for other types of units (e.g. 9666), EPA has in fact evaluated capital c osts associated with the final standard as a separate metric, found them to be comparable to those experienced (successfully) by this industry

for other NSPS, and reasonable. See preamble section V.H.4. With regard to use of NETLstudies to generate data u sed in the L COE comparison, commenter 10095 said mistakenly

that these estimates do not include transport and sequestration costs for a non - EOR case. The commenter’s error is explained in preamble section V.I .5. The EPA also carefull y reviewed the assump tions on which the transport and storage cost estimates are based and continues to find them reasonable. The RIA presents an illustrative anal ys is using NETL estimates as demonstrative of the range of costs which, as the commenter points out, may

vary by r egion. For transport, costs reflect pipeline capital costs, related capital expenditures, and O&M costs. Pipeline costs used in the NETLstudies upon which the EPA anal ys is was based were comparable to costs quoted by industry experts. See Carbon Dioxide T ransport and Storage Costs in NET L Studies (DOE/NETL
- 2013/1614), p. 16. Sequestration cost estimates reflect the cost of site screening and evaluation, the cost of injection wells, the cost of injection equipment, operation and maintenance costs, pore volume acquisition expense, and long term liability

protection. These seques tration costs reflect the regulatory requirements of the Underground Injection Control Class VIprogram and GHGRP subpart RR for geologic sequestration of CO 2 in deep saline formations. In the cost estimates, each formation in each basin has a maximum theo retical capacity to store CO 2 and this capacity significantly exceeds the mass of CO 2 being stored b y a single project. Therefore it is reasonable to assume that multiple storage projects could be implemented in a formation. In fact, the sequestration cost s conservativel y assume storage in a formation until the total mass of CO 2 injected from all projects approaches 40 percent of the theoretical storage capacity. See Carbon Dioxide Transport ant Storage Costs in NETL Studies, p. 19. The transport and storag e costs provide a conservative estimate of storage costs and are consistent with cases modeled in the NETL report
. Another erroneous comment (10952) maintained that the NETL studies are not peer reviewed. The initial NETLstudy

“Cost and Performance Base line for Fossil Energy Plants, Vol. 1: Bituminous Coal and Natural Gas to Electricity” (2006) was subject to peer review by industry experts, academia, and government research and regulatory agencies. Subsequent iterations of the study were not further pee r reviewed because the modeling procedures used in the cost estimation were not revised. The SAB determined here that this peer review was adequate under6
- 173

both DOE and EPA peer review guidance. See chapter 2 RTC dealing with comments referencing the Infor

mation Quality

Act. Other commenters noted that the NETL studies present costs as a range, and urged the EPA not to use point estimates for these figures. EPA agrees with these comments, and is using the range of cost estimates presented in its assessment of costs. See, e.g., Table 8 to the preamble to the final rule. In this regard, the EPA notes that costs for nuclear power are also presented as a range. This approach is consistent with expert advice to EPA from the EIA, and with the methodology

used by leading techno
- economic modelers in the field, notably L azard Global Power and the Global CCS Institute. 48 The nuclear L COE estimates of these various entities are likewise relativel y consistent. See preamble sections V.H.5 and I.2.b. Commenter 10095 s tated that, at the least, NETL should not be used as the exclusive basis for generating cost information for L COE comparisons. The EPA has, in fact, looked to other techno
- economic models and current vendor marketing and cost information, and finds these other sources of information to be corroborative of NETLestimates (and, in notable instances, to provide lower cost estimates than those of the NETLstudies

– although the EPA L COE estimates continue to be based on the NETL results). See preamble section V.I.2.and 3. Commenters 10098 and 10239 referenced the source relied upon b y EPA in their claim that "partial" CCS, with an emission rate of 1,100 lb CO 2 /MWh, will only add $18 to the cost of electricity for a pulverized coal boiler and noted that the onl y study relied upon by EPA that even speaks to the costs of "partial" CCS shows that cost of electricity will increase b y twice as much as the proposed rule's estimate. However, the EPA notes that the commenter calculated the change in LCOE to meet an emis sion rate of 1,055 lb CO 2 /MWh on a net basis ... not for an emission rate of 1,100 lb CO 2 /MWh on a gross basis as proposed by the EPA (and adopted as the form of the final standard of performance) . In any case, for the final rule, the EPA relied on updated cost estimates by the DOE/NETL that were based on recent, up
- to - date vendor quotes. This new information predicts that the final standard will result in an increase of the levelized cost of electricity

(L COE) at the compliant plant of $16.8/MWh. Commenter 10239 states that no real world operating experience is reflected in the NETL estimates making their use arbitrary . The same commenter indicates that estimates should not be based on units under construction. The cost estimates used b y the EPA for post
- c ombustion partial CCS reflect the most recent vendor quotes for the CanSolv process that is in current operating use at the commercial
- scale full CCS Boundary Dam #3 facility
. Commenter 7977 referenced a 2013 State of Kentucky Energy and Environment Cabine t anal ys is which concluded the levelized cost of electricity (LCOE) with CCS technology is higher than the LCOE without CCS. The EPA agrees with that conclusion (see Table 8 in the final rule preamble). The commenter references a report 49 that concludes that “the addition of CCS to either an IGCC or USCPC facility would increase cost per kWh by 40 percent to 58 percent

48 Global CCS Institute, “The Costs of CCS and Other Low
- Carbon technologies 2015 Update” (July 2015) (compiling estimates of Lazard, EIA 2014, IPCC 2014, Brookings 2014, EP RI 2013, IEA 2012, and NREL 2015). 49 http://eec.ky.gov/Documents/Appendix%20C%20Electric%20Generating%20Report%20FINAL.pdf6
- 174

respectivel y”
. The EPA notes that those studies assume “full CCS” (i.e., capture and storage of 90% or more of the CO 2 from the facility). T he EPA did not find “full CCS” to be a component of the BSER as the projected costs exceed the projected costs of other non
- NGCC, base load generating options. **Comment 6.3 -**  **262:** Commenter 10098 stated that as there are no existing commercial
- scale coal
fired EGUs utilizing CCS, the actual construction and operating costs of CCS for a commercial
scale power plant will not be understood until coal
- fired EGUs actuall y finish construction and operate. According to the commenter, b y failing to present a range of potential costs that include the cost overruns that can be expected with a first
- of
- a - kind technology , EPA provides an illusion of artificial certainty in its $18/MWh estimate. The commenter stated that the accuracy of this number cannot be defended, for lack of any real
- w orld data, and EPA should acknowledge this. Commenter 9666 stated that the problem with using the LCOE metric is that it averages the cost of generation over the lifespan of a generating unit and fails to account properly for significant differences in upfront capital and related financing costs, which are ty pically much higher for coal
- fired units, especially with the integration of CCS, than for NGCC facilities. According to the commenter, because corporate decisions on generating technologies will be driven in large part not only

by a LC OE metric but by

upfront financing and capital constraints, EPA erred by not factoring these considerations into its cost analy sis. For these reasons, the commenter noted that EPA's cost anal ys is is in error and inadequ ate. **Response 6.3 -**  **262:** Boundary Dam #3 is a commercial operating facility utilizing full CCS. The cost estimates used for the L COE anal ys is for post
- combustion CCS is based on recent vendor quotes of the Shell Cansolv post
- combustion capture process

– the process that is c urrentl y being utilized at the Boundary

Dam #3 facility. The EPA has also carefull y monitored the most recent marketing materials and estimates, which, as explained in preamble section V.I.2.c, is corroborative of the NETL cost estimates. EPA regards th e LC OE metric as a highl y reasonable, and widel y utilized metric that takes into account all costs to construct and operate a new power plant over an assumed time period and an assumed capacity factor. Levelized costs are often used to compare the cost of different potential generating sources. However, in response to this comment (from commenter 9666) and similar comments, EPA also explicitly considered capital costs alone. See preamble section V.H.4 explaining why

the EPA finds potential capital cost in creases reasonable on a per
- plant basis. **Comment 6.3 -**  **263:** Commenter 9664 stated that EPA's standard does not produce unreasonable levelized cost of electricity impacts. While the levelized cost of electricity (LCOE) for new coal
fired generation that includes partial CCS i s more than constructing coal plants without CCS, or new natural gas
- fired generation, the commenter noted that it is competitive with new construction of other low
- carbon electricity generating power plants, including nuclear, the principal other option c onsidered for baseload electricity generation. The commenter cited several court decisions that the impact of a standard on the L COE is a factor that EPA can consider in evaluating a standard's cost, consistent with the D.C. Circuit's precedent. **Response 6.3 -**  **263:** The EPA largel y agrees with this comment.6
- 175

**Comment 6.3 -**  **264:** Commenter 9321 stated that for coal refuse designed EGUs with CFB boilers, it is not economically feasible to incorporate identified efficiency technologies. According to the commenter, it is not practical to establish an aggressive greenhouse gas emission rate for coal refuse designed EGU's as the economics will inhibit the development of these projects and this same economic issue will also surface if the application of efficiency improvements to existing coal refuse fire d EGUs is required. The commenter stated that the required use of CCS would also be cost prohibitive and would discourage the development of plants to remove the coal refuse piles and this same economic issue will also surface if the application of CCS to existing coal refuse fired EGUs are required. **Response 6.3 -**  **264:** See preamble section III. E. **Comment 6.3 -**  **265:** Commenter 9664 stated that EPA's standard meets the D.C. Circuit's test
- they are not "exorbitant" when evaluated in terms of the resulting cost of electricity, or as compared with the social cost of carbon. Commenter 9514 EPA stated that properly considered the costs of partial CCS in light of the benefits that will accrue from considering the social cost of carbon and the co
- benefits from reduced emissions of other harmful pollut ants, including SO2, NOx, and PM2.5. According to the commenter, while Section 111 does not require strict cost
- benefit balancing, it allows EPA to consider costs broadly , including consideration of the pollution reductions described above, as well as the social cost of carbon and co
- benefits. The commenter stated that these considerations provide further support for the conclusion that a partial CCS standard will not impose exorbitant cost, in satisfaction of section 111's standards **Response 6.3 -**  **265:** The EPA largel y agrees with these comm ents. **Comment 6.3 -**  **266:** Commenters 10098 and 10239 disagreed with the use of social cost of carbon to reduce the cost of "partial" CCS by 5% per the Social Cost of Carbon document developed b y OMB. Commenter 10098 stated that any reliance on this deeply flawed policy is arbitrary and capricious, as the document is completely unreviewable for reasonableness or accuracy due to OMB's "black box" approach. The commenter provided additional information on social cost of carbon estimates. Commenter 10239 also s tated that the social cost of carbon anal ys is has numerous flaws and should not be utilized in projecting the LCOE. **Response 6.3 -**  **266:** First, the chief metrics used to show that costs of the rule are reasonable are projected LCOE and projected capital cost increases. The So cial Cost of Carbon (SC
- CO 2 ) does not enter into any of these comparisons. Second, the (SC
- CO 2 ) is not a policy, it is an estimate of the net economic damages resulting from CO 2 emissions, and therefore is used to estimate the benefit of reducing those emi ssions. Third, EPA strongl y disagrees that the (SC
- CO 2 ) technical support documentation (“SC
- CO 2 TSDs) is “unreviewable for reasonableness or accuracy .” To the contrary , the SC
- CO 2 TSDs are comprehensive and technically rigorous in explaining the sources of data, the assumptions employed, the analy tic methods applied, and the statistical assumptions employed. Terming this a ‘black
- box’ process is a significant mischaracterization. Indeed, t o ensure that the results are reproducible, EPA has provided technical assistance and modeling results to external stakeholders upon request. EPA also notes that opportunities for public comment have been provided on all aspects of the SC
- CO 2 estimates, including prior6
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rulemakings dating back to 2009 that made use of th e estimates. As a general practice, EPA requests comments on all aspects of the regulatory impact anal ys is, thereb y providing ample opportunity

for the public to comment on SC
- CO 2 estimates used in these analy ses. In addition, OMB provided a stand
- alone co mment period on the 2013 estimates. For additional responses to comments regarding the transparency of the SC
- CO 2 estimates and their consistency with federal guidance, such as OMB Circular A
- 4, see Response to Co mments Section 4, Comment 4.5
- 5 **Comment 6.3 -**  **267:** C ommenter 10098 stated that in the RIA , EPA improperl y reduced the cost of "partial" CCS by

38% through a series of assumptions that are not only unsupported but contradicted b y EPA 's own GHG BACT determinations regarding CCS
. T he commenter cited the EPA estimate of $29/MWh for the cost of partial CCS , noting that the origin of this estimate is not explained in the RIA , making the entire exercise arbitrary and capricious. **Response 6.3 -**  **267:** T he EPA ’s estimates for the cost of partial post
- combustion CCS reflect cost information from recent vendor quotes of the S hell C ansolv post
- combustion capture process

– the process that is currently being utilized at the B oundary D am #3 facility . The EPA has also carefully monitored the most recent marketing materials and estimates, which, as explained in preamble section V
. I .2.c, is corroborative of the NETL cost estimates. The EPA does not believe that utilizing this recent , well
- documented , and corroborated information on cost to be arbitrary and capricious. **Comment 6.3 -**  **268:** Comm enters 10098 and 10239 stated that EPA's cost estimates are arbitrary and capricious because EPA deducts 3% of the costs based on flawed assumptions that "partial" CCS will reduce emissions of other pollutants as a co
- benefit without further explanation of this claim. The commenters countered that CCS would actuall y increase emissions of conventional pollutants, referencing a 2011 NETL study and PSD permit determinations. **Response 6.3 -**  **268:** As shown in Chapter 5 of the RIA, under assumptions where new non
compliant coal capac ity

is added, use of partial CCS results in significant reductions of criteria pollutants, in particular, SO2. **Comment 6.3 -**  **269:** Commenter 8954 and 9472 discussed high costs associated with CCS. Commenter 8954 noted the EIA cost estimates to build a new IGCC coal plant with CCS of $6,599 per kilowatt is more than six times the price of a new NGCC unit without CCD and more expensive than hydro, solar, onshore wind and nuclear options. As a result, the commenter concluded that the proposed standard for coal is far too expensiv e for anyo ne to consider building a new coal plant. Commenter 9472 stated CCS is exorbitantly costly and EPA has significantl y underestimated the cost of CCS by misinterpreting DOE cost estimates and has failed to recognize the first
- of
- a - kind nature of CC S costs. The commenter estimated the addition of CCS to a single new coal
- fueled electric generating unit costs in the range of $1 billion. Commenter 9401 referenced EIA data that adding CCS to a new power plant can cost up to $1 billion and increase its c apital cost by 60 percent. The commenter also stated that the Administration's CCS task force reported that CCS would add $400 million (IGCC) to $900 million (pulverized coal) to the cost of a typical coal plant, increasing the capital cost of the plant by 25 percent and 80 percent, respectivel y.6
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Commenter 10243 stated costs to install CCS on a new coal
- fired power plant are prohibitively high, and CCS projects in the U.S. are viable onl y as a result of government assistance. Commenter 9780 stated the costs of partial CCS are not reasonable and partial CCS is too expensive to be BSER. Commenter 10050 also stated CCS costs are exorbitant and unreasonable. Commenter 10043 noted deficiencies with the exorbitant costs of CCS and the insufficient cost anal ys is conducted b y the EPA regarding the effects of the Proposed Rule. Commenter 9194 stated, as demonstrated in the NETLstudies employed by EPA, CCS technology

is resource intensive and overl y expensive for use with utility
- size EGUs. Commenter 1959 stated co sts should be considered, and the additional costs associated with CO 2 capture are very

large unacceptable and would roughl y double the co st vs. a PC plant without CCS. Commenter 8966 stated Implementation of partial CCS is exorbitantly costly in both econ omic and environmental way s. 1. Pre
- CCS planning and design costs are significant even before factoring CCS sy stem expenses. 2. In addition to special planning and design costs, the cost of a CCS system itself is immense. 3. CCS implementation raises a hos t of safety , liability , and other practical issues that EPA failed to take into account. According to the commenter, these are issues that must be resolved as a prerequisite to wide deplo ym ent and use of the technology
. Their importance cannot be marginali zed by EPA. Commenter 10662 stated EPA's proposal constitutes a significant energy action with great adverse effects and fails to consider the increase in construction, operation, and energy penalty costs associated with CCS technology
. The commenter noted the potential for increased electricity costs, the reliance on subsidies, the need for additional research, the lack of commercial scale applications, and the parasitic load. A number of commenters (e.g. 8954, 9401) stated that adding CCS to coal
- fired plants is exorbitantly costly

and can add costs of up to $1 billion. Commenter 9401 cites in support that Administration’s CCS Task Force. The Task Force report addressed full CCS, not partial CCS. **Response 6.3 -**  **269:** The EPA is not selecting full CCS as BSER for reasons of cost. See preamble section V.P. However, as shown in preamble Table 8 and discussion underlying that table, cost of partial post
- combustion CCS compares reasonably to that of other non
-NGCC baseload dispatchable technologies. See also Global CCS Inst itute, “The Costs of CCS and Other Low
- Carbon Technologies” (2015) stating that “CCS is a cost competitive power sector emissions reduction tool when considered among the range of available low and zero emissions technologies” (p.1); statement of Alstom Vice President Macnaughton endorsing “ findings from a recentl y- conducted cost anal ys is showing that the cost of electricity generated b y coal and6
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natural gas plants equipped with CCS is competitive with other low or no
- carbon energy carbon energy sources, such as wind, solar, geothermal, hydro and nuclear”
. 50 In response to commenter 1959 and 9401, the EPA has carefull y considered capital costs as part of its consideration of cost. See preamble section V.H.4. The commenters, again, are basing their figure s on the capital costs associated with full CCS, and therefore are much higher than those associated with the standard in the final rule, which the EPA has evaluated and found to be reasonable, in particular because they are in the same range as capital co sts for this industry in earlier NSPS, which costs were found to be reasonable both by EPA and by

reviewing courts. Comments that the EPA is ignoring (unspecified) issues of safety and liability associated with partial CCS are misplaced. Costs reflect a c arefully documented item
- by
- item assessment of equipment and construction needs . Issues of liability of sequestration sites are addressed, to the extent of EPA authority , in the Class VIwell standards, in particular the closure and post
- closure provision s. See preamble section V.N. The EPA has also carefully considered the issue of parasitic load (termed ‘energy penalty’ b y commenter 10062) and found those impacts to be reasonable. See preamble section V.O.3. See also the following response. **Comment 6.3 -**  **270:** Commenters 7433, 9593 and10017 stated that EPA also overlooks the substantial energy

penalty that CCS sy stems would impose on the generating capacity of an individual facility . Commenter 7433 stated when CO 2 capture and storage is compared to other technical options for reducing CO 2 emissions, 10
- 40% more energy is needed for producing the same amount of electricity ; therefore, it is expected that CCS would raise the cost of producing electricity b y about 20 to 50%. **Response 6.3 -**  **270:** The EPA has carefully analyzed the issue of parasi tic load . The actual figures are considerabl y l ess than the commenter s posit, and EPA has found the energy requirements of the rule, including consideration of energy requirements related to parasitic load, are reasonable. See preamble section V.O.3. **Comment 6.3 -**  **271:** Commenter 9381 stated CCS as EPA envisions it for use at power plants has not been adequatel y demonstrated and its current costs are wholl y disproportionate to the costs of a conventional power plant and are currently prohibitive. The commenter stated that el ectricity generated from coal with CCS is almost 50 percent more expensive than energy generated from conventional coal. According to the commenter, it is estimated that CCS technology would add between approximately

$800 million to $1 billion to the cost of a coal
- fired EGU and would use as much as 30 percent of the electricity generated from the plant for CCS operation as parasitic load. With costs of this magnitude, the commenter noted it is highl y doubtful that any merchant power companies or regulated electric utilities will invest in a new coal
- fired power plant with CCS, nor will they

be able to obtain financing. This could impact reliability and prevent states from diversifying their energy portfolios. Moreover, the commenter stated, CCS technology will not be deployed, refined or improved so as to make it technologically or economically

viable.
50 S ee http://www.alstom.com/Global/US/Resources/Documents/Press%20Releases/PR_JMacN_CCSbriefing_FINAL.pdf6
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**Response 6.3 -**  **271:** The commenter (Nextera Energy) cites in support a 2012 article titled The Twilight of Coal
-Fired Power (May 1, 2012). Comment p. 3 n.2. That article was addressing the now - withdrawn 2012 proposal of EPA, and the costs cited again appear to reflect full CCS (and certainl y do not reflect the costs of the standard based on performance of partial
- CCS adopted in this final rule ) . See The Twilight of Coal
-Fired Power at p. 11 and Fig. 7. **Comment 6.3 -**  **272:** Commenters 8179, 8200, 8206, 8231, 8242, 9190, 9590, 9725. 10050, 10552, and 10680 disagreed with EPA's assumption that the costs for CCS will decrease with the next plants constructed, as the commenters stated that actual experience in development of control technologies shows that second generation technologies will cost more as new risks are identified in performance and reliability . The commenters referenced comments by the Duke Power CEO that CCS is "too expensive" to c onsider adding to its recently commissioned Edwardsport IGCC plant, and noted that the Kemper County Energy Facility has experienced cost overruns of over 100 percent since 2010 and remains uncompleted. Commenter 9666 stated that because CCS has never been applied as an integrated s ys tem at EGUs on a commercial scale, experience from the first generation of CCS sy stems at units like Kemper County and Boundary Dam is likel y to reveal performance and reliability issues that may require costly

additional measures to address. Commenter 10952 stated that because the projects, Kemper, TCEP, and HECA, of which EPA relies, are not in operation, the ultimate costs of employing carbon capture on an EGU are unknown. The commenter stated that EPA has not and cannot exp lain this dramatic departure from its earlier rulemaking, or from the technology development timelines and milestones developed b y this administration and described in the Task Force report, especiall y with input from DOE whose knowledge and expertise in these areas of technology development dwarfs EPA's, to conclude carbon capture is adequatel y demonstrated. Commenter 9396 stated that due to the excessive cost
- increase of CCS demonstration projects, particularl y the Kemper project, EPA should use a very su bstantial cost uncertainty when evaluating project costs that include CCS. The commenter also stated that the cost estimates for the Kemper facility are outdated and understate the cost of the facility
. Commenters 9666 and 10395 stated that because the projects that EPA relies on (Kemper, TCEP, HECA) are not in operation, the ultimate costs of employing carbon capture on an EGU are unknown. Commenter 2471 stated that EPA references the Kemper, Boundary Dam, TCEP and HECA projects, however each of these p rojects are oil and gas recovery projects and EPA does not consider the risks and costs to inject CO 2 in locations with little or no oil and gas recovery opportunities. Commenter 7977 referenced the Edwardsport and Kemper projects, noting that the actual c osts accrued were much higher than the original cost estimates.6
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Commenter 8925 stated that FOAK costs have been significantl y underestimated and provided additional background information on the Kemper and Boundary Dam projects. For the Kemper project, th e commenter stated that based on the current estimate, it will cost $9,922/kW which is considerabl y more than those estimated in the DOE/NETL "baseline" studies cited in the EPA proposal. The commenter referenced the DOE/NETL 2011 report titled "Cost and P erformance of PC and IGCC Plants for a Range of Carbon Dioxide Capture" which cites an IGCC with 60% CO 2 capture having a "total overnight cost" of $3,024/kW. Total overnight costs do not include so called "owner's costs" or costs outside of the plant boun dary limits such as transmission lines and fuel delivery sy stems. According to the commenter, if those costs are removed from the Kemper estimate, and the $245.3 million DOE subsidy is also removed, the equivalent "total overnight cost" of the Kemper woul d be $3.768 billion or $7,190/kW
-- over twice the DOE/NETL baseline estimate. Commenter 8925 provided background information on the SaskPower Boundary Dam project. According to the commenter, th e anticipated total cost of the Boundary Dam project was $ 1.24 billion (CDN). SaskPower has received a $240 million (CDN) subsidy from the Canadian federal government to support the project. Accor ding to the commenter, project overruns were reported in October 2013 and the total projected cost now stands at $1. 36 billion (CDN) for the 110 MW unit. Commenter 9497 stated that in approving the Kemper project, the Mississippi Public Service Commission (MPSC) explicitly recognized and guarded against the cost escalation being experienced at Kemper. As a result of the construction cost cap imposed by the MPSC, the company has written off over $1.5 billion. According to the commenter, this protective shifting of risk is unlikely

to appeal to a broad range of utilities or be practical for the broader implementation of partial CCS technology in its current state. Commenter 9497 noted that the actual cost of the Kemper facility is greater than the cost assumed in EPA's RIA for an IGCC with CCS. The commenter calculated that the $4.6 billion plant cost translates to $7,846 per kW, more than double the cost assumed by EPA for an IGCC with partial CCS, noting that the calculated cost per kW for Kemper is conservative because it excludes the CO 2 pipeline cost, which is likely to be a necessary component of any IGCC with CCS. T he commenter stated that EPA's use of a cost assumption for I GCC with CCS that is at odds with both EIA's cost estimates and the actual cost of Kemper deems the RIA unreliable. Commenter 9497 stated that the MPSC experience with the Kemper project demonstrates that the projected cost of a project with CCS technology can drastically

change during deploy

ment. The commenter suggested that in four years, the costs of this technology will be more knowable and the capture efficiency will be better understood. Co mmenter 9497 provided additional information on the Kemper project, including a discussion on the imposition of a cap on construction costs, beyond which incurred costs could not be recovered from ratepayers. The commenter stated that MPSC imposed perform ance standards and expectations on Kemper that shift risk to the utility . The commenter stated their belief that most other state commissions would likely insist on similar protections and that these6
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requirements are unlikel y to promote broader implementation of partial CCS technology across a wider range of utilities. Commenter 9723 stated since the CCS projects, including Kemper, Boundary Dam and HECA, have required funding through governmental programs, it is clear there is more time needed to develop ec onomic CCS technologies before it would be considered BSER. Commenter 9773 stated that the four facilities that EPA references are under construction, or proposing to construct, are receiving government financial assistance to be viable and are not using c ommerciall y available CCS technology. The commenter provides information on the subsidies for Boundary

Dam, Kemper, TCEP and HECA. According to the commenter, this required level of public funding to support these named projects does not support EPA's posi tion that partial capture CCS meets the cost criteria to be BSER. The commenter also stated that incentivizing developers to install CCS via public grants and tax incentives of this magnitude is not sustainable when applied on the national scale required to power the nation's future industrial, commercial and residential demand.Commenter 10095 referenced the Kemper, TECP, and HECA projects, noting that since all of these projected receive federal funding, none can be said to be independentl y accommodating the cost of CCS. The commenter also stated that two of these projects do not have power purchase agreements. Commenter 9666 stated that EPA's assumption that a control technology's costs necessaril y decrease with implementation experience is fundamentally flawed. In practice, experience with developing control technologies often reveals new risks that increase costs or compromise the sy stem's performance. The commenter referenced EPA's suggestion that Kemper and Boundary Dam are FOAK projects and that future NOAK projects will have lower costs. Commenter 9780 referenced the cancellation of AEP Mountaineer pilot project due to cost estimates increasing drastically . The commenter stated that the existence of plans that will never be put into action provides no additional support to the CCS BSER determination. Commenter 8024 stated the recent cancellation of the Wolverine Power 600 MW coal
- based power plant provides another example of the uneconomic nature of CCS applied to a conventional power project. The co mmenter provides extensive information regarding the BACT anal ys is for the permit application, noting that the subsequent engineering cost analy sis of the application of CCS to the project concluded that CCS was not economic, and should not be pursued even with government support. According to the commenter, there are similar cases of BACT reviews evaluating and rejecting CCS on economic grounds, such as the proposed Taylorsville coal gasification facility in Illinois. The commenter noted that project
- sub sequently cancelled
- offered the opportunity to capture a pure stream of CO 2 from the gasification process, without the need for costly post
- combustion capture technologies, and I llinois EPA rejected the application of CCS on economic grounds. Commenter 1 0618 stated each example of a potential commercial
- scale CCS on a coal
- based generating unit has experienced a significant escalation in costs. According to the commenter, the wide disparity in the cost estimates of current efforts is indicative that CCS i s not a one - size
fits
- all technology , that project
- specific cost drivers are significant, that reliable estimates of6
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CCS costs are evolving, and that future CCS cost s are highl y speculative.Commenter 8966 stated that in close consultation with Alstom, a manufacturer of the chilled ammonia
- based CCS sy stem, AEP commissioned a front
- end engineering and design (FEED) study to develop a commercial
- scale CCS sy stem at the plant, capturing carbon from approximately 20% of the flue gas output. A single installatio n of the sy stem was estimated to cost over $1 billion, and even despite installation, the facility would likel y exceed the 1 , 100 lb/MWh standard, even assuming 100% carbon capture efficiency . In light of these astronomical costs, AEP decided to cancel the commercial
- scale project. To achieve a level of carbon capture that would suffice under the rule, a multi
- billion dollar investment would likely be necessary

for a single new large
- scale coal power plant, which is several times greater the cost of the plant itself. AEP's sudden reversal of plans is a strong indicator that other prospective operators will similarly turn away

from coal
fired plants when they

experience the "sticker
- shock" associated with the massive costs of a commercial
- scale CCS sy stem. **Response 6.3 -**  **272:** Co mmenters 9666 and 10952 maintained that the EPA should not base cost estimates on plants not in operation. A number of commenters (e.g. 2471) indicated more generall y that the EPA should not base its cost considerations on plants engaged, or planning to e ngage in, EOR. As noted in other responses, EPA has sought the most up
- to - date information on costs, and the cost estimates for post
- combustion CCS are for the CanSolv compression and capture s ys tem which is the sy stem in place and operating at Boundary Dam. The EPA is not considering EOR revenues in its assessment of costs. Commenter 9666 anticipated reliability concerns when Boundary Dam commences operation. In fact, the company has reported, with considerable enthusiasm, that the plant is operating even better than anticipated. See preamble section V.D.2.a. Commenter 8925 referred to cost overruns at the Boundary Dam project as an instance of the EPA underestimating costs associated with CCS. In fact, the EPA has documented that all cost overruns related to the boiler, not to the carbon capture sy stem. Any cost overruns assigned to the capture side were financing costs that were due to delay s caused by the boiler side. The installation of the capture equipment came in on schedule and on budget. S ee Memorandum to Docket re Conversation between Dr. Nick Hutson (EPA) and Mike Mone a (SaskPower). Commenter 8925 stated that the plant received government funding, which is correct but not pertinent to the question of total cost. The Boundary Dam facility is a FOAK plant, built with multiple redundancies, and its costs are reflective of FOAK. Boundary Dam facility

personnel have stated publicall y that they expect at least a 30% cost on the next CCS plant. A number of commenters referred to Kemper as the prime example of CCS costs being exorbitant (e.g. 9497, 8925). As noted in other responses, cost overruns at Kemper reflected a series of idios yncratic decisions that essentially resulted in construction commencing before proper planning had occurred, re sulting in improper sequencing of construction efforts and enormous resulting excess costs. The motivation for this cart
- before
- the
- horse approach 51 was to

51 “[T]he ‘just
- in
- time’ approach to engineering and procurement (meaning that the engineering was often completed shortly before material procurement and construction activities) resulted in a greater number of construction work
arounds, congestion of construction craft labor in the field, inefficiencies and additional steps that became necessary6
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obtain the IRC 48g tax credit for a particular calendar year. The EPA believes that these cost increases are avoidable by following normal practice rather than just
- in
- time sequencing, and therefore that the cost overruns at Kemper are not predictive of what next plants would experience. Moreover, the Independent Monitor’s Prudency Evaluation report id entifies cost issues associated with IGCC (idiosy ncratic, as noted) but not with the CCS sy stem. Kemper cost information consequently is not a good predictor of cost overruns for CCS sy stems for this reason as well. Commenters 8966 and 9780 indicated that AEP terminated the Mountaineer project based on projected cost overruns. AEP’s public statements at the time were that the CCS technology was reliable, but that the company was withdrawing at least in part because of regulatory uncertainty. Preamble se ction V.D.3.b. The EPA also notes the positive statements from AEP executives regarding the project and CCS generally : “ AEP still believes the advancement of CCS is critical for the sustainability

of coal
- fired generation.” 52

. Alstom’s contemporaneous re marks were equally positive: See also statement of Alstom senior Vice President for Power and Environment Policies Joan Macnaughton’s statement (August 4, 2011): “AEP’s decision to put Mountaineer II on - hold (sic) is a bellwether to our leaders on the cons equences of uncertain climate policy . The Validation Plant at Mountaineer demonstrated the ability to capture up to 90% of the carbon dioxide from a stream of the plant’s emissions. The technology works.” The press release further states that Vice Presi dent Macnaughton “presented findings from a recentl y- conducted cost anal ys is showing that the cost of electricity generated by

coal and natural gas plants equipped with CCS is competitive with other low or no
- carbon energy carbon energy

sources, such as wi nd, solar, geothermal, h ydro and nuclear.” 53 Inits public comments here, AEP cited high costs associated with siting monitoring wells and other cost issues associated with developing a suitable sequestration site. The Mountaineer project involved a retro fit of an existing facility

(id.), and issues relating to siting of a sequestration repository can be avoided. In addition, none of the Class VIpermits issued to date by the EPA required the number of monitoring wells need for the Mountaineer site, again indicating that the monitoring and sequestration experiences at that site are site
- specific
. Commenter 8024 refers to the State of Michigan’s determination that CCS was not part of BACT for the Wolverine facility. This issue is addressed in preamble sec tion XII.C. **Comment 6.3 -**  **273:** Commenter 9231 stated the proposed rule should take into consideration the ty pe of electricity

markets that exist in the various states/regions of the country . The commenter explained that ty

picall y, in regulated markets (rate based markets); the cost of compliance to the greenhouse regulations is passed through to the ratepayer through the state public utility /service commission (PUC) rate mechanisms. While the PUC would compare the cost of various technologies and/or fuel sources, the PUC woul d also take into account the need for energy during construction to cope with this just
- in
- time engineering, procurement and construction approach”. Independent Monitor’s Prudency Evaluation Report (April 15, 2014) p. 6. 52 CCS LESSONS LEARNED REPORT American Electric Power Mountaineer CCS II Project Phase 1, Prepared for The Global CCS Institute Project # PRO 004, January 23, 2012, page 2. See also AEP FEED Study at pp. 4, 63 (same). 53 See http://www.alsto m.com/Global/US/Resources/Documents/Press%20Releases/PR_JMacN_CCSbriefing_FINAL.pdf
.6
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diversity for security , price stability , and reliability reasons. The commenter also stated that in the case of deregulated markets (market based rates), the investor would have to bear the cost and risk associated with compliance which could put that particular state or region at risk in terms of energy

diversity. According to the commenter, if not done properly, the proposed rule could determine winners and losers for not just EGU's but general industry competi veness between states and regions relative to that areas energy mix. **Response 6.3 -**  **273:** See response RTC 3.3
- 3. The NSPS is a nationwide standard that is applicable and achievable in all parts of the U.S. Responses to comments regarding differences between regulated and dere gulated markets are provided elsewhere in this RTC. **Comment 6.3 -**  **274:** Commenters 9190, 9725, 10050, 10552, 10667 and 10680 stated that capturing and compressing CO 2 consumes a substantial fraction of the plant's electrical generation output so a plant with CCS will have to be substantially larger than one without CCS and will require more fuel to power it. The commenter stated that the Deputy Assistant Secretary of Energy for Clean Coal recentl y testified before Congress that CCS technology would increase the cost of produci ng electricity from a coal base load plant by 70
- 80 percent. Commenter 9593 also stated EPA also overlooks the substantial energy penalty that CCS sy stems would impose on the generating capacity of an individual facility
. Commenter 10043 stated that anoth er major cost of CCS is the "parasitic load" that ranges from 20 percent to 30 percent of a power plant's output to energize the associated emission control technologies. The commenter noted that future research and development may bring this cost down, but the reductions will not be significant enough to offset the major financial burden created b y power lost to operate the CCS technology. The commenter provided the example that for an 800MW supercritical coal unit, its average energy costs would increase from approximately

$42/MWh to $54/MWh (a 29% rate increase) assuming parasitic consumption for carbon capture at the low end estimate of 20% and $2/ton for transportation of 50% of the unit's CO 2 emissions. The commenter stated that the result is the loss of 1.1 million megawatt
- hours per year an impact much too large for the EPA to simply disregard under the CAA
- and that does not include costs for the sequestration and storage itself. The comment er conclu d ed that beyond the direct costs of installation and operation, CCS will have an exorbitantly costly impact on the electric generation industry and ultimately

the nation's ratepayers as the country will no longer utilize electricity

generated usin g reliable and stable coal resources. Commenter 9590 stated capturing and compressing CO 2 consumes a substantial fraction of the plant's electrical generation output, so a plant with CCS will have to be substantially larger than one without CCS and will re quire more fuel to power it. The commenter also stated that the cost of deploying CCS technology is exorbitant and unreasonable, and tis factor alone disqualifies CCS as BSER for coal base load power plants. Commenter 10870 stated the Boundary Dam Unit 3 w ill produce 160 MWe gross and only 110 MWe net, a 31% parasitic load with most of it consumed by the CCS sy stem. According to the commenter, this is well above the normal 7
- 12% parasitic load expected of a plant without CCS. The commenter also stated that without experience on full
- scale CCS sy stems, any estimate of6
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capital costs and operation and maintenance costs is suspect. The commenter also stated concern with the exorbitant cost of operation and maintenance of CCS. **Response 6.3 -**  **274:** These comments are addres sed in preamble section V.O.3. As shown there, the results in preamble Table 14 show that a new SCPC unit without CCS can expect a parasitic power demand of about 5.2 percent. A new SCPC unit meeting the final standard of performance by implementing 16 percent partial CCS will see a parasitic power demand of about 6.3 percent, which is not a significant increase in energy requirement. Of course, new SCPC EGUs that implement higher levels of CCS will expect higher amounts of parasitic power demand. As shown in Table 14 , a new SCPC EGU implementing full CCS would expect to utilize over 14 percent of its gross power output to operate the facility and the carbon capture s ys tem. But, the EPA does not find that a new SCPC implementing full CCS is the BSER for new fossil
- fire d steam generating units. The EPA notes in addition that the DOE testimony referred to b y commenters was with regard to full CCS, not the degree of partial CCS identified as part of BSER in this action. **Comment 6.3 -**  **275:** Commenter 10618 stated their concern that EPA's cos t evaluation relies only on the two NETL reports become even more pronounced when considering the large difference of the estimated costs projected b y EPA in the proposed rule and the actual costs that active CCS projects are incurring. The commenter provi des a table to summarize their comparison. The commenter stated that EPA's cost analy sis is flawed due to a narrow review of available information and a failure to consider the cost of actual proje cts. The commenter stated that EPA's cost anal ys is relies o n only two DOE/NETL reports that are based on conceptual designs for technologies that, at least in the case IGCC and CCS, have never been constructed. According to the commenter, much of the cost anal ys is language contained in the preamble is verbatim fro m these reports, albeit without appropriate references. The commenter then provides a list of flaws in the EPA's cost anal ys is as well as review points of the EPA's references that the commenter considers to have either been ignored or misinterpreted by th e EPA. Then the commenter cites a couple references/reports showing that development costs may increase as new information is discovered, urging the EPA to consider that in their anal ys is. Commenter 9425 stated EPA relies on a 2011 cost and performance rep ort by the DOE NETL that is merely

modeling predictions that estimate the performance of various CCS configurations and is not based on information gathered from actual operating experience. According to the commenter, the cost of CCS at smaller demonstration facilities cannot be reliably scaled up to inform predictions about the cost of CCS at commercial units. Commenter 100 87 stated EPA arbitraril y considers CCS costs from NETLfor coal, but does not consider that according to NETL , electricity generated from natural gas CCS plants is less expensive than coal. The commenter also stated EPA arbitraril y omits the fact that according to this DOE/NETLstudy , natural gas with CCS produces less expensive electricity than coal with CCS. Commenter 10095 stated i n trying to specifically justify not using EIA ’ s CCS cost estimates, EPA claims, no estimates were provided b y EIA for IGCC with partial or full CCS, and that the DOE NETL reports provided detailed cost estimates for a range of CO 2 capture levels for both ne w SCPC and I GCC facilities. According to the commenter, both of these rationale s are flawed.6
- 186

The commenter noted that EIA did provide cost estimates for IGCC with full CCS, and that EPA did not directly

use DOE NETL's partial CCS cost estimates. Instead, the commenter explained, to estimate partial CCS cost, EPA linearly scaled DOE NETL's no and full capture CCS cost estimates. According to the commenter, this exact anal ys is (i.e. linearl y scaling) could have easily been performed using EIA's cost estimates
. Commenter 9666 stated the series of NETL reports, perhaps valid for use in a technology screening study, are not adequate upon which to base a national energy strategy. According to the commenter, none of the NETL reports appear to have been subjected to an authentic peer review, and a legitimate peer review would address how (a) capital costs were derived, and escalated or revised to reflect changing market conditions, and (b) input data from vendors or suppliers was used, changed, or adjusted to conform with the study scope. The commenter also stated that the DOE/NETL cost reports that EPA cites as the basis for its CCS cost estimates are merel y modeling predictions and do not reflect actual experience implementing CCS. Commenter 9423 stated cost estimat es provided by EPA related to CCS D0E/NETLstudies from May 2010 through August 2012 do not include cost overruns that have been publicized for some of the projects EPA cites as currently under construction or under development. According to the commenter, if EPA were to update the cost estimates to include cost overruns, and given the accuracy range of estimates of
- 15 to +30 percent from the center point cost in Table 6 on p. 1476 of the January

8, 2014 notice of proposed rulemaking, the actual cost could be beyond the cost criteria of BSER **Response 6.3 -**  **275:** Commenter 9425 states that the NETL study used at proposal costs a s ys tem which has never been implemented in practice and therefore is too uncertain. Partly in response to this and similar comments, and also in order to use the most up
- to - date information, EPA’s final cost estimates reflect the latest iteration of the NETL studies which are based on recent vendor quotes of the Shell Cansolv post
- combustion capture process

– the process that is currentl y being utilized at the Boundary Dam #3 facility
. Commenter 9666 states that the NETL cost studies are not peer reviewed and therefore unreliable. The commenter is mistaken. The EPA Science Advisory Board Work Group considering the adequacy of the peer review noted EPA staff’s statement that “the NETL studies were all peer reviewed under DOE peer review protocols”, further noted EPA staff’s statement that “the different levels of review of these DOE documents met the requirements to support the anal ys es as defined b y the EPA Peer Review Handbook,” and concluded that “peer review on the DOE documents” was conducted “at a level required by agency guidance.” 54

54 Letter from James Mihelcic, Chair, SAB Work Group on EPA Planned Actions for SAB Consideration of the Underlying Science to Members of the Chartered SAB and SAB Liaisons (page 3, Jan. 24, 2014). http://yosemite.epa.gov/sab/sabproduct.nsf/F43D89070E89893485257C5A007AF573/$File/SAB+work+grp+memo +w+attach+20140107.pdf.6
- 187

Commenter 9423 urged the EPA to use the full range of the NETL cost estimates. The EPA has done so in its L COE analy sis. See preamble at Table 8. Li kewise, the EPA uses the full range of cost estimates for nuclear and other low carbon technologies. Commenter 10087 states that the EPA ignored NETLestimates that electricity generated from natural gas is cheaper than th at generated from coal. This is true whether or not CCS is utilized, as the EPA noted repeatedly at both proposal and in this final rule. See e.g. RIA chapter 4. **Comment 6.3 -**  **276:** Commenter 9678 stated the costs of CCS technology particularl y as applied to NGCC units demo nstrate that CCS is not BSER for natural gas
- fired units. According to the commenter, given the efficiency and low
- emitting nature of NGCC units, application of CCS would result in an excessive cost per ton of CO 2 avoided, which means that CCS is not BSER for NGCC or other natural gas
- fired units at the present time and may not be reasonable on a cost basis for a long time, if ever. **Response 6.3 -**  **276:** The EPA agrees that partial CCS is not BSER for new natural gas
- fired units. **Comment 6.3 -**  **277:** Co mmenter 10618 discussed how the costs required to comply with the requirements of an Underground Injection Control (UI C) permit increased costs of the CCS project b y 30%. The commenter encouraged the EPA to review three reports that AEP submitted to the Global CCS Institute and included citati ons of how to access each Commenter 9423 stated EPA has failed to include other costs associated with CCS, such as seismic studies, right
- of

- way costs, permitting, pore space ownership, liability , and water resources. Commenter 10083 stated CCS comes at a high cost to both the utility and the electric customers that the utility

serves. The commenter noted at a minimum, these costs include completing all necessary environmental assessments, permitting to complete the project, designing the plant to accommodate CO 2 capture, routing the captured CO 2 to the injection site, preparing the injection site, and then the actual injection of CO 2 into the storage area. The commenter provided additional information on the situational and locational differences in the wes tern states for siting and using CCS technology required by

EPA's GHG NSPS to permit and build a coal
- fired EGU. **Response 6.3 -**  **277:** The commenter is mistaken. The EPA’s cost estimates do in fact include costs associated with transport and geologic sequestration. For transp ort, costs reflect pipeline capital costs, related capital expenditures, and O&M costs. Sequestration cost estimates reflect the cost of site screening and evaluation, the cost of injection wells, the cost of injection equipment, operation and maintenance costs, pore volume acquisition expense, and long term liability protection. These sequestration costs reflect the regulatory requirements of the Underground Injection Control Class VIprogram and GHGRP subpart RR for geologic sequestration of CO 2 in deep s aline formations. See preamble section V.I.5. **Comment 6.3 -**  **278:** Several commenters discussed financing concerns for CCS projects. Commenter 9597 stated no company, or consortium of companies for that matter, can undertake a $5 billion project without financing., and acquiring financial backing for a project reliant on CCS is going to be extremely difficult and definitely

not on good terms. Commenter 105006
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stated the costs of CCS are unreasonable and cooperative like AECC cannot receive Rural Utility Service ("RUS") funding for new coal
- unit projects. According to the commenter, this high cost prohibits entities from investing in and developing CCS and, therefore, it does not incentivize money lenders approving loans to construct the technology . Commenter 10086 stated that wi thout adequate demonstration of the control, developers, and hence, financiers will have no assurance of future compliance for coal
- fired projects and therefore, in addition to the technical concerns regarding CCS, any new generation projects will not be a ble to obtain capital financing. Commenter 10238 also stated that it would be very difficult to obtain non
- governmental financing on a project that has yet to be commercially available and adequately demonstrated. **Response 6.3 -**  **278:** The EPA has carefully evaluated the issue of financing, and is utilizing cost estimates which reflect “high
- risk” financial assumptions rather than conventional financing which are used for cost estimates for non
- CCS technologies . See NETL (July 2015) at p. 18. **Comment 6.3 -**  **279:** According to commenter 8966, CCS systems require significantly more space than traditional emission controls and the footprint of CCS equipment may exceed that of the EGU itself. The commenter stated that this characteristic can pose particular implementation difficulties for facilities planned on sites surrounded by land unsuitable for construction or otherwise occupied. Further, the commenter explained, new projects must incur the additional land or right
- of

- way (ROW) acquisition costs to house the CCS equipment, as well as additional l egal costs associated with obtaining zoning or other siting permits that may be unnecessary if no CCS system were installed, and these land acquisition requirements may be significantly

higher for or on
- site storage of captured CO 2 . **Response 6.3 -**  **279:** The EPA’s cost estimate s include costs associated with transport and geologic sequestration. For transport, costs reflect pipeline capital costs, related capital expenditures, and O&M costs. See preamble section V.I.5. Pipeline capital costs include materials, direct labor, right - of
- way acquisition, and miscellaneous costs
. 55 Sequestration cost estimates include pore volume acquisition expense, and also reflect the regulatory requirements of the Underground Injection Control Class VIprogram and GHGRP subpart RR for geologic seque stration of CO 2 in deep saline formations. **Comment 6.3 -**  **280:** Commenter 9194 stated CCS is excessively costly to the consumer, which EPA has attempted to disguise b y inappropriatel y comparing coal with CCS to nuclear and biomass generation instead of comparing coal with CCS to the newest, cleanest coal plants without CCS. Commenter 10036 stated that the nuclear power sector is not a useful benchmark for cost viability . According to the commenter, EPA used dissimilar techniques in comparing the cost of nuclear power to the co st of coal
- fueled power and if the two sectors are compared on a consistent basis, the cost of coal s ys tems with partial CCS fails EPA's own test of reasonableness. Commenter 9677 stated that a unit built with CCS is just too expensive (that is, unreasonab le cost.). The commenter stated that EPA evaluates cost for the proposed rule by comparing a unit with CCS to other non
- natural gas power generation processes. The commenter

55 Carbon Dioxide Transport and Storage costs in NETL Studies (DOE
-NETL
- 2013/1614), p. 11.6
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equated that approach with comparing apples to oranges. The commenter suggested co sts be considered on an incremental basis; the cost of a fossil fuel fired unit vs cost of the same unit with CCS. **Response 6.3 -**  **280:** The EPA disagrees; the comparison with nuclear

– the other main dispatchable baseload non
-NGCC electricity- generating unit, is reasonable. See preamble section V.I.1. The EPA has also compared capital cost increases for SCPC with and without partial CCS, and found that increase to be reasonable. See preamble section V.H.4. **Comment 6.3 -**  **281:** Commenters 9407, 9600 and 10952 stated all real identifiable costs a ssociated with the proposed partial carbon capture as applied to coal
- fired EGUs show cost increases from 50 to 100 percent above generation costs without carbon capture. According to the commenter, this proposal has failed to demonstrate that CCS is avail able at all much less at a reasonable cost. Commenter 9407 and 10097 stated the proposal including information contained in the rulemaking docket presents no information that could lead to a rational conclusion that full or partial carbon capture can be deployed as part of a BSER **immediately** and, at a **reasonable cost**  . According to the commenters, EPA has failed to provide any explanation in this rulemaking's docket to document what carbon capture technologies in other industries it is utilizing and how it i s technically appropriate to extrapolate those technology applications to coal
- fired steam electric generation that must operate under required and specific duty c ycl es that do not mimic those required in other industries. Thus, the commenter stated, there is an insurmountable problem with the proposal since the information provided in this rulemaking docket includes no reasonable basis to conclude that carbon capture is technically available at a reasonable cost for use as BSER in the immediate future and perhaps not available as a BSER for many years to come. Commenter 10046 stated even if CCS were technologicall y feasible, which it is not, the Proposed Rule imposes astronomical costs, which makes new coal
- fired power plants economicall y nonviable. According to the commenter, EPA's own cost numbers demonstrate that partial CCS costs are unreasonable. Commenters 9590 and 10050 stated the cost of deploying CCS technology is exorbitant and unreasonable, and this factor alone disqualifies CCS as BSER for coal base load power plants. Commenter 9596 urged EPA to reconsider its decision to designate partial CCS as BSER until the costs of implementing this sy stem of emission reduction come down to more reasonable levels. Commenter 9423 stated the proposed BSE R standard is economically unreasonable and EPA's anal ys is does not appropriately consider the cost of ancillary factors such as pipelines, transportation of CO 2 , and storage. The full cost of the proposed standards could substantially affect competition. BSER is applied to a particular source and not the entire industry . Had EPA fully evaluated the costs of BSER, the proposed BSER standard based upon IGCC and CCS would have been rejected as economicall y unreasonable on its face without looking further at the effects on the industry . By itself, CCS is 30 to 50 percent of the total capital cost of a project, and6
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the 30 percent parasitic loss resulting from CCS corresponds to a large annual operating cost. However, the proposed BSER is the proverbial "straw th at breaks the camel's back" when considering the total cost of the proposed BSER along with other costs of controls in this source category . I f one were to follow EPA's rationale for not having to consider a pollutant
- specific endangerment finding, because the justification and anal ys is is based upon source category , then one should also apply

that rationale to evaluating total costs necessary to meet BSER for all pollutants, not just the newly added pollutants. CCS and other pollution controls for a PC uni t would easily

account for up to 80 percent of the total cost of a project. In terms of operating cost, CCS and other pollution control equipment combined can account for over 50 percent of the overall annual operating costs. Total costs, both capital and operating, of complying with BSER for all pollutants regulated in the subpart, including CCS controls and other existing required controls, are not economically reasonable. **Response 6.3 -**  **281:** A number of commenters (e.g. 9407) claimed that the proposed rule would lead to ex orbitant cost increases, comparing an SCPC with and without CCS. Several commenters projected capital cost increases on the order of 50%. 56 Commenter NRECA (10952 p. 38) projected an increase of 24% which is roughly the rate of increase projected by EPA f or the final rule, albeit for a less stringent standard than proposed (so capital costs would presumabl y be somewhat less than NRECA projects under its methodology). EPA explains in preamble section V.H.4 why these cost increases are reasonable

– in parti cular, that the industry has absorbed such costs for other NSPS. The same commenter notes that a 12 % capital cost increase was found reasonable in the first Portland Cement case. The commenter is correct as to the result of the case, but the EPA does no t accept the innuendo that 12% is an upper bound of what level of capital cost increase could be considered reasonable under section 111 (a). The EPA believes the more germane comparison is with capital cost increases in prior NSPS for this industry , whic h (like the standard in Portland Cement) were also upheld upon judicial review. Commenters 9423 and 10952 also maintain that EPA simply failed to consider certain costs. Commenter 9423 maintains that the NSPS are the ‘straw that breaks the camel’s back ’ and that EPA failed to also consider the costs of other pollution control standards for this industry . This is incorrect. In assessing costs, the EPA relied on the NETL studies which assume a coal
burning steam generating unit in compliance with applic able environmental standards, including MATS for hazardous air pollution emissions, and the most recent NSPS for criteria pollutant emissions . NETL(July

2015) at p. 29. Commenter 10952 mistakenly stated (Comment p. 38) that EPA had failed to consider transportation and storage costs for captured CO 2 . The EPA’s cost estimates do in fact include costs associated with transportation and storage of CO 2 . See preamble section V.I.5. **Comment 6.3 -**  **282:** Commenter 9514 stated EPA correctly concluded that the costs of installing and operating partial CCS for any new coal plants that may be constructed as a result of the proposed standards are reasonable, and clearly not exorbitant or too high for the industry to bear. The commenter noted EPA has concluded that few, if any , new coal plants would be built in the coming ye ars even in the absence of the proposed NSPS due to the changing economics of the

56 Comenter 9423 (Comment p. 5) provides no basis for its statement that CCS would increase facility capital costs by 30%
- 50% and it is possible the commenter is referring to full, rather than partial CCS.6
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utility sector. According to the commenter, requiring installation and operation of partial CCS at only a few plants would therefore i ncur costs that the industry as a whole could easily

absorb and for this reason, EPA's proposed NSPS would not entail exorbitant costs, and fully satisfy section 111 in this regard. The commenter also stated from an industry
- wide perspective, the increment al costs of partial CCS on few new coal
- fired plants spread over a region would be inconsequential and thus the costs of EPA's partial CCS standard easily meet the standard under Section 111. Commenter 9035 stated that a CCS requirement for new power plants, coupled with federal support, could aid in the development and deplo yment of this critical technology . According to the commenter, the approximately 18 percent cost difference between coal plants without and with CCS (assuming no EOR price) found b y EP A is roughl y in line with estimates made b y other experts. The commenter referenced a 2013 report by I CF International for the National Association of Regulatory Utility Commissioners and the Eastern Interconnection States Planning Council in which I CF rep orted that the inclusion of CCS technology on an IGCC coal plant would add to the levelized cost of electricity by roughl y 18 to 30 percent. According to the commenter, since this estimate assumes no return from EOR, net CCS costs should be lower. Commenter 10525 stated it may be easier for EGU owners and operators to absorb financially the cost of incorporating partial CCS versus full CCS. T he comm e nter also noted that depending on the location of EGUs, owners and operators will have an opportunity to use or sell their captured CO 2 for EOR. **Response 6.3 -**  **282:** The EPA largel y agrees with these comments. The EPA agrees that costs of the rule are absorbable by the industry

on a national basis. Preamble section V.H.6. The EPA has also assessed costs on a per
- plant basis and found them to be reasonable. The EPA agrees that EOR opportunities may be used to further reduce costs, but is not premising its cost analy sis on availability

of EOR opportunities. **Comment 6.3 -**  **283:** Commenter 9592 noted EPA also cited the greater cost to employ CCS for gas - fi red EGUs when compared to coal
- fired. The commenter noted that, however, the 2013 update of the NETL Report concluded: " When today's technology for CO 2 capture and sequestration (CCS) is integrated into these new power plants, the resultant COE, including the cost of CO 2 TS&

M, is: 86 mills/kW

h for NGCC; 108 mills/kW h (average) for PC; and 112 mills/kW h (average) for IGCC. While the commenter agreed that the estimated cost of CCS for gas - fired EGUs is too great for the technology to be considered BSER, they noted that the NETL concludes that the cost for coal
- fired EGUs is even higher. The commenter stated that i t does not seem reasonable that if the gas
- fired CCS cost is too high to be considered BSER, then the more expensive CCS for coal
- fired EGUs could b e BSER. Commenter 9201 stated the following: "According to the Interagency Task Force on Carbon Capture cited b y EPA, DOE anal ys es indicate that post
- combustion CO 2 capture on a 550 MWe net output NGCC plant would increase the capital cost of that plant by 80 percent
--- about the same increase that would result from employing post
- combustion capture on an SCPC plant. The incremental cost increases of electricity for N GCC with CCS is significantl y lower (33%) than for a SCPC plant (60%) given6
- 192

fuel cost estimates, lower capital costs for NGCC units, and other factors. DOE's anal ys es also show that for CCS:

 NGCC has the lowest total overnight cost (TOC) at $1,842/kw as c ompared to SCPC ($4,391/kw) or IGCC ($4,086/kw);  NGCC has the lowest cost of electricity (COE) at $90.43 MWh as compared to SCPC ($147.27/MWh) or IGCC ($141.27/MWh); and  The increase in the COE for NGCC would be about 45 percent as compared to 70 percent for SCPC.<FOOTNOTE 170> As a general matter, NGCC with CCS looks more favorable than coal
- fired EGU with CCS considering that (1) the capital costs of NGCC turbines are roughly one - third the cost of those for SCPC units; (2) there is less CO 2 to capture, compress and store for a NGCC unit; and (3) lower natural gas prices forecasted by EPA will lower the overall TOC and COE for gas as compared to coal, even with CCS on those units." **Response 6.3 -**  **283:** A number of commenters maintained that if CCS is not BSER for NGCC for rea sons of cost, then it should not be BSER for coal
- fired power plants, since the costs are even higher. The EPA is not identifying CCS as BSER for NGCC, but it is on grounds of technical uncertainty. See preamble section IX.C.4.a . Commenter 9201 also bas es its analy sis on the interagency

Task Force Report, which was addressing full CCS, so the costs quoted are much higher than those for the actual standard of performance adopted by EPA in this rule. **Comment 6.3 -**  **284:** Commenter 10095 stated that EPA's cost anal ys is is incomplete and potentially

mischaracterizes the cost of pre
- or post - combustion CCS technologies to support its proposal. The commenter noted EPA's methodology and reliance on the DOE NETL for partial CCS cost estimates for SCPC and I GCC generation technol ogies. According to the commenter, it is necessary

for EPA to provide the most accurate cost estimates as possible when establishing such critical performance standards, and for an emerging technology like CCS, for which cost estimates are changing, it is imperative that EPA use multiple sources and the most up
- to - date costs from ongoing projects to develop the most accurate estimates. The commenter also stated that contrary

to EPA's assertions, the proposal, in fact, intermingles DOE NETL
- based and EIA
bas ed technology

cost estimates in some instances. The commenter noted that the two sources use dissimilar methodologies as described in the Coal Utilization Research Council's (CURC) comments. The commenter stated that EPA needs to address these inconsistenc ies to allow for more comparable results. **Response 6.3 -**  **284:** Inresponse to this and similar comments, and also consistent with the EPA’s attempt to utilize the most up
- to - date information, cost estimates for post
- combustion CCS reflect recent vendor quotes for the Cansolv process – the process currentl y in full
- scale commercial use at the Boundary Dam facility
. In response to comments maintaining that the LCOE values are derived from different sources which do not use identical methodologies, the EPA notes that the latest publication of the Global CCS Institute “examines the costs and emissions intensities of low emission technologies in power generation. It uses cost data for the US from a variety

of published sources and applies these in a common methodological6
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framewor k based on the levelised cost of electricity (LCOE) that allows comparison between different technologies in terms of emission reductions.” 57 The estimates for full CCS (the study does not estimate partial CCS costs) are in the same range as NETL and other techno
- economic expert cost estimates. See preamble Table 10. Nuclear estimates are likewise within the same range of other techno
- economic expert estimates. 58 **Comment 6.3 -**  **285:** Commenter 2471 stated USEPA has falsel y made assumptions to support the CCS technology , such a s in its cost consideration to society
- at - large, rather than the costs at individual units, and utilization of an unreasonable future timeframe to justify its cost
- benefit anal ys es. **Response 6.3 -**  **285:** The EPA has analyzed costs at both the per
- plant and national level. Se e preamble section V.H. **Comment 6.3 -**  **286:** Commenter 9034 stated that even assuming CCS technology could be successfull y implemented at commercial coal
- fired EGUs, it still would not be the BSER for coal plants, because implementing this technology would be cost prohibitive. The commenter noted that Section 111 of the CAA requires EPA to take costs into account when determining the BSER for new sources, and the D.C. Circuit has explained that EPA's BSER determination will not be sustained when the costs of using the technolog y are "exorbitant" or "excessive." Commenters 7977, 9197, 9201, 9600, and 10880 stated that partial CCS is not BSER when costs are considered. Commenter 10880 referenced the recent rejection of CCS at Edwardsport due to costs and noted that several engine ering studies concluded that the costs for a coal EGU with 90% capture will increase costs by 70
- 79% over a plant without CCS. Commenter 9201 stated that technology

experts and utilizes agree that CCS is not adequately demonstrated, providing the discontinuation of the Mountaineer project as evidence, along with citing testimonies from DOE and Duke Power on the high costs of CCS. The commenter also provided reasons why a new coal plant with CCS would cost substantially more than one without CCS including equipment costs and the energy

penalty
. Commenter 9596 stated EPA's assertion that CCS is adequatel y demonstrated notwithstanding the exorbitant costs represents a departure from EPA's previous practice in setting performing standards. Commenter 10618 stat ed that EPA's rationale for eliminating full capture CCS as the BSER based on costs is equall y applicable to partial capture CCS. The commenter provided additional reasons that full or partial CCS is not the BSER, including technical, financial, regulatory and practical considerations. According to the commenter, the experience of recent projects and findings of major studies demonstrate that EPA's cost analy sis is flawed and that CCS is not the BSER. For example, the commenter stated that EPA's range of a 12 to 60% cost increase for

57 Global CCS Institute, “The Costs of CCS and Other Low
- Carbon Te chnologies

– 2015 Update” (July 2015) p.2.. The sources utilized, and evaluated under a common methodology, are Lazard 2014, EIA 2014, IPCC 2014, Brookings 2014, EPRI 2013, IEA 2012, and NREL 2015. App.A. 58 EIA 2014, $87
- 115; Lazard 2014, $92
- 132; Global CCS Institute, $86
- 102 (p. 9).6
- 194

CCS is far below the estimates of DOE and others that approach 80% or more. The commenter concluded that If the 40
- 60% increase was sufficient to eliminate full capture, then the 80+% increase experienced b y active projects and estimated b y DOE and others is more than sufficient to also eliminate partial capture as the BSER. Commenter 8966 stated under Section 111 of the CAA, technology constituting a BSER cannot impose an exorbitant cost to achieve a performance standard; howev er partial CCS is exorbitantly

costly . According to the commenter, enactment of the proposed rule would make it virtually impossible for any

new coal power plants to be constructed and remain viable. The commenter continued that as the existing fleet of ag ing coal power plants is retired and not replaced b y new coal
- fired plants, the costs imposed by the proposed standard would indeed be greater than the industry

could bear and survive, which violates the Section 111 cost provision. Commenter 10952 stated that while EPA's conclusion that carbon capture is BSER is not supported by

the rulemaking docket and is otherwise arbitrary , EPA's sole rationale for concluding such is based on exclusive reliance on information gleaned from projects that EPA is prevented from considering. According to the commenter, for these DOE funded projects, EPA has not and cannot point to any full scale project that utilizes the technology identified as BSER, nor can it point to any

project with an operating history that can yield re al costs associated with actuall y emplo yi ng carbon capture at an EGU that would allow appropriate and needed anal ys is regarding operational costs and viability so to justify

its BSER determination. **Response 6.3 -**  **286:** A number of commenters pointed to costs incurred at the E dwardsport and Mountaineer projects as evidence that a CCS
- based BSER is exorbitantly costly . The commenter acknowledges that its cost estimates for Edwardsport reflect full CCS, which is not the basis for the BSER determination in the final standard. No r is BSER based on IGCC, and the EPA notes that at both Edwardsport and Kemper, it was cost overruns on IGCC (rather than CCS) that were the source of cost overruns. Indeed, Edwardsport is IGCC only at present, so cost overruns obviousl y have nothing to d o with CCS. Mountaineer was a retrofit, not a new source , and incurred high costs for reasons one might expect relating , at least in part (and as stressed in its public comments), to sequestration sit ing difficulties after already locating at a site selected without consideration of sequestration opportunities. Commenter 10628 (AEP) maintained that partial CCS is exorbitantly costly by EPA’s own logic. The commenter maintains that the EPA rejected full CCS as BSER yet the cost of partial CCS is withi n this same range, properl y analyzed and considering the upper end of the NETL range of cost estimates. The EPA has adopted a somewhat less stringent standard of performance than proposed in large part due to considerations of cost. The final standard of performance is comparable to nuclear, including at the upper range of potential cost estimates . See preamble at Table 8. Moreover, the comment is somewhat misleading. The EPA indicated not that a certain cost was too great, but rather that the cost was too great in relation to the cost of other non
NGCC low
- carbon technologies with which it would be competing. As it happens, the cost of the final standard of performance (normalized to LCOE) is far lower than the values cited in the comment , even though this is not the proper metric to evaluate. Commenter 10952 indicates that the proposed standard of performance rests on EPAct facilities which EPA cannot properly consider. In fact, EPA at proposal noted that Boundary Dam was6
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due to commence operations, and it has in fact done so. The commenter’s claim is therefore incorrect for post
- combustion CCS, and is also incorrect with respect to pre
- combustion CCS. See preamble section V.D and E. Commenter 8966 stated that that as the existing fleet of aging coal power plants is retired and not replaced b y new coal
- fired plants, the costs imposed by the proposed standard would indeed be greater than the industry

could bear and survive. However, coal is already significantl y less economic than new NGCC capacity an d is projected to remain so for the foreseeable future
. RIA chapter 4. Thus, if new coal is added, it will be because developers believe it pr udent to pay

a cost premium. An additional cost premium associated with partial CCS still leaves coal cost comp etitive with nuclear, the baseload dispatchable non
-NGCC technology which might also be added for the same reason. See preamble at Table 8. The EPA further notes that in a lower
carbon future, CCS may

prove to be the technology that allows new coal to co ntinue to be constructed. This appeared to be the view of commenter AEP: “AEP still believes the advancement of CCS is critical for the sustainability of coal
- fired generation.” 59 **Comment 6.3 -**  **287:** Commenter 9664 provided information to support EPA's cost anal ys is and BSER determination for CCS. The commenter stated that when evaluating a performance standard's projected costs, EPA may take into account the standard's long
- term impacts on both a plant
- wide and nationwide basis, including effects on the national economy and the legislative history affirms that the term "best technology " encompasses considerations of long
- term growth, long
- term cost savings, and financial incentives for improved technology . The commenter also stated EPA appropriately recognizes that the constr uction and operating costs associated with CCS technologies will decrease as further experience with them is gained in response to the standard, referencing the setting of mobile source air emission limits as a previous example. The commenter also stated the statute and case law authorize EPA not only to evaluate the costs of achieving the standard, but also any offsetting revenue streams, and to weigh the severity of the pollution problem to be addressed, in selecting missions control options comprising th e "best" sy stem of emission reduction. The commenter also stated Section 111(a)(1) directs EPA to "take into account" the cost of achieving reductions and any nonair quality health and environmental impacts and energy requirements when selecting the BSER and setting performance standards. The commenter provided additional discussion on several D.C. Circuit court cases to support their argument. The commenter also stated that as EPA correctl y observes in the preamble to the proposed rule, the D.C. Circuit ha s never invalidated an NSPS as too costly , providing information on several court cases. **Response 6.3 -**  **287:** The EPA largel y agrees with this comment. **Comment 6.3 -**  **288:** Commenter 8966 stated coal
- fired plants depend on fundamentall y distinct processes. CO 2 emissions from coal plants are greater than other sources due to the intrinsic

59 CCS LESSONS LEARNED REPORT American Electric Power Mountaineer CCS II Project Phase 1, Prepared for The Global CCS Institute Project # PRO 004, January 23, 2012, page 2. See also AEP FEED Study at pp. 4, 63 (same).6
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properties of coal during combustion. As a result, the magnitude of CO 2 capture is greater and will cost significantl y more than for other industries. The commenter provided additional concern with EOR re
- use and future expectations of reduced CCS costs, noting the costs of CCS implementation are heavily amplified for prospective coal power plant operators, marking a particularl y exorbitant cost that distinctly hits the coal ind

ustry . **Response 6.3 -**  **288:** See preamble section V.H.8. **Comment 6.3 -**  **289:** Commenter 9407 disagreed with EPA's conclusion that the proposal, if finalized, will have no cost, stating that this proposal's cost to the nation in terms of a flawed energy policy and resulting costs to the nation's ele ctric consumers would be substantial. According to the commenter, these are compelling reason to rethink this NSPS proposal. Commenter 2470 stated EPA should avoid one
- size
- fits
- all mandates that would unnecessarily increase utility

costs. Commenter 9592 s tated not only is CCS technology

not ready for commercial deploy

ment, it will be excessively

costly to the consumer. Commenters 8024, 8966, 9505, 9592, 9780, 10662, 10667, 10880, cited U.S. DOE statements that CCS technology

would increase the cost of pro ducing electricity by as much as 80 percent. Commenter 8918 stated CCS costs are not reasonable, as Great River Energy's mission calls for "affordable rates" to our member cooperatives. According to the commenter, approximately 83% of their member cooperat ives' energy sales are residential. The commenter noted that as discussed in NRECA's comments, relying on a reasonable cost criterion being less than the cost where "industry

could not bear and survive" ignores the majority of the people to whom we and our member cooperatives supply electricity. Commenter 9780 stated that the level of cost increase resulting from the proposal to require partial CCS for coal plants would likely be a "death knell" for any projects aimed at increasing fuel diversity

in the el ectric generating fleet, as no customer would be willing to pay such a premium. According to the commenter, it is highly unlikel y that any state public utility commission would approve its construction, and that certainl y no competitive wholesale electrici ty market would bear such costs. According to the commenter, customers and retail rate regulators demand reliable electricity , but they also demand that it be provided at a reasonable price; however, the costs and parasitic load impacts of CCS technologies significantly increase the projected cost of building a coal plant which is why CCS is routinely

rejected in GHG BACT anal ys es for new or modified plants. The commenter noted that the Power4Georgians plant that EPA cites as an example of one that customer s would be willing to pay a premium for was designed as a conventional coal plant without CCS in order to compete with natural gas. Commenter 9196 stated that the proposed rule will limit fuel options and cause increases in electricity costs. According to the commenter, removing coal from our country's energy mix in the future raises additional concerns due to the volatility that exists in the other energy markets. The commenter cited testimony from David Wright regarding the need for a diverse resource po rtfolio to protect ratepayers against price increases that one fuel may experience. The6
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commenter also stated that increases in electricity costs harm the econom y, public health, and the environment. According to the commenter, affordable, reliable energy is one of the main drivers of economic growth, and increasing the cost of energy and thereb y forcing U.S. industries oversees is something we cannot risk as our country continues down the path of economic recovery . The commenter noted that higher electrici ty prices will disproportionately impact vulnerable individuals. The commenter also noted the proposed rule is likely to adversel y affect public health in three way s: by increasing the cost of medical care and treatment; by imposing real threats on human h ealth by suppressing economic growth and the improved health it brings; and by focusing on expensive rulemakings with little incremental benefits when those resources, if more sensibly

deployed, could save many times more lives. Furthermore, the commenter suggested that the higher electricity prices will be largel y borne b y companies in energy
intensive manufacturing, where higher prices will make it more difficult to expand operations and increase emplo ym ent, and provided information on the link between un employ ment and public health. The commenter also provided information on energy costs for hospitals and the implications for their budgets. Commenter 9770 stated EPA would need to evaluate the energy and costs, including the cost of electricity to communi ties of partial CCS in order to determine that CCS is an "adequately demonstrated" s ys tem of emission reduction. Commenter 9505 stated that the proposal fails to address the significant financial barriers that will simply

result in higher costs for ratepayers, and ultimately , the taxpayers of the States. Commenter 9107 stated industry concerns that CCS is not proven and it will increase costs of coal use and resulting into higher costs to the public. According to the commenter, high cost of this otherwise m ost economical coal fuel will take away the competitive advantage of the manufactured goods b y the US industries compare to the countries who continue to allow their industries to operate without such mandates. The commenter suggested alternate solutions are needed which will allow the use of abundant resources of coal in USA while mitigating environmental and climate control concerns as you are seeking per these EPA mandates without increasing costs. Commenter 4162 stated that EPA should avoid one
- size
- fit s - all mandates that would unnecessarily

increase utility

costs. Commenter 9423 stated disagreement with EPA's conclusion that the cost of BSER "could be passed on without substantially affecting competition." TCEQ, PUC, and RRC noted that costs can be pass ed on more gradually and over a longer period of time in a regulated electric market than in a competitive electric market like Texas' Electric Reliability Council of Texas (ERCOT). According to the commenter, companies in a competitive electric market are more sensitive to additional costs, and are more likely to transfer those increased costs to electric consumers in the short term. Consequently, the commenter stated that the ability to pass on the cost of BSER is likely to affect competition. **Response 6.3 -**  **289:** A number of commenters maintained that consumers would pay the cost of increased electricity

prices associated with a standard of performance reflecting performance of6
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partial CCS (e.g. commenters 8918, 9780). Commenter 9196 projected significant costs in reduced manufacturing output and general economic non
- competitiveness. These comments appear to assume that new non - compliant coal capacity will be constructed, yet all evidence is to the contrary , and for reasons unrelated to the standard of performance adopted he re. See RIA chapter 4. Even in Kentucky , the very heart of coal country , new capacity i s NGCC. 60 EPA explored scenarios using alternative assumptions with considerabl y higher future electric demand and higher natural gas prices, and no scenario resulted in new conventional coal by 2020. Independent anal ys is and projections from EIA confirm this trend . EPA does not project any change in energy

prices as a result of this rule, and as such does not expect negative impacts on the affordability

or reliability

of electricity
. Thus , EPA’s conclusion that there is likel y to be no new non - compliant capacity bu ilt during the section 111 (b) review period is well founded. Nor does the EPA believe there is compelling evidence that new coal capacity would be competitive but for the cost increment associated with partial CCS. See preamble section V.I.4. Commenters 2470 and 4162 urged the EPA not to adopt a ‘one size fits all’ standard. In fact, there are alternative compliance pathways available to meeting the final standard of performance while using coal as the fuel. In response to Commenter 9423’s statement reg arding cost recovery in competitive energy markets, the EPA notes that competitive electricity markets were designed to send price signals to incentivize the development of cost
- effective generation, allowing for cost recovery for those units through diffe rent market mechanisms depending upon the design of the specific competitive market. Through security constrained economic dispatch (SCED), the s ys tem operator determines which resources will be dispatched to meet s ys tem load, utilizing available resources to serve load as inexpensively as possible. Competitive markets have mechanisms that allow the recovery

of environmental compliance costs, similar to how other generator costs are recovered. The s ys tem operator will dispatch those units that are needed to reliably serve load, with dispatched units receiving the market price. **Comment 6.3 -**  **290:** Commenter 9684 stated the recycled Carbon Rule is still a fuel
- switching mandate, although not as overtly so. The commenter stated in the first go
- round, EPA decided that CCS was not an "adequately demonstrated" s ystem of emission reduction. The commenter noted that the levelized cost of new coal power plants already exceeded that of new NGCC plants, and according to EPA's 2012 proposal, today's CCS technologies would add around 80% to the cost of electricity

for a new pulverized coal (PC) plant, and around 35% to the cost of electricity for a new advanced gasification
- based (IGCC) plant. The commenter noted EPA has since changed its tune, arguing that during the period between the original and revised proposals, several utility
- scale CCS projects have made significant progress towards completion, so the technology

now qualifies as adequately demonstrated. The commenter provided information on the increased costs associated with the Kempe r project noting that unless a utility intending to build a new coal power plant wants to go bankrupt, it's only real choice is to fuel
- switch and build an NGCC plant instead.

60 See, e.g. Washington Post , “Outrage Over EPA Emissions Regulations Fades” p. A
- 1 (July 23, 2015); Washington Post , “The Demise of Coal
- Fired Plants” (Nov. 23, 2012) (both available in the administrative record for this rule).6
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Commenter 9486 stated concern that compliance for new coal
- fired power plants re lies on CCS control technologies that are new and unproven when applied to the coal power industry as a combined sy stem for control and are cost prohibitive to implement at this time. According to the commenter, the cost of CSS control technologies could b e so high that U.S. EPA will be inadvertentl y eliminating a much needed piece of the nation's complex future energy suppl y puzzle which includes coal, natural gas, nuclear, wind, solar as well as other renewable resources. Commenter 9197 stated the extreme ly high cost of producing electricity from coal with partial CCS, combined with the need to account to both regulators and shareholders for their investment decisions, will likely

preclude most
- if not all
- utilities from investing in new coal
- fired generati on. For most of these utilities, the costs of implementing partial CCS
- in relation to natural gas combined cycle (''NGCC"), which is the only other trul y viable option for new baseload power
- will be so excessive as to make investment in new partial CCS
- cap able facilities unreasonable. Thus, as existing coal
- units retire, the proposed NSPS will effectivel y preclude the supply of new coal
- fired electricity to future electricity markets. For all of these reasons, we do not agree with EPA that CCS is adequately demonstrated when considering cost. **Response 6.3 -**  **290:** See preamble section s V.H and I. Costs of new coal are already not competitive with new NGCC, and the final standard of performance preserves the possibility of coal for fuel diversity reasons by adopting a standard w ith an LCOE within the same range as new nuclear technology , the other baseload dispatchable non
-NGCC option. Nor does it mandate a single manner of compliance, given that there are various potential compliance paths available to achieve the final standard of performance. **Comment 6.3 -**  **291:** Commenter 10239 (pp. 17
- 18) referenced two Iowa DNR PSD permit decisions which concluded that CCS was too costly . The commenter noted that in one of the decisions, the Iowa agency highlighted transport costs to suitable GS sites as a key impediment to CCS. The commenter stated that EPA reviewed each permit and did not comment or question Io wa DNR's conclusions on CCS. The commenter also cited to the State of Michigan’s action in rejecting CCS as BACT for the Wolverine facility
. **Response 6.3 -**  **291:** The comment er refers to actions taken by state agencies in rejecting CCS on cost grounds when making individual BACT determinations. First, these agencies were evaluating full CCS, not partial CCS. Second, the agencies all evidently found that CCS (even full CCS) w as technically feasible (since determinations were not made at step 1 of the BACT anal ys is), but rejected on grounds of cost, especially (in the case of the Iowa determinations) cost of transport and sequestration. The final standard of performance has alternative pathway s not involving sequestration, in the event a new source chooses to site in a location without ready access to sequestration (and this is a very limited area

– see preamble section V.M and Availability

TSD). Third, these are state determi nations, not determinations of EPA. As explained in preamble section XII.C, state agencies that have their own approved state implementation plan, the state has primacy over their permitting actions and discretion to interpret their approved rules and to apply the applicable federal and state regulatory requirements that are in place at the time for the facility in question. The EPA’s role is to provide oversight to ensure that the state operates their PSD program in accordance with the CAA and6
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applicable rules. If the EPA does not adversel y comment on a certain permit or BACT determination, it does not imply EPA endorsement of the proposed permit or determination. **Comment 6.3 -**  **292:** Commenter 9677 stated EPA relies on data that shows CCS increases capital costs for a supercritical pulverized coal unit by 34.6%, fixed O&M costs by 28.5%, and variable O&M costs b y 36.4%. The commenter noted that in the Portland Cement case, which is referred to in the Proposal's cost discussion, it was determined that the cost of technologies that a new facility would need to install to meet the standard was around 12 percent of the capital cost for the entire facility

with annual operating costs increasing b y 5
- 7 percent. It was also determined that these costs could be recovered "without subst antially affecting competition." By contrast, the commenter concluded, the CCS incremental capital cost and operating cost increases, mentioned above, are much higher than those which were discussed in the Portland Cement case as being acceptable. **Response 6.3 -**  **292:** The commenter is correct that the capital cost increases here are higher than those found acceptable in the first Portland Cement I case, although that case did not say that the costs were at the upper range of acceptability. As shown in preamble section V.H. 4 , the capital cost increases here are within a range found acceptable for this industry in prior NSPS . Th e increases associated with the final standard of performance also are less than those cited b y the commenter, given the reduced stringency of the fin al standard of performance compared to the proposed standard
. See RIA at Table 4
- 4, showing capital cost increase (in the bituminous coal case) of 21.3 %, FOM increasing 1 9.7 5%, and VOM increasing 1 1 %. **Comment 6.3 -**  **293:** Commenter 7422 stated concern that the level of funding available from government assistance programs in the future may be less than the EPA asserts and that the costs of CCS may

decline less than forecasted. The commenter also stated that in a restructured market, the impact on market
- based investment decisio ns is even more dramatically impacted by reliance on government funding availability as merchant generators do not have customers from whom they

can recover costs like traditional, vertically
- integrated utilities. This distinction is critical and should be an important consideration in this rulemaking. The commenter stated that this is all the more reason to allow for state and regional consideration and flexibility . According to the commenter, the cost of installing CCS on a new coal boiler is sufficiently high to make it extremely unlikel y for a regulated utility or merchant generator to consider construction of coal
fired generation when constructing new generation resources. Commenter 10243 stated costs to install CCS on a new coal
- fired power plant are prohibitively high, and CCS projects in the U.S. are viable onl y as a result of government assistance. **Response 6.3 -**  **293:** The EPA has reasonabl y determined that costs of partial CCS, at the level of capture reflected in the final standard of performance, are not exorbitant and are reasonable. See preamble sections V.H and I
. **Comment 6.3 -**  **294:** Commenter 9318 stated the agency's assumptions in the new unit rule about the availability

of CCS are unreasonable and unproven. According to the commenter, if these positions are repeated or incorporat ed into the existing source rule, impacted units will likely not be able to compl y with any existing source rule in a cost
- effective way
. T he commenter stated CCS is at best an unproven and expensive experimental technology that should not be used as the6
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basis for emissions standards in the existing source rule. The commenter urged EPA to decline to adopt these assumptions in the existing unit rule in light of the agency's assertion that it is seeking cost
- effective and flexible solutions. **Response 6.3 -**  **294:** BSER under the guidelines for existing sources does not include CCS. **Comment 6.3 -**  **295:** Commenter 9666 stated the methodology to project SCPC and NG/CC cost for a 30
- ye ar time period should be improved. The commenter suggested the methodology should consider the following: Varied Capital Cost Sources. Additional cost sources should be sought. The six studies cited in this report invoke three sources of data
- two proprietary databases and the EIA
- and results show capital cost estimates depend on the data source. A key variable is how esc alation is handled. Role of Suppliers and Vendors. The inputs provided by vendors or suppliers, and how they are used, should be evaluated. As discussed in the critique in Appendix A, (of the commenter's attachment) costs submitted by vendors in some cases should be adjusted for scope, fuel ty pe, or other variables. A more robust approach soliciting budgetary quotes for this material and reviewing in the context of more than one in
- house database, constructed from recent cost data, and using a more realistic sensitivity

anal ysis that reflects the actual variations in capital cost incurred and anticipated is advised. According to the commenter, the cost estimates cited by EPA used to dismiss SCPC as a viable power generating option over the next three decades appear based on data from one engineering firm, the bulk of which appears gathered during the time period of 2005
- 2007. How these costs were adjusted for market conditions and price escalation is not clear from the reports. Discussion is presented in two reports suggesting that rather than escalating 2005
- 2007 costs to latter years, a separate procurement document was prepared and issued to revise estimate. This approach appears limited to certain categories of ancillary equipment. For the cost estimate published in September 2013 that is used by EPA, it is not possible to tell if the cost is determined using (a) data from 2004
- 2007 that is escalated using a cost index, versus (b) recent commercial bids in response to a procurement. The commenter al so stated that NETL estimates for the capital cost for SCPC and NG/CC equipment are compromised by several factors: the escalation of capital equipment prices due to strong global demand; the drop in natural gas price and improved cost viability of NG/CC e quipment; and the overnight drop in SCPC equipment demand. These factors should be considered in estimating equipment costs going forward for 30 ye ars. **Response 6.3 -**  **295:** Commenter 9666 (UARG) suggests a variety of means of assessing costs of SCPC and NGCC technologies for the next 30 years. Before answering the spe cifics, the EPA notes that the 3 0
- year time frame suggested b y the commenter is not compelled by statute (section 111 (a) does not specify a time frame for consideration of costs) , nor any compelled6
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factual justif

ication . The time frame generall y considered in the RIA

– through 2022, the ye ar of the next review cycle for NSPS under section 111

– is reasonable. The commenter’s specific suggestions also are somewhat misplaced. The commenter requests the EPA to ev aluate other sources for capital cost estimates than used at proposal. EPA has made every

effort to use the latest figures. The NETL(July 2015) cost figures reflect recent vendor quotes for the Shell Cansolv process, the process in (successful) full sca le commercial use at Boundary

Dam. The NETL methodology for financing involves assuming “high
- risk financial costs” (p. 18). The commenter’s request regarding use of vendor quotes is answered immediately above. The EPA has also evaluated the NETL estimate s against those of other techno
- economic estimates and marketplace quotes from suppliers and found them to be consistent. See e.g. preamble at Tables 8
- 11. The commenter also questions the reliability of the NETL cost estimates vis
- à
- vis SCPC technology
. The AEP John W. Turk facility is an example of a highl y efficient supercritical PC. In comments of AEP (p. 76), AEP represented the cost of the Turk facility as $2,885/kW. The DOE/NETL estimates for such a facility is $2,842/kW (NETL , 2015

– for a plant using bituminous coal). This close agreement is another validation of the NETL cost methodology generall y, and for SCPC specificall y. **Comment 6.3 -**  **296:** Commenter 10119 provided the following discussion: "Nonetheless, EPA states it may decide to exempt the plant because th ere might be "opportunity costs"
--- specificall y market opportunities that could be realized only b y beginning construction immediately
--- associated with complying with the standard. Of course, because it has formed "no view" as to the facility's constructi on status or market opportunities, EPA has no idea whether these opportunity costs even exist, much less whether compliance with the performance standard would impose opportunity costs. Incredibly , EPA declines to determine whether the statute even authori zes it to consider "opportunity costs," claiming it is unnecessary to do so in light of EPA's own uncertainty as to whether there are any "opportunity costs" to consider. EPA cannot justify

an exemption from plain statutory requirements on the basis of fac ts it declines to find and legal analy sis it declines to undertake. The requisite process of notice and comment is fatally undermined when a proposed rulemaking omits the factual basis, the legal rationale, and even aspects of the rule itself, leaving the public to guess at what action the agency might take and wh y the agency chose to take it. A final rule announcing a decision based on such an entirel y inadequate notice and comment process would be invalid for this reason alone. In any event, reliance on " opportunity costs" to exempt a project that has not yet commenced construction is just as impermissible as consideration of "sunk costs" (we do appreciate, however, EPA's withdrawal of "sunk costs" as a possible reason for exempting sources from NSPS). Tho ugh nebulous, EPA's concept of "opportunity costs" seems, in essence, to amount to no more than ordinary

but unverifiable and highl y fluid commercial expectations of profits. Thus, EPA characterizes opportunity costs as those involved in forgoing the abili ty "to meet a valuable near
- term resource need or market opportunity ." But meeting such needs and market6
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opportunities is precisely why all industrial plants are conceived and pushed forward, and why pre - construction costs are incurred in the first place: these opportunities and needs, and the profits expected from capturing them, must be anticipated to be sufficiently large and near
- term to justify the planning and pre
- construction costs in every case. The promulgation of new NSPS standards and their conco mitant additional expenses and potential construction delay s will alway s affect these market opportunities, and each specific source will be affected differentl y depending on a m yriad of individually applicable factors. Those factors and their evaluation are far outside the agency's ken, and include the specific and shifting business, financial, strategic and contingency

plans of each facility , its owners, investors or lenders, as well as the characteristics of the market opportunities themselves
--- informat ion which often consists of highl y valuable, confidential business information closely guarded against disclosure b y all the market participants. In other words, the promulgation of new standards will always affect the often confidential business opportuni ties and profitability projections of projects any where along the pre
- construction stage, and will do so in way s unique to each project and shifting over time. Congress clearly

recognized this problem, and thus set an unambiguous cut
- off point that determi nes when a project will have to comply , and its market opportunities will therefore be affected: that cut
- off point is whether construction has or has not commenced at the time a standard is proposed. The statutory language is clear, and EPA has longstandi ng regulations enforcing it. EPA may

not override Congress' express judgment on this point." **Response 6.3 -**  **296:** EPA’s position on sources under development are set out in preamble section III.J. EPA notes further that it has ample discretion under section 111 to create sub categories, and can reasonably do so under the circumstances set out in preamble section III.J. **Comment 6.3 -**  **297:** Commenter 10667 stated coal and lignite are vital to Texas' continued economic success and electricity security and any impacts to these industries place the entire Texas economy

at risk. **Response 6.3 -**  **297:** The EPA is of course s ympathetic to these and related comments. As shown in chapter 4 of the RIA, however, new non
- compliant coal technology is very unlikel y to be constructed anywhere in the country for reasons unrelated to the new standard of performance. **Comment 6.3 -**  **298:** Commenter 10869 stated f or CCS to play

a major role in reducing CO 2 emissions, new infrastructure must be constructed to capture, process, and transport large quantities of CO 2 . Support for commercial
- scale, fully integrated CCS demonstration projects at coal
- fired power plants should be a part of our energy strategy , alongside investments in R&D on other low carbon energy

resources. Careful selection and monitoring of geologic storage (or "sequestration") sites, and the development of regulatory standards and mechanisms to guide this process, will be needed to minimize the environmental risks associated with CO 2 leakage (including groundwater contamination). As more CCS project s are undertaken, learning opportunities and economies of scale could help drive down costs and improve performance of this technology . The ultimate costs of compl yi ng with regulations for limiting other pollutants, including SO2 and NOx, have turned out t o be much lower than either the EPA projected or industry warned. EPA's carbon standard for new power plants provides an incentive to industry to undertake investments in CCS. Projections6
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from EIA, MIT and IEA show that CCS costs could come down over time as the technology is more widel y deplo yed. For example, in AEO 2013, EIA projects coal PC with CCS capital costs to fall 9 percent by

2025, 14 percent b y 2030 and 23 percent b y 2040 compared to 2015 costs. Studies by

the Department of Energy (DOE) also pro

ject cost declines for advanced PC and IGCC power plants with carbon capture, of 27 percent and 31 percent, respectivel y, relative to current costs.41 EPA carbon standards could be an important driver for these cost reductions. **Response 6.3 -**  **298:** The EPA agrees with the ton e of this broad policy
- oriented comment, although the existing CO 2 transportation infrastructure is more extensive than the commenter appears to envision. See preamble section V. M. **Adequate Demonstration Comment 6.3**  **- 299:**  Commenters 2525, 7433, 8349, 8501, 8971, 8974, 90 01, 9192, 9194, 9396, 9407, 9425, 9428, 9595, 9596, 9725, 9735, 9770, 10024, 10028, 10036, 10086, 10087, 10096, 10098, 10105, 10238, 10242, 10387, 10392, 10393, and 10501 stated that CCS is not adequatel y demonstrated. Similarly, Commenters 0840, 7977, 897 1, 9034, 9194, 9382, 9601, 9648, 9773, 10044, 10083, 10103, 10242, 10391, 10395 and 10097 stated that EPA has not demonstrated that carbon capture meets NSPS statutory requirements for adequate demonstration because no full scale power plants currentl y ope rate with CCS. Commenter 9472 also proposed that EPA's determination that CCS is adequatel y demonstrated conflicts with its own permitting decisions. Commenter 9596 commenter that the performance standard itself is also invalid as a matter of law because CCS has not been adequatel y demonstrated. Commenter 10098 stated that EPA's conclusion that CCS is adequatel y demonstrated is based on a series of misunderstandings and mischaracterizations of existing data. Commenter 10392 cited technological immaturity, accessibility and transportation issues as arguments against adequate demonstration. Commenters 9773, 10028 and 10030 cited feasibility and cost as reasons wh y they disagree with the BS ER determination. Commenters 9407 and 9194 cited the lack of transpo rtation, storage and monitoring infrastructure as reasons why CCS cannot be BSER. Commenter 9396 stated that EPA has not addressed pipelines, monitoring, sequestration, or impacts related to non - air quality health, environmental, costs, or electricity reli ability as required to demonstrate achievability . Commenter 9770 stated that EPA has ignored cost, land use and feasibility issues, such as the cost and time needed to build and permit pipelines and find suitable sequestration sites. Commenter 7433 cited cost, transport and safety concerns as reasons adding to the uncertainty of the technological feasibility . Commenter 0775 noted that while there are some active CCS projects, they have diminished since last year and few of the active projects demonstrate the feasibility of using CCS. Commenter 10062 also cited IPCCs concerns about the operational safety and long
- term integrity of CO 2 storage. Commenters 0588, 8966, 9381, 9396, 9423, 9648, 9666, 10046 and 10619 also added that technical feasibility

is not the same as adequate demonstration and CCS is not adequatel y demonstrated. Commenter 9382 stated that not even IGCC is adequatel y demonstrated. Similarly , Commenter 8501 states that 'projected to be available' is not the same as 'adequate demonstration'.6
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Commenter 9497 recommended that EPA reexamine the rule in four ye ars to determine if CCS is then adequately

demonstrated and Commenter 10046 recommended that EPA wait a year or two to gather the necessary

operating data. Commenter 9317 recommended that EPA not consider CCS until an 8 year technology review has been conducted to ensure concerns have been addressed. Commenters 2470, 10062 and 10880 recommended that EPA must wait to determine if CCS is adequately

demonstrated until reliable data at commercial scale EGUs is available. Commenter 9683 encouraged EPA to re
- propose the rule so as to not discourage the continued development of CCS, and Commenter 10518 encouraged EPA to re
- propose the rule using optimized heat rate efficiencies. Commenter 8949 stated that EPA should be prepared to revise or revoke the proposed rule should the reference facilities fail to meet the anticipated emissions reductions. Commenters 9190, 9666, 9678, 9725, 10083, and 10680 stated that the CAA does not allow for unproven technol ogies to be considered and therefore, EPA should adopt a BSER standard that does not rely on CCS. Commenters 2470 and 9648 encouraged EPA not to require CCS until the technology has been adequatel y demonstrated on more than one ty pe and size of coal plant. Commenter 9396 asserted that the rule's interpretation of the CAA only serves to promote uncertainty and instability. **Response 6.3 -**  **299:** Most of these comments are full y addressed in the preamble to the final rule. See, e.g. preamble sections V.D and V.E (post
- and pre
- c ombustion partial CCS are demonstrated technologies); V.H., V.I and V.O (efficient SCPC and partial CCS are adequatel y demonstrated considering issues of cost, nonair quality health and environmental impacts and energy requirements). Is sues relating to pipeline and sequestration (commenter 9396) are addressed in preamble section V.I .5 and V.N. Comments maintaining that individual BACT determinations (none of them involving EPA determinations regarding fossil
- fuel fired EGUs, as it happens) are addressed i n preamble section XII.C. and other comment responses. Commenters’ undocumented claims of safety issues and reliability issues associated with CCS (e.g. comment 10062) are lacking in basis. Boundary Dam is operating highl y effectively. Dakota Gasificati on has been operating full CCS effectivel y for decades. See NETL (2015) at p. 36: “The capture and CO 2 compression technologies have commercial operating experience with demonstrated ability

for high reliability.” **Comment 6.3 -**  **300:** Commenter 1959 remarked that CO 2 storage has not been demonstrated sufficiently

to win public acceptance and that public opposition to storage may preclude CCS at some locations. **Response 6.3 -**  **300:** Public awareness and support have been widel y recognized as critical components in the development of new energy infra structure, including CCS deploy ment . Efforts have been made to design strategies for successful outreach to the public
. For example, under the DOE Regional Carbon Sequestration Partnerships, DOE has been engaging with local communities to educate and infor m them about planned pilot and demonstration projects in their areas. DOE’s Best Practices for Public Outreach and Education for Carbon Storage Projects presents lessons learned through the planning and implementation of CCS projects, as well as best practices for community engagement.6
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**Comment 6.3 -**  **301:** Commenters 9035 and 10869 cited several projects that indicate that broad experience with CCS although it has not been deployed at the commercial scale. Commenter 9035 also noted that all commercial scale projects rely on EO R and that EPA has provided a pathway for demonstrating geologic storage through EOR by meeting requirements for UI CP and GGRP. **Response 6.3 -**  **301:** The EPA agrees that geologic sequestration is adequately demonstrated and that the regulatory

requirements and safeguards of the Underground Injection Control Program and complementary

monitoring and reporting requirements of the GHGRP, together ensure that sequestered CO 2 will remain secure and provide the monitoring to identify and address potential leakage. **Comment 6.3 -**  **302:** Commenters 1902, 1959 , 2470, 4217, 6871, 8952, 8954, 9190, 9201, 9202, 9382, 9426, 9472, 9487, 9497, 9505, 9597, 9657, 9666, 9678, 9683, 9725, 9780, 10023, 10033, 10036, 10098, 10137, 10239, 10243, 10393, 10396, 10466, 10660, 10662, 10680, 10974 and 10975 stated that CCS is n ot adequatel y demonstrated because coal EGU (including pulverized coal and simple cycle units) has ever used CCS in commercial operations or achieved the proposed emission limit. Commenter 10023 added that EPA cannot rel y on estimates of performance. Comme nters 9201 and 10662 remarked that EPA dismisses SCPC and I GCC technology as BSER without assessing the recent improvements and anal yz ing industry investment patterns. Similarly, Commenter 4814 proposed that a more practical option would be to base the sta ndard on the latest coal technologies such as the CFBC or ultra SCPC. Commenter 9201 also discussed EPA's assertion that all new coal builds are designed with CCS in mind, stating that the majority seeking permits have since failed or switched to natural g as. Commenters 10974 and 10975 stated that in contrast, CO 2 emissions will increase due to the parasitic load associated with CCS. **Response 6.3 -**  **302:** Post
- combustion CCS is demonstrated in full commercial scale at Boundary Dam #3. In response to comments urging that supercritical PC alone be BSER (e.g. comment 9201) , see preamble section V.P.1. EPA notes as well that it is fully aware of, and has considered the latest performance for supercritical and ultra
- supercritical boiler performance. Id. This technology

forms part of the basis for the BSER determination. In addition, highly efficient SCPC with natural gas co
- firing is an alternative compliance pathway to achieve the standard of performance. The EPA has also carefull y evaluated the issue of individual plant energy requirements due to parasitic load, and found them to be reasonable. See preamble section V.O.3. **Comment 6.3 -**  **303:** Commenters 1959, 2864, 6870, 7433, 9194, 9317, 9320, 9396, 9422, 9425, 9678, 10082, 10083 and 10086 stated that CCS cannot be implemented in all parts o f the country , particularly

due to the availability

of storage sites. For example, Commenter 10083 discussed the large distances between western power plants and suitable geological for mations, and the potential for interconnectivity issues, environmental impacts, siting difficulties and project costs with increased distance.6
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Commenter 10083 also stated that while saline formations may be suitable, they

are not located near potential power plant locations and have not been characterized extensively . Commenter 8971 states that CCS selects winners and losers among states and areas. Commenter 9320 stated that EPA has failed to adequatel y consider the unique circumstances faced by sources in Florida with respect to the proposed standards for combined
- cycle comb ustion turbines. Similarly, Commenter 2864 stated that only five to eight states have the means to capture and use CO 2 . Commenter 9422 asserted that an EPA regulation should not disallow the construction of power plants in large sections of the country simply due to the geological makeup of those areas. Commenter 9396 provided an example of a DOE research project that assessed the ability store carbon in an aquifer and determined that the site was unsuitable and would have cost 1 million dollars per each of the 100 wells needed to secure the site. Similarly, Commenters 1902, 6870 and 9194 discussed the misalignment of the majority of power plants with EOR opportunities. Commenters 6870 and 10082 further noted that transporting large quantities of CO 2 is not easily addressed financiall y, technically or legall y. Commenter 10086 stated that EPA failed to account for the lack of transportation infrastructure and the environmental impact associated with developing a network of pipelines. Commenter 10393 noted the legal and regulatory challenges to long
- term sequestration. Commenter 10083 states that there are no planned projects in western states except for the HEC project in California. Commenter 10395 asserted that CCS will not be developed, even in areas with EOR and sequestration opportunities, until additional research dollars are invested to evaluate whether it is an available, effective, and commerciall y viable technology
. **Response 6.3 -**  **303:** See Section V.M. of the preamble with respect to geologic and geographic availabil ity , and V.N. of the preamble with respect to the legal and regulatory framework of GS. Potential GS formations are widel y available in the United States. The EPA recognizes that geologic conditions to support CO 2 storage may not exist in all regions of th e country . Where such capacity

is unavailable, electricity demand in those areas can be served by coal
- fired power plants built in neighboring areas with geologic availability with generated electricity being supplied via transmission line, see Figure 1 of TSD on geographic availability, or the CO 2 can be transported to available GS sites via pipeline. T he design, construction, operation, and safety requirements for CO 2 pipelines have been proven. For other of those areas, coal
- fired power plants are either not being built due to state law prohibitions against building such units, or other available compliance alternatives exist allowing a new coal
- fired power plant meeting the promulgated NSPS to be sited. There are alternative means of complying with the f inal standards of performance which do not necessitate use of partial CCS, so any siting difficulties based on lack of a CO 2 repository

would be obviated. **Comment 6.3 -**  **304:** Commenters 8966, 9597, and 10043 stated that the performance statistics of EPA
- cited facilities indic ates that CCS was installed on an extremel y small scale, and that the technology

itself is not effective at capturing carbon to levels necessary to comply

with the proposed standard. Commenter 8966 then discussed NETL data on Warrior Run, indicating that C CS only resulted in a 7 percent reduction and was still in excess of the proposed emission limit. Commenter 8966 also discussed Shady Point and Barry Plant's excess emissions even after6
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capture and the small scale of Mountaineer Plant's CCS, all of which i ndicate that CCS has not been demonstrated show adequate effectiveness and reliability to support a BSER determination. **Response 6.3 -**  **304:** S ee preamble sections V.D and V.E. Preamble section V. G.3 also explains why pilot scale performance of CCS can be scaled up, and further supports the EPA ’s determination that CCS is a demonstrated te chnology **. Comment 6.3**  **- 305:**  Similarly, Commenter 9666 stated that none of the material cited by EPA, most of which have utilized only portions of CCS technology , demonstrate that the emission levels can be met. **Response 6.3 -**  **305:** See preamble sections V.D and E. as well as preamble sections V.G.1 and 2. **Comment 6.3 -**  **306:** Commenter 9326 stated that the data that EPA relies upon is an insufficient sample size. The commenter also stated that EPA presumes all new coal fired EGUs will be IGCC and recommended that EPA use CCS performance data on PC fired units as opposed to IGCC. **Response 6.3 -**  **306:** The final BSER determination in fact is based on SCPC utilizing partial CCS. **Comment 6.3 -**  **307:** Commenter 9472 provided a list of reasons and references why CCS is not adequatel y d emonstrated by discussing how EPA's cited projects do not demonstrate integration of all CCS components and are not economicall y viable, and by citing references listing the costs per kilowatt hour and overall cost increase of CCS. The commenter further added that without second generation CCS, the technology is unlikely to be economicall y viable or commercially available. Similarly, Commenter 9194 stated that the pilot projects do not demonstrate that CCS is widely useable nor technicall y and economicall y feasible for all 50 states. Similarly, Commenter 8024 discussed the cost and energy penalties associated with the first generation captured technology , as reflected in the Carbon Sequestration Leadership Forum 2013 Roadmap. Commenter 8027 stated that high purity CO 2 capture may not be available for 5 to 10 ye ars and have not been adopted and validated. **Response 6.3 -**  **307:** See preamble sections V.D and V.E. Energy penalty issues are addressed in preamble section V.O.3. Although the EPA is not relying principall y on pilot sc ale performance to show that CCS is a demonstrated technology (comment 9194), that information is nonetheless probative and corroborative of the EPA’s determination. See preamble sections just cited. Commenter 8027 is completely mistaken that high purity CO 2 capture is not presently available. Food
- grade CO 2 has been recovered and utilized for over a decade. See preamble section V.D.2.b ( at the 320 MW Shady Point Plant, a plant that burns a blend of bituminous and subbituminous coals, CO 2 from an approx imate 5 percent slip
- stream (about 66,000 metric tons6
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of CO 2 per year) has been captured since 2001. The captured CO 2 from the Shady Point Plant is also sold for use in the food processing industry
. 61 ) **Comment 6.3 -**  **308:** Commenters (2470, 2 864, 3107, 3176, 3236, 4710, 4814, 8 024, 8906, 8971, 9196, 9396, 9397, 9401, 9472, 9661, 9683, 9767, 9780, 10046, 10082, 10086, 10098, 10294, 10391, 10518, 10618, 10952, 11051 and 11052) stated that CCS has not been adequatel y demonstrated in EGUs and is cost
- prohibitive. Commenter 10391 fur ther stated that "even if it were an adequatel y demonstrated technology, CCS is not remotely feasible and sustainable for coal
- fueled power plants in most of the states". Commenters (1899, 9396, 9661, 9683, 9780, 10086, 10098, 10618, 10662 and 10952) also stated is underdeveloped with respect to legal and logistical aspects of capture, shipping, and storing CO 2 . Commenters 9683, 9666 and 10096 also provided several quotes stating that CCS is not adequatel y demonstrated. Commenters 3107, 8906, 9196, 9320, 9 396, 9497, 9661, 10096, 10952, 11051 and 11052 asserted that the proposed rule is effectivel y a ban on new coal. Commenter 10046 stated that compulsory

CCS will not work, and cited a 2012 UKERC report stating that mandating CCS now will likely

shift investment to less risky power generation technologies, and that it will not be eas y to identify

when the time is right to mandate CCS. The report also states that "CCS should arguabl y appl y to existing plants too as climate change targets begin to bite". Commenter 9320 discussed Sierra Club v. Costle, which indicates that EPA may not establish standards that preclude the construction of new coal. **Response 6.3 -**  **308:** Recent assessments are at odds with these commenters’ assertions. See, e.g. Global CCS Institute, “The Costs of CCS and Other Low
- Carbon Technologies 2015 Update” (July 2015) 62 at p. 1: “ CCS is a cost competitive power sector emissions reduction tool when considered among the range of available low and zero emissions technologies ....Significant cost reduction are also expected for CCS technologies with increased deploy ment”. This conclusion reflects studies of Lazard (2014); EIA 2014; IPCC 2014; Brookings 2014; EPRI2013; IEA 2012; and NREL2015. **Comment 6.3 -**  **309:** Commenters 8923, 9780, 10095 and 10103 discussed the differences between the S ynthetic Natural Gas commercial
- scale Production Plant and an EGU (e.g., heating step, the catal ys ts and stream compositions). Commenters 9780 and 10095 stated that EPA has
61 Dooley, J. J., et al. (20 09). “An Assessment of the Commercial Availability of Carbon Dioxide Capture and Storage Technologies as of June 2009”. U.S. DOE, Pacific Northwest National Laboratory, under Contract DE
AC05
- 76RL01830. 62 Available at http://hub.globalccsinstitute.com/sites/default/files/publications/195008/costs
ccs - other
- low
- carbon
- technologies
- 2015 - update.pdf . A copy of the report is docketed as part of the administrative record as well.6
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provided no data to indicate the facility could continuously

achieve the proposed standards. Furthermore, Commenter 10095 asserted that EPA must ensure that the CO 2 is subpart RR compliant. Commenter 10395 further noted that a Sy nfuels plant does not demonstrate the viability or cost effectiveness of IGCC. **Response 6.3 -**  **309:** See preamble section V.E.2.a. High purity CO 2 has been captured successfull y using CCS. See, e.g. preamble section V.D.2.b. **Comment 6.3 -**  **310:** Commenter 9666 stated that EPA relies on a 2011 cost and performance report b y NETL that merely assumes the performance of various CCS configurations a nd is not supported by

any technical or statistical anal ys is of emissions data from units implementing CCS because no such data exist. **Response 6.3 -**  **310:** Costs for post
- combustion CCS reflect the most recent available vendor quotes for the Shell Cansolv compression and capture process – the process in use at the Boundary Dam facility
. **Comment 6.3 -**  **311:** Commenter 10665 cited the 2011 NETL Carbon Sequestration Program Plan stating that CCS will not be commercially viable until 2020. The commenter then stated that that if CCS is not commercial ly viable it cannot be considered for BACT. **Response 6.3 -**  **311:** This comment refers to a study evaluating full CCS , which is not BSER. **Comment 6.3 -**  **312:** Commenters 0588, 1902, 2864, 7977, 8024, 8925, 8949, 8966, 9033, 9034, 9191, 9197, 9326, 9381, 9382, 9425, 9426, 9596, 9602, 9666, 9648, 9 683, 9734, 9780, 10036, 10043, 10046, 10050, 10083, 10085, 10087, 10098, 10100, 10137, 10239, 10618, 10660 and 10880 also discussed how the plants and projects assessed b y EPA (e.g., TCEP, HECA, Kemper, NRG's project) are not operational yet or do not have operational data at the commercial scale for adequate demonstration. Commenter 8501 stated that the experimental and development projects underway do not support an adequate demonstration finding. However, Commenter 8925 stated that the individual process es of CCS have been demonstrated, some of which for significant time periods. Commenter 10618 discussed CCPI's initiative to accelerate development and minimize the cost of CCS and noted that none of the CCPIprojects have been completed, indicating that C CS is not yet adequatel y demonstrated. Commenter 9780 also discussed CCPIand concluded that if and when operational, these projects might demonstrate the technical feasibility of CCS, but would not address the commercial viability of the technology

given the significant funding that they have received as a result of their participation in the CCPIprogram. Similarly, Commenter 8024 stated that the few U.S. energy facilities that EPA uses to support its finding that CCS is adequatel y demonstrated are all i n various stages of construction, and all rely on government financial support. The commenter further stated that even the projects with federal aid are encountering difficulties with project financing and power sales. Commenter 10043 stated that EPA's ci ted projects are unique with respect to location and financial situation and do not demonstrate representativeness.6
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Commenter 9427 stated that none of the four projects cited by EPA in the preamble as a basis for BSER for a coal
- fired electric utility ste am generating unit (Kemper County Energy Facility , Sask Power Boundary

Dam Project, Texas Clean Energy Project, and Hydrogen Energy California) has produced any electricity , captured any

carbon dioxide, or sequestered any carbon dioxide, therefore, none of the four projects has "adequatel y demonstrated" the ability to meet any lb CO 2 /MWh emissions standard such as proposed and cannot serve as a basis for BSER. According to Commenter 9425, even if these units eventuall y become operational, several ye ars of operating experience would be required to support any conclusions about CCS, and projections b y several organizations and agencies do not expect CCS to be commercially available until about 2020. Commenters 8348, 9666, 9734, 9780 and 10137 also stated that ye ars of operation and research will be required before technologies can be fairly evaluated on a technical and economic basis with regard to uncertainty , representativeness and risk. Commenter 9201 stated that evaluating the feasibility of CCS for applic ability to the array of fuels and sites that ty pify dedicated power generation facilities in the U.S. will require at a minimum, operating data over several years from at least eight utility
- scale projects, similar to the process in which FGD and SCR sy ste ms were developed over numerous years and demonstration projects. Commenters 8348, 8949, 8966, 9034, 9381, 9382, 9648, 9666, 9734, 9780, 10046, 10098, 10239, 10618 and 10662 also stated that the proposed rule provides no information as to how pilot
- scale projects advanced the reliability , efficiency , cost, and commercialization of CCS and further, EPA has not taken the economic setbacks, cancellations or delay s encountered b y the projects into account. Similarly , Commenters 8971 and 9596 disagreed with extrapolating from pilot scale data to commercial scale regarding the use of CCS to a nationwide
- applicable CO 2 NSPS. Commenter 8024 cited CPS energy's press release on their decision to allow the TCEP power purchase agreement to expire as support for the economic realities of CCS. Commenter 10662 stated that all of the projects in the Global CCS Institute's database cited b y EPA have some element which eliminates it from consideration in the context of the proposed rule and discussed reasons for several of the projects. Commenter 9780 also added that many of EPA's cited projects separate CO 2 from other gases as part of normal operations which decreases the implementation cost and technical difficulty
. Commenter 10033 stated that while they do not believe the technology is not well understood at the scale required for commercial power plant implementation, the commenter does not wish to suggest that CCS cannot or should not go forward in an appropriate manner or that the process cannot be done safel y. Comme nters and 9596 and 9602 further added that no power plant currently utilizes geologic sequestration. Commenter 9596 stated that facilities which are not utility scale EGUs do not demonstrate CCS with geological sequestration. Commenter 9033 remarked that CCS has yet to reach demonstration stages to reduce the cost and reduce the risk of scaling these technologies from pilot or validation scale to full scale. The commenter presents several integration issues that have not been a ssessed at full scale, such as how the capture process turns down with generation load, how compression is affected b y reduced load, what the management practice for water and flue gas b yproducts will be, and risk6
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of shut down. Commenter 9033 further asserted that without full scale demonstration, the industry is not in a position to make proper commercial warranties and guarantees as required. **Response 6.3 -**  **312:** For discussion of wh y partial CCS is a demonstrated technology , see preamble sections V.D. and E. Commenter 106 18 noted that many of these plants receive, or have received government subsidies. The need for subsidies to support emerging energy s ys tems and new control technologies is not unusual. Each of the major types of energy used to generate electricity has be en or is currentl y being supported by some type of government subsidy such as tax benefits, loan guarantees, low
- cost leases, or direct expenditures for some aspect of development and utilization, ranging from exploration to control installation. This is true for fossil fuel
- fired, as well as nuclear
- , geothermal
- , wind
- , and solar
- generated electricity. Moreover, this issue does not relate to whether the technology is technicall y feasible and demonstrated. We further note that this same commenter publically stated that CCS represents a path forward to an energy future where coal continues to be a utilized fossil fuel (“AEP still believes the advancement of CCS is critical for the sustainability of coal
- fired generation.” 63 ). Issues relating to pilot plant performance are addressed in sections V.D. and V.E as well as V.G.3. Commenter 9596 is mistaken that there has been no geologic sequestration of CO 2 captured from an EGU. Boundary

Dam sequesters CO 2 it fails to sell for EOR, and the EPA has issued permits for Class VI wells for the FutureGen EGU facility , premised on findings that the facility ’s CO 2 emissions can be successfully captured, transported, and sequestered for geologic time frames. Regarding commercial guarantees for CCS, see preamble section V.F. Commenter 10662 states that international experience with CCS does not show that the technology

is demonstrated. The comment is mistaken both factually and legally . Section 111 (a) does not re strict EPA to data from domestic facilities only
. Boundary Dam, a full scale commercial facility operating full CCS successfully , thus is an appropriate facility to look to as showing that CCS is a demonstrated technology
. See Sierra Club v. Costle, 657 F. 2d at 364 ( support for achievability

of section 111 standard of performance comes, in part, from operation of Japanese sources using the BSER) ; Li gnite Energy Council v. EPA, 198 F. 3d at 394 n. 3 (section 111 (b) standard of performance justified in part based on data from “foreign boilers burning lignite”)
. Additional international facilities discussed in preamble section V.E.2.b provide corroborative information with respect to pre
combustion CCS (not the BSER but a potential alternative compliance p athway), and further indicate world
- wide interest in the technology , and willingness to invest in it. **Comment 6.3 -**  **313:** Commenter 9666 remarked that EPA has failed to identify and assess the impacts of conditions that could affect a unit's CO 2 emissions, such as differences in types of fuel combusted and load duty.
63 CCS LESSONS LEARNE D REPORT American Electric Power Mountaineer CCS II Project Phase 1, Prepared for The Global CCS Institute Project # PRO 004, January 23, 2012, page 2. See also AEP FEED Study at pp. 4, 63 (same).6
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**Response 6.3 -**  **313:** The EPA has carefully assessed both the performance of fossil
- fired EGUs using different types of coal, and the cost and energy implications when different coal types are used. See preamble section V.J. **Comment 6.3 -**  **314:** Comment er 9201 asserted that the lack of actual data from facilities in commercial operation has caused EPA not to adopt numerical standards. **Response 6.3 -**  **314:** The final standard of performance is a numerical level, as was the proposed standard of performance. **Comment 6.3 -**  **315:** Commenters 9472, 9 592 and 10952 asserted that the proposed BSER does not address the lack of available infrastructure needed to transport, sequester and monitor the CO 2 captured b y coal
- fired EGUs, such as CO 2 pipelines and deep well sequestration or EOR fields, and therefo re CCS cannot be considered a best "s ys tem" of emission reduction. Similarly , Commenter 9596 stated that EPA has not adequately demonstrated the transportation and sequestration components of CCS. Commenters 10952 and 10097 stated that it is unclear whether carbon sequestration or EOR is included as part of the s ystem that defines BSER or whether carbon capture fully comprehends the sy stem in BSER. **Response 6.3 -**  **315:** The transportation and storage of CO 2 is adequately demonstrated. See preamble section V.M., which discusses the existing processes, technologies, and geologic conditions that enable successful geologic sequestration and section V.N., which discusses the comprehensive, in
- place regulatory str ucture that is currentl y available to oversee GS projects and assure their safety

and effectiveness. The BSER determination and regulatory impact anal ys is for this rule relies on GS in deep saline formations. However, the EPA also recognizes the potential for sequestering CO 2 via EOR and allows the use of EOR as a compliance option. **Comment 6.3 -**  **316:** Commenter 8957 discussed the Boundary Dam project a FutureGen 2.0 and concluded that additional experience across a range of geologic formations and other site
specific conditio ns as well as additional information on cost is necessary to make a determination that CCS has been adequately demonstrated. Similarly , Commenter 10395 stated that Boundary Dam is not an IGCC project and does not support EPA's contention that IGCC with partial carbon capture is BSER for coal
- fired units. **Response 6.3 -**  **316:** In the United States, the EPA has issued Class VI UI C permits for six wells for two projects. EPA considered, among other information, information on the regional geology and local geologic features at each site as part of its permitting process to determine that the wells were appropriatel y sited and met the Class VI requirements. Additionally , there are several large scale CO 2 sequestration projects including the I llinois Basin Decatur Project and the Cran field (Tuscaloosa) Project that demonstrate that storage of large amounts of CO 2 can be achieved. In April 2015, DOE announced that CCS projects supported b y the department have safel y and permanentl y s tored 10 million metric tons of CO 2 , which is the same order of magnitude expected for an EGU. Furthermore, existing commercial CCS fac ilities in other countries demonstrate the commercial storage of CO 2 , and the ability to inject large quantities over long period of time. The CO 2 streams from these facilitie s have ph ys ical and chemical6
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characteristics similar to pipeline grade CO 2 that would be expected from an EGU so the source of the CO 2 is not a factor in assessing the feasibility of long term secure storage. Commenters 9190, 9201, 9425, 9381, 9426, 9497, 9590, 9648, 9666, 9725, 9780, 10036, 10046, 10085, 10095, 10036, 10500, 10552 and 10680 stated that to adequatel y demonstrate the national feasibility of CCS technology , all components of EGUs with CCS must be demonstrated to work together at the commercial scale due to the complexity and scope of the processes. **Comment 6.3 -**  **317:** Commenter 9683 stated that CCS is not a BSER as there is not nearl y enough experience with carbon capture at an appropriate scale and under the variety of circumstances necessary

to reasonabl y determine that capture technology is adequatel y demonstrated. Similarly , Commenters 8966, 9190, 9197, 9201, 9426, 9590, 9648, 9666, 9725, 9735, 9780, 10036, 10095 and 10036 stated that data from multiple integrated technology demonstrations using different co nditions and configurations at commercial scale are needed (e.g., using different power s ys tems, ranks of coal, different separation sy stems, locations and CO 2 storage in a range of geologic formations). Commenters 10036, 10095 and 10500 further asserted that no projects referenced b y the Agency are simultaneousl y producing electricity, capturing, cleaning, compressing, transporting, and storing large volumes of CO 2 on a continuous basis, which is essential to the effective operations of a commercial plant and adequate demonstration. Commenters 1899, 8024, 8966, 9320, 9381, 9596, 9666, 9780, 10032, 10500 and 10082 also stated that EPA has not considered the unique technical issues or reliability obligations of EGUs when assessing the technical feasibility of CCS. For example, Commenter 9596 stated that non
EGU's are able to vent CO 2 when it is not needed or accepted b y EOR and are not subject to load shift response requirements or continuous operations. Commenter 9317 stated their concern that the rule will impede states' energy diversity and reliability
. Commenter 9190, 10032, 10552, and 10680 further stated that the proposed standard is not based on actual data and does not demonstrate that the proposed standard is consistently ach ievable
. **Response 6.3 -**  **317:** See preamble sections V.D. and V .E. We repeat here the NETL ( July 2015) recent assessment of the technology (p. 36): “The capture and CO 2 compression technologies have commercial operating experience with demonstrated ability for high reliability .” **Comment 6.3 -**  **318:** Commenter 9666 further asserted that EPA has failed to engage in the necessary anal ys is to support a finding that a standard of 1,100 lb CO 2 /MWh is achievable for the industry

as a whole under the full range of relevant conditions. **Response 6.3 -**  **318:** Preamble section V.J. discusses wh y the standard is achievable under a range of variable operating conditions. **Comment 6.3 -**  **319:** Commenter 10098 stated that the natural gas industry's experience with CO 2 capture provides no basis for EPA's proposed conclusion in this rulemaking that partial CCS i s BSER.6
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**Response 6.3 -**  **319:** The EPA’s finding that partial CCS is part of the BSER (along with a highly efficient SCPC boiler) is based on operating experience involving combustion of coal, not NGCC. **Comment 6.3 -**  **320:** Similarly, Commenters 9381 , 9397, 9497, 9505, 10088, 10239, 10500 and 10662 stated that the unique characteristics that make Kemper the right choice for Mississippi cannot be consistently replicated on a national level and should not serve as a primary basis for new emissions standards impacting all new coal
- fired power plants. For example, Commenter 9497 noted that the gasifier technology used at Kemper does not work well for higher grade coals. Commenter 1959 noted that another reason Kemper is not BSER because Kemper is onl y commerciall y viable because of a suite of financial incentives and public subsidies that are not available for new projects, including revenues from sales of CO 2 at the plant for enhanced oil recovery which is not nationally

available. Commenters 1959, 8349, 9381, 9382, 9396, 9505, 9734, 10239 and 10662 al so discussed the cost increases, delay s and regulatory issues that have affected Kemper, as well as EPA's other cited facilities in construction or planning phase, such as Boundary Dam, FutureGen and TCEP. Commenter 8949 discussed the similarities between process units in Kemper and Pinon Pine, which shut down in 2000 due to technical problems. The commenter h ypothesized that similar challenges may

occur with Kemper because it is FOAK. Commenter 10662 stated that questions remain regarding long term storag e, venting CO 2 , and the source of the 65 percent capture target at Kemper. Commenters 9381 and 9396 also cited public statements from Alstom declaring that it does not consider CCS to be technically feasible at a commercial scale. Commenter 9396 also cite d public statements from Mississippi Sierra Club opposing the Kemper plant. Commenter 9382 also noted a mistake in the 2015 operations date listed b y EPA for the NRG Energy CCS project. **Response 6.3 -**  **320:** The EPA is not selecting IGCC as BSER, although IGCC with natural gas co - firing, or partial CCS, is an alternative compliance path. See preamble section V.P. Thus, Kemper is not directl y part of EPA’s primary support for the BSER determination. The EPA has also explained that the cost overruns involved with the project are the result of management decisions which are very

unlikely to be repeated elsewhere, since they involved decisions contrary to normal protocols. Regarding commenters’ claims that CCS technology is likely to operate with poor reliability , Boundary Dam is operating “highl y successfull y” (in the words of the project developers, see preamble section V.D.2), Dakota Gasification has operated full CCS successfully for decades, and NETL (2015) characterizes the technology as having high reliability based on co mmercial operating experience. Finally , in response to commenters 9381 and 9396, the EPA notes that Alstom has publically

endorsed CCS as a reliable and available technology. See preamble section V.F and V.I.2.c. See also statement of Alstom senior Vice President for Power and6
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Environment Policies Joa n M acnaughton’s statement (August 4, 2011): “ AEP’s decision to p ut Mountaineer II on
- hold (sic) is a bellwether to our leaders on the consequences of uncertain climate policy . The Validation Plant at Mountaineer demonstrated the ability to capture up to 90% of the carbo n dioxide from a stream of the plant’s emissions. The technology works. But without clear policies in place outlining options for cost recovery , power generators are hard
pressed to invest i n its continue d refinement.” The press release further states that Vice President Macnaughton “presented findings from a recently
- conducted cost anal ys is showing that the cost of electricity generated b y coal and natural gas plants equipped with CCS is co mpetitive with other low or n o - carbon energy carbon energy

sources, such as wind, solar, geothermal, h ydro and nu clear.” 64 **Comment 6.3 -**  **321:** Commenter 9666 also discussed the Boundary Dam project and stated that it is located outside the country and cannot serve as an example of adequate demonstration for United States
- based generators which face different operational and technical constraints because: it is not a project that a company would have taken in the normal course of commercial operations, it cannot be considered financially feasible, and it has encountered multiple delay s. Commenter 8024 discussed the total costs of the Boundary Dam project. **Response 6.3 -**  **321:** Boundary Dam is operating highl y successfully. Section 111 (a) contains no bar on the source of information EPA can c onsider in assessing which s ys tems of performance are adequatel y demonstrated. Further, the project cost overruns related solely to the cost of the boiler, not the CCS system. See Memorandum of conversation between Dr. Nick Hutson (EPA) and Mike Monea (S askPower), part of the administrative record for this final rule. **Comment 6.3 -**  **322:** Commenter 8966 stated that a BSER determination must rely on some wholly independent grounds apart from any data gathered from a publicl y s upported facility under the Energy

Policy Act. Th e commenter stated that in addition to Kemper County and Texas Clean Energy

Project not demonstrating actual effectiveness or reliability with operational data, data from these facilities must be excluded from consideration in a BSER determination due to their public funding. Similarly, Commenters 9034, 9497, 9774, 10083, 10662, 10974 and 10975 stated that EPA should not have considered the federall y funded facilities
. **Response 6.3 -**  **322:** EPA’s determination is not solely , or mainl y, premised on performance of facilities rec eiving funds under EPAct, and can be justified entirely without consideration of any such facility. **Comment 6.3 -**  **323:** Commenter 9515 stated that although the EPA's reading of the Energy Policy Act is reasonable, but will not insulate it from legal challenge. Instead, the commenter suggested that EPA reference projects with individual components of CCS and state the partial CCS can be demonstrated even in the absence of projects funded b y the Act through facilities

64 See http://www.alstom.com/Global/US/Resources/Documents/Press%20Releases/PR_JMacN_CCSbriefing_FINAL.pdf6
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such as Warrior Run, Shady Point, Searles Valley, Great Pl ains Sy nfuels and other international projects such as Sleipner and Schwarze. **Response 6.3 -**  **323:** See preamble sections V.D and V.E. **Comment 6.3 -**  **324:** Commenter 10095 stated that they are optimistic that CCS may play a role in reducing GHGs in the future, but integrated CCS technology is still in the development and demonstration phase and much remains to be understood. Commenters 9326 and 10095 asserted that by prematurel y requiring CCS, the proposed rule will hamper the technology's advancement. Commenters 9326 and 9497 asserted that the app lication of CCS to larger pulverized coal plants is not available or necessarily applicable with any reliability . Similarly , Commenter 8024 stated that four of the six projects cited by EPA utilize technologies not suited to pulverized coal. **Response 6.3 -**  **324:** See preamble section V.L. and V.I.4. CCS is demonstrated for PC plants, notably at Boundary

Dam #3. **Comment 6.3 -**  **325:** Commenter 10095 also remarked that neither Kemper County Energy Facility or Boundary

Dam CCS project will have completed even one full year of operation before EPA is statutoril y required to finalize the rule, which will not provide the robust experience required for CCS technologies to be considered Adequatel y Demonstrated nor full y satisfy the requirements of this proposal regarding subpart RR. **Response 6.3 -**  **325:** The commenter (Southern Company) correctl y states that Boundary Dam will not have completed a year of operation at the time of promulgation of the final standard. Nonetheless, plant performance to date has been highl y successful (in the words of the project developers), and CCS technology has operated reliably

in many other applications (see preamble section V.D and V.E). The EPA consequentl y believes it reasonable to rel y on the operating performance of Boundary Dam as an example of demonstration of post
- combustion CCS at comm ercial scale. **Comment 6.3 -**  **326:** Commenters 8966, 10046, 10870, 10088 and 10952 stated that EPA and/or DOE have not found CCS to be viable on a commercial scale in recent statements and reports. Commenter 8966 also cited CRS' statement that there is no data supporting the ef fectiveness and reliability of CCS sy stems and therefore CCS does not meet the level of demonstration required by CAA Section 111. Commenters 8024, 9396, 10395 and 10952 further noted that EPA's Task Force recognized that up to ten full scale demonstratio n projects at EGU sites were needed to commercialize carbon capture technology

and reduce costs from 80 percent, and endorsed a ten year timeline to complete needed commercialization. Commenters 9196, 9765 and 10662 cited the Task Force report and its conc lusions that CCS is not ready for widespread implementation and is not demonstrated at the EGU scale. Commenter 10395 questioned why EPA has departed from the Task Force milestones. Commenter 9396 further questioned how CCS can be NSPS if States have recently rejected it as6
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BACT. Commenter 9774 provided examples of a State rejecting CCS as BACT and cited feasibility and cost as the reasons. Commenter 8024 also cited the Task Force findings and the 2010 Guidance on BACT as evidence that CCS is not adequatel y demonstrated. **Response 6.3 -**  **326:** Inresponse to commenter 8966 et al, DOE’s latest published statement on CCS is that, based on commercial operating experience, it has “demonstrated ability for high reliability”. NETL ( July 2015) p. 36. **Comment 6.3 -**  **327:** Commenter 9515 noted that the Ta sk Force Report supports EPA's finding that there are no insurmountable technological barriers and provided support from a Pacific Northwest National Lab report that concluded that CCS is technically viable and deployed at large enough scales to support co mmercial development. **Response 6.3 -**  **327:** The EPA largel y agrees with this comment. **Comment 6.3 -**  **328:** However, Commenter 8024 cited the 2009 PNNL study's conclusions that CCS is technically

viable, but stated that the study does not address cost or energy requirements, nor does it conclude that full scale CCS has been installed and integrated at an EGU. The Commenter also cited the BACT guidance white paper's statement that full scale CCS has not been installed and integrated at an EGU. **Response 6.3 -**  **328:** See preamble section V.D. **Comment 6.3 -**  **329:** Commenters 9197, 9596 and 10395 noted that because no full scale plants with CCS are operational, it is not possible to consider the technology adequately demonstrated or ensure that the technical configurations meet the duty cycle demands of base load EGUs, such as reliability

and cost
. **Response 6.3 -**  **329:** See preamble section V.D. **Comment 6.3 -**  **330:** Commenter 9034 noted that although the SAB Work Group ultimately decided to withdraw its recommendation for further review, it encouraged EPA "to carefull y monitor the post
- rule reality to ensure that the technologies are feasib le and available to newl y constructed electricity generating units to meet the new standards." The commenter stated that the "post
- rule reality ," however, will show that CCS will remain infeasible and unavailable to coal
- fired EGUs for the foreseeable future. Commenter 9648 stated that their message is consistent with SAB's findings that the rulemaking would benefit from additional review. Commenter 9195 noted that the Science committee uncovered serious problems and unanswered questions with the scientifi c and technical assumptions supporting EPA's new power plant proposal when observing interactions between EPA and the SAB.6
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Commenter 9396 noted that the SAB has indicated that non
- EOR sequestration has not been peer reviewed or adequately demonstrated an d has requested an anal ys is. The commenter stated that without an anal ys is of non
- EOR sequestration, CCS cannot be designated as BSER. **Response 6.3 -**  **330:** See response in chapter 2 addressing comments relating to the Information Quality Act . The short of it is that these c ommenters are significantl y misinformed. First, the SAB was briefed in great detail on the Class VI rule as it was being developed. Second, the SAB workgroup in its January

7, 2014 public letter stated that “while the scientific and technical basis for c arbon storage provisions is new and emerging science, the agency is using the best available science and has conducted peer review at a level required b y agency guidance.” Letter p. 3. The full SAB endorsed this letter in their edits of Jan. 24, 2014. ( Commenter 9034 correctly notes that the SAB withdrew its recommendation for further review, but fails to note the Workgroup’s finding of use of best available science and adequate and ample peer review.) **Comment 6.3 -**  **331:** Commenters 8966, 9505, 9666, 9677, 10870 and 10088 also asserted that under the standard established in the case of Essex Chemical, CCS cannot be considered adequatel y demonstrated. Commenters 8966, 9497, 9666, 9677 and 9505 defined adequatel y demonstrated s ys tem as shown to be reasonabl y reliable, reasonab ly efficient, reasonabl y expected to serve the interests of pollution control without becoming exorbitantly costl y in an economic or environmental way (see Essex Chemical), all of which CCS has not validated. Similarly, Commenters 10089 asserted that CCS i s currentl y cost prohibitive and not demonstrated at the commercial scale EGUs. Commenter 10088 cited the cost issues with Kemper Plant as further evidence. Commenter 9677 stated that EPA does not cite any case law that supports deploying BSER in a source category that has never used the technology
. **Response 6.3 -**  **331:** A) The technology is demonstrated at full commercial scale, highl y successfull y. See preamble sections V.D.2 and V.E.2.a; B) In response to commenter 9677, performance of a control technology in another indus try

has long been recognized as a legitimate way to show that a technology is demonstrated. See, e.g. Lignite Energy Council , 198 F. 3d at 934. Inany

case , post - combustion CCS is demonstrated within the source category ; C) the technology

is not exorbitantly

costl y, and does not have collateral nonair quality environmental or health impacts. See preamble section V.H and V.O. The BSER determination here the refore satisfies the standard set forth in Essex and other opinions of the D.C. Circuit. **Comment 6.3 -**  **332:** Commenters 9401, 9774, 10036, 10095, 10098, 10239 and 10952 stated that CCS cannot be NSPS if it has never been selected as BACT. Commenters 10239 and 10098 also discu ssed the BACT selection process which, the commenters asserted, accuratel y rejects CCS as BACT due to technical and economic feasibility considerations. Similarly, Commenters 7977, 9401, 9683, 10239, 10030 and 10662 noted that EPA's previously proposed ru le on the same subject in 2012 did not consider CCS to be an "adequatel y demonstrated" and that there is not sufficient support to warrant a change. Commenters 9401, 9683 and 10239 technology therefore asserted that CCS as BSER is arbitrary and capricious. Commenter 9472 asserted that the current proposal is at odds with EPA's 2012 rulemaking proposal, which is still relevant because there are still no operating facilities or advancements in CCS.6
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C ommenter 10083 discussed BACT limits and stated that since NSPS sets the floor for BACT and BACT has recently

only required relativel y inexpensive, small reductions in CO 2 , NSPS 'would be limited to requiring very modest emission limits not more stringent than previousl y adopted BACT'. Commenter 9773 posited that if an NSPS more stringent than would be determined under BACT for the same source does not appear to be the intent of the CAA, why would there be a BACT program under the CAA? Commenter 10662 also stated that the following EPA statement, 'this proposal doe s not have any direct applicability on the determination of Best Available Control Technology (BACT) for existing EGUs that require PSD permits to authorize a major modification of the EGU' directly contradicts EPA's determination that BACT can be no less stringent than NSPS. **Response 6.3 -**  **332:** Comments regarding the relationship of individual BACT determinations and the standard of performance adopted in the final rule are at preamble section XII.C. Commenter 10062 misconstrues EPA’s statements: a final standard of perfor mance creates a BACT floor, but a proposal does not, as the EPA accuratel y stated. Commenter 9773 that BACT determinations for the same source would be less stringent than the proposed NSPS, showing that an NSPS based on CCS is arbitrary . There have been no such BACT determinations made by the EPA, or b y states. The closest example would be the (now discontinued) Wolverine project in Michigan, but the EAP proposed that this facility would not be subject to the proposed NSPS. With regard to the 2012 (with drawn) proposal (commenter 7977 et al.), the EPA stated that “CCS is a feasible technology option for new coal
- fired power plants because CCS is technically feasible and sufficientl y available in light of the limited amount of new coal
- fired construction e xpected in the foreseeable future.” 77 FR at 22414. Commenters 7977 et al. consequentl y do not accuratel y characterize that proposal, which in any case, has been overtaken b y events, including the re
- proposal , plus full scale successful operation of CCS at commercial scale
. **Comment 6.3 -**  **333:** Commenters 9683, 10086, 10087 and 10391 cited Portland Cement Ass'n v. Ruckelshaus and stated that EPA has not demonstrated that CCS is available for installation or at a reasonable cost. Commenter 10391 also stated that the proposed rule oversteps the Congressional intent of the NSPS. Similarly, Commenter 10870 cited Portland Cement Ass'n v. Ruckelshaus and Sierra Club v. Costle when stating that EPA must evaluate the "demonstration of commercial
- scale s ys tems". Commenters 9596 and 1 0046 cited the District of Columbia Circuit's Sierra Club decision that rejected dry

scrubbing as an adequatel y demonstrated technology and noted that this proposed rule is similar (or less robust) due to the lack of commercial scale operating data. Comme nter 10087 also cited National L ime Association v. EPA, finding that EPA must consider "the representativeness for the industry as a whole of the tested plants on which it relies.6
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Commenter 8024 cited Lignite Energy Council v. EPA in stating that EPA may n ot rely on unbuilt facilities or conjecture to document adequate demonstration. **Response 6.3 -**  **333:** See preamble sections V.D (demonstration of post
- combustion CCS), V.H and V.I (availability

of BSER at reasonable cost), and V.G.1 and 2, noting how the standard of performanc e is consistent with applicable caselaw, including Portland Cement I , and Lignite Energy Council
. **Comment 6.3 -**  **334:** Commenters 9514, 9660, 9664 and 10108 provided projects (e.g., Warrior Run, Plant Barry , a North Dakota gasification facility, Coffey ville gasification, and a 200 mile pipeline for EOR in Canada), vendor statements, reports (e.g., DOE/NETL reports) and articles for the Agency

as support for its final standards that EPA that integrated CCS is adequately demonstrated, that EPA amply established integrated CCS sys tems will be available for commercial application on coal
- fired power plants, and that the component elements of these sy stems have been in long
- standing use in other similar industrial applications in the U.S. and abroad. Commenter 10108 further stated th at the evidence is considerable more extensive than past NSPS, such as the SO2 BSER and supports EPA's determination. Commenter 10869 also stated that the component elements are commercially in use. Commenter 9660 cited the Global Carbon Capture and Storag e Institute 2014 report as further support. Commenter 9664 further stated that CCS is necessary in order to control anthropogenic CO 2 in a timely

enough manner so as to avoid the worst climate impacts. **Response 6.3 -**  **334:** The EPA largel y agrees with this comment. The EPA al so notes that the Global CCS Inst report (2015, the successor to the version cited b y the commenter) finds that “CCS is a cost competitive power sector emissions reduction tool when considered among the range of available low and zero emissions technologie s” (p. 1), and provides L COE estimates using a common methodological framework which are consistent with those of other recognized expert entities with respect of cost of full CCS and cost of nuclear power. The study also presents estimates for the variou s technologies, including nuclear, as a range, again consistent with the approach of other entities. See preamble section V.I.2. b through e. **Comment 6.3 -**  **335:** Commenter 9514 provided a list of CCS projects using pre
- combustion and post - combustion technology at commercial scale for decades in other applications. Commenter 9660 discussed pre
- combustion, post
- combustion and ox yfuel combustion technologies that have been implemented and stated that EPA has correctly determined that CCS is a feasible compliance alternative with a 30 year averaging period. Commenter 9660 also cited literature and projects which demonstrate separation, capture and s torage of CO 2 , such as Sleipner , In Salah, Wey

burn, Il linois Industrial Capture and Lost Cabin projects. **Response 6.3 -**  **335:** The EPA agrees with much of this comment, although noting that pre
combustion CCS is not part of the BSER and that the final standard of performance does not have a 30
- ye ar compliance averaging period. **Comment 6.3 -**  **336:** Commenters 10048 and 10095 stated that the high cost of the CCS technology

effectivel y precludes its deplo ym ent even if the outstanding technical limitations, such as a lack of integrated, commercial scale demonstration, could be addressed and the6
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technolo gy

was ready

for commercial deploy

ment. Commenter 10048 noted that the 2013 NETL report acknowledged that CCS is not ready for implementation at coal
- fired power plants. Commenter 10095 also stated that a CO 2 emission limit based on this technology is not achievable as required under Section 111(b). **Response 6.3 -**  **336:** See preamble V.H. and L. See also statement of American Electric Power that CCS can be coal’s means of perpetuation (“AEP still believes the advancement of CCS is critical for the sustainability of coal
- fired generation” 65 ). The NETL (2013) report was not in the context of partial CCS, and in any case, NETL (2015) finds that CCS is highl y reliable based on its record in commercial application. **Comment 6.3 -**  **337:** Similarly, Commenters 9034, 9765 and 10396 cited a 2013 OMB comment questioning EPA's finding that CCS is adequatel y demonstrated based on projects yet to operate. Commenter 10294 stated that EPA's disregard for the OMB is troublesome. **Response 6.3 -**  **337:** The final standard of performance reflected interagency review pursuant to EO 12866. **Comment 6.3 -**  **338:** Commenter 10039 asserted that EPA's proposal that the CCS BSER is undercut b y the recent release of the Climate Change Report which describes CCS as not ready for widespread use. Commenters 9196, 9396, 9472, 10087 and 10095 stated that the recent National Cl imate Assessment confirms that CCS is presentl y in the pilot/demonstration phases of operational hierarchy **Response 6.3 -**  **338:** This report concerned full CCS, and also considered application to existing sources. EPA has determined that full CCS is not the BSER for either ne w or existing sources. **Comment 6.3 -**  **339:** Conversel y, Commenters 9514 and 9664 stated that the public comments asserting that the NCA report questions whether CCS is ready to be deployed do not address or contradict anything on which EPA bases its BSER determination. **Response 6.3 -**  **339:** The EPA agrees with these comments insofar as the reports concern full CCS and the BSER determination is based on partial CCS. **Comment 6.3 -**  **340:** Commenter 10046 cited the 2012 IEA report entitled 'A Policy Strategy for Carbon Capture and Storage' to state that CCS is not currently cost effective or technically mature, and should be incentivized rather than mandated. **Response 6.3 -**  **340:** NETL(2015) states (p. 36) that, based on commercial operating experience, CCS has “demonstrated ability for high reliability.” Global CCS Institute (2015), in a c ompilation of expert views and anal ys es, states that “CCS is a cost competitive power sector emissions reduction tool when considered among the range of available low and zero emissions

65 CCS LESSONS LEARNED REPORT American Elec tric Power Mountaineer CCS II Project Phase 1, Prepared for The Global CCS Institute Project # PRO 004, January 23, 2012, page 2. See also AEP FEED Study at pp. 4, 63 (same).6
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technologies” (p. 1). See also preamble section V.F (vendor guarantee s) and V.I.2 (reliability of NETLcost estimates). **Comment 6.3 -**  **341:** Commenters 9514 and 9664 asserted that EPA is well within its authority to set standards that are technology
- forcing, forward looking, and in the interests of long
- term environmental benefit. The commenter s stated that EPA is not constrained to establish new source emissions limits based on s ys tems of emission reduction that are in "widespread use" (see Essex Chemical, 486 F.2d at 427
- 434 and Nat'l Asphalt Pavement Ass'n v. Train, 539 F.2d 775, 786. **Response 6.3 -**  **341:** The EAP largel y agrees with this comment. **Comment 6.3 -**  **342:** Commenter 9660 cited Lignite Energy Council v. EPA, 198 F.3d 930, 933
- 34 (D.C. Cir. 1990) and Weyerhaeuser Co. v. Cos t le, 590 F.2d 1011, 1054 n.70 (D.C. Cir. 1978) to support EPA's rule and state that EPA's reliance on the successful implementation of various components of CCS at a small scale is consistent with previous NSPS. The commenter also stated that adopting CCS as BSER encourages further development and implementation of the control technology

as Section 111b intends. **Response 6.3 -**  **342:** The EPA largel y agrees with this comment. **Comment 6.3 -**  **343:** Commenter 9514 stated that they support EPA's conclusion that geologic sequestration of CO 2 is available and adequatel y demonstrated for the purpose of establishing CCS as BSER for coal
- fired EGUs and agree that site characterization of each potential storage site is essential to ensure safe and permanent storage. Similarl y, Commenter 10106 agreed with EPA's conclusion that CCS is BSER and technically proven. Commenter 9513 also agreed with EPA's conclusion and stated that technologies demonstrated in the oil and gas sector are transferable, as supported by the Joint Environmental Group comments. **Response 6.3 -**  **343:** The EAP largel y agrees with this comment. **Comment 6.3 -**  **344:** Commenters 9471 and 9666 stated that they do not believe CCS will become commerciall y available for full
- scale application to EGUs in 7 years and therefore, the proposed BSER is incorrect. Similarly , Commenter 2864 stated that it will be five to ten years before the technology

is commercially

available and cost
- effective. The commenter stated that once facilities are operational, cost and feasibility can be evaluated. Commenter 9196 cited a DOE report that stated that CCS is 20 years away from commerciall y availability. Commenter 9666 also listed Alstom, Congressional Research Service, U.K. Ministry for Energy and Climate Change, International Energy Agency, and DOE as entities that have stated it will take until at least 2020 to determine if CCS is commerciall y proven and a technology deemed "best s ys tem of emission reduction" of CO 2 is shared by other governmental and regulatory agencies. **Response 6.3 -**  **344:** These commenters are referring to full CCS being available as a retrofit technology . The BSER determination for new sources involves neither of these. With regard to Alstom, the E PA notes A lstom’s public statements that CCS works, that it is cost effective, and6
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also notes that Alstom has provided public cost estimates for CCS consistent with those of NETL . See preamble sections V.F.3 and V.I.2.c. See also statement of Alstom senior Vice Pre sident for Power and Environment Policies Joan Macnaughton’s statement (August 4, 2011): “AEP’s decision to put Mountaineer II on
- hold (sic) is a bellwether to our leaders on the consequences of uncertain climate policy . The Validation Plant at Mountaineer demonstrated the ability

to capture up to 90% of the carbon dioxide from a stream of the plant’s emissions. The technology

works. But without clear policies in place outlining options for cost recovery , power generators are hard
- pressed to invest in it s continued refinement.” The press release further states that Vice President Macnaughton “presented findings from a recentl y- conducted cost anal ys is showing that the cost of electricity generated by

coal and natural gas plants equipped with CCS is compet itive with other low or no
- carbon energy carbon energy

sources, such as wind, solar, geothermal, hydro and nuclear.” 66 **Comment 6.3 -**  **345:** Commenter 10085 proposed that EPA rel y on subsequent statutory reviews of the final rule to determine when CCS becomes adequatel y demons trated and ready to incorporate into NSPS. **Response 6.3 -**  **345:** The EPA has reasonabl y determined that partial CCS, with a highly efficient SCPC, is BSER now. **Comment 6.3 -**  **346:** Commenter 9666 stated that a facility in the planning or construction stages provides no evidence that CCS can operate reliably or efficiently , no accurate evidence regarding the cost as costs may

continue to rise substantially until construction is complete, and no guarantee that it will reach completion and become operational. **Response 6.3 -**  **346:** See preamble sections V.D and V.E explaining operating facilities show that CCS is a demonstrated, effective, and reliable technology
. **Comment 6.3 -**  **347:** Commenter 10095 stated that pre
- and post
- combustion CCS demonstration projects are technologically different, are not interchangeable, not demonstrated at the commercial scale, and thus, cannot be comingled to justify partial CCS as being Adequatel y Demonstrated. The commenter further asserted that EPA cannot claim an emission standard based on partial CCS provides equivalent levels of operational and design flexibility without properl y analyzing the potential for pre
- and post
- combustion CCS applications because the flexibility, if any , will clearly be different. **Response 6.3 -**  **347:** The EPA is considering post
- and pre
- combustion CCS independently , and also assessing costs of ea ch independentl y. See preamble sections V.D. and E. and V.H.4., 5. And 7. **Comment 6.3 -**  **348:** Commenter 9666 remarked that EPA's onl y achievability anal ys is is based on its estimates of CCS performance using pre
- combustion CO 2 separation technology , which can be implemented onl y at IGCC units. Therefore, the commenter stated that EPA has not demonstrated that the proposed NSPS is achievable for units firing PC.
66 See http://www.alstom.com/Global/US/Resources/Documents/Press%20Releases/PR_JMacN_CCSbriefing_FINAL.pdf6
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Similarly, Commenter 9486 stated that EPA's examples only include coal gasification facilities, not standard coal fi red plants. **Response 6.3 -**  **348:** See preamble section V.J. **Comment 6.3 -**  **349:** Commenter 9666 discussed the difference between commerciall y availability

and commercially

proven, and stated that the evolution of a control technology from FOAK to NOAK is unchartered and includes significant econo mic and technological risks. Similarly, Commenter 9597 stated that because no one has experience designing, installing and operating an EGU with CCS, the risks will be too great to build a new coal plant. Commenter 9426 further commented that there are sev eral typ es of capture s ys tems, each of which must go through FOAK before reaching NOAK costs. **Response 6.3 -**  **349:** Post
- combustion CCS is successfull y demonstrated at the Boundary Dam facility . Vendors are actively promoting the technology , using cost estimates consistent wi th those estimated here. See preamble sections V.F. and V.I.2.b. **Comment 6.3 -**  **350:** Commenter 9593 stated that EPA's proposal ignores the difference between showing that a control technology is adequatel y demonstrated and establishing an associated emission limit that is achievable. The commenter noted that EPA is proposing partial CCS as BSER despite the successful deploy ment on an EGU in a full scale operation, and EPA's reliance on case law to support this determination ignores that the cases that have reviewed past NSP S standards have not involved a BSER determination that had not been deployed at all on operating sources in the source category
. **Response 6.3 -**  **350:** CCS is deployed on operating facilities. The commenter is mistaken as a matter of law that a BSER must be deployed on all operating sources, which would indeed defeat the whole purpose of a new source standard which is to reflect best s ys tem of emission reduction, not some ty

pe of least common denominator. Commenter 0775 noted that one of the five planned coal plants listed in the EIA database does include CCS, but that project, Medicine Bow Fuel & Power LLC, is not a power plant and may not need post
- combustion CCS in order to capture and store its carbon emissions. A source which is not a power plant is not an affected EGU, and so is not subject to the promulgated NSPS. **Comment 6.3 -**  **351:** Commenter 9396 stated that EPA is imposing a requirement that dictates the combustion and control technology , which would generall y be collaborative decided b y State public utility

commissions, municipal utility commissions, and cooperative boards and asso ciated electric utilities, through the Integrated Resource Planning (IRP) process taking into account local conditions and multiple factors to make the critical choices of what ty pe of plant to build and what fuel to use. **Response 6.3 -**  **351:** The EPA is not requiring sources to use a particular technology , nor does the final standard of performance force use of a particular technology . There are a variety of potential compliance alternatives available, including IGCC with natural gas co
- firing, and SCPC with natural gas co
- fi ring.6
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**Comment 6.3 -**  **352:** Commenter 9195 provided the following list of questions for EPA: a. Are any of these 12 projects a full
- scale, base
- load electric power plant? b. Do an y of these 12 projects currently have a final Class VIwell permit? c. For each of these 12 project s, please provide: A general description of the project, its location, and the electric generating capacity of the project, and the specific type of fuel the project uses; The approximate date any planning initially began for the project or a previous iteration of the project; The current status of the project, Estimated completion date of the project; Planned operating life of the project.; A technical description of the capture technologies, including detailed disclosure of any chemicals used in these s ys tems; Documentation of any commercial guarantees for capture technologies used in conjunction with any projects receiving federal funding; Volume of C02 currentl y captured; the annual volume of C02 anticipated to be captured when fully operational; and the total volume of C02 anticipated to be captured over the lifetime of the project; Explain where, how, and under what regulatory and reporting s ys tems the C02 will be stored; The total federal, state, or municipal financial assistance the project has receiv ed or anticipates obtaining. Please include any grants, tax incentives, loan grantees, or rate recovery mechanisms; Explain the parasitic load factor of the entire carbon capture, compression, transport, and storage s ys tem. Explain how this impacts the ef ficiency of the project as compared to the project without CCS; Explain how the project foot print is impacted by the CCS system; Provide the percentage of the overall cost of the project that is predominately related to the CCS portion of the project; Li s t any objections made to the project b y any stakeholders, environmental groups, NGOs, or other individuals. Provide petitions for any challenges or objections that are currentl y pending. For any objections that have been resolved, provide concessions or alterations made that allowed the project to move forward. d. isn't there a difference between demonstrating the components of CCS and demonstrating CCS as a fully

integrated sy stem? e. How does EPA explain these apparent inconsistencies between EPA's findi ng and EPA
- cited and co
- draft studies? f. Please identify

all: Post
- combustion coal projects EPA has cited or is aware of; Post
- combustion natural gas projects EPA has cited or is aware of; Pre
- combustion CCS projects currently capturing and storing C02 at coal power plants that EPA has cited or is aware of; Pre
- combustion CCS projects currently capturing and storing C02 at natural gas power plants that EPA has cited or is aware of; CCS power plant projects proposed or under construction that EPA has cited or is aware of; Other non - power generation CCS projects currentl y capturing and storing C02 at the same scale that would be required in the power generation context
- at least 1,000,000 tons C02 per year. How long has any such project been continuously cap turing, injecting, and monitoring at this scale? What legal and regulatory s ys tems are any such projects operating under?6
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**Response 6.3 -**  **352:** See preamble sections V.D. and V.E. The EPA has issued six class VI permits to date, to Archer Daniels Midland and FutureGen. Issu es of parasitic load are addressed in preamble section V.O.3. **Comment 6.3 -**  **353:** Commenter 8024 stated that, to date, Congress has not authorized programs to accelerate the large
- scale commercial demonstration of CCS technologies beyond the relativel y modest programs funded through the Office of Fossil Energy at the U.S. Department of Energy and as a result CCS has not adequatel y demonstrated. **Response 6.3 -**  **353:** See preamble sections V.D. and V.E. **Comment 6.3 -**  **354:** Commenter 9194 noted that every proposed NSPS, except for this NSPS, had vendor performance guarantees at the time of the proposal. Commenter 10046 also discussed the absence of vendor guarantees as an indication that CCS is not adequatel y demonstrated. **Response 6.3 -**  **354:** There are in fact vendor guarantees for CCS. See preamble section V.F. **Promotion of Technologica l Development**  **Comment 6.3 -**  **355:** Commenters 7977, 10098, 10618 stated that EPA mischaracterizes and overstates the technology
- forcing nature of the NSPS provisions. According to commenters 10098, 10239, because CCS remains an emerging technology that cannot be effectivel y implemented today , EPA cannot require its use in coal
- fired EGUs because the NSPS is effective upon proposal and not at some later undeterminable date when technological advances may occur. Commenter 7977 stated that the proposed rule sets a standard which forces the use of an experimental, currentl y i nfeasible technology , a factor that is not implicit in Section 111(b) of the CAA or explicit within the statute. The commenter stated that the proposed rule, which relies upon technology

forcing to justify

the proposed standard, exceeds relevant authority
. Commenter 10239 stated that nothing in section 111 or the EPA's implementing regulations mandates that the EPA must consider whether the sy stem promotes the implementation and further development of technology
. **Response 6.3 -**  **355:** See preamble section III. H.3.d and responses on this issue in chapter 2 of this RTC. **Comment 6.3 -**  **356:** Commenters 1624, 9033, 9196, 9426, 9666, 9683, 9780, 10046, 10098, 10100, 10239, 10618, 10662 stated that the proposal will impede or stop CCS development. Commenters 91 96, 9426, 9683, 10046, 10098 stated EPA's reliance on CCS in the proposed rule is likely to impede, rather than promote, the development of CCS technology because it will have the practical effect of preventing any new coal
- fired EGUs from being built. Ac cording to commenters 9033, 9196, without new coal plants, it is unlikely technology developers will continue to invest in CCS development. The commenters noted that with6
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decreased coal, there will be decreased R&D and investment into CCS technology
. Comme nter 9033 cites the slowing pace of private and public investment world
- wide in CCS projects as shown in the annual survey of the Global Capture and Storage Institute. Commenters 9196, 10100 stated that increased costs associated with CCS for coal
- fired EGUs and resulting increased electricity

prices from such units would yield few, if any, merchant power companies or regulated electric utilities that are likel y to invest in a new coal
- fired power plant with CCS and as a result, CCS technology will not be d eveloped, refined or improved so as to make it technologically

or economically

viable. Commenter 9780 stated that given current market realities, the key

for driving CCS technology development at this point is not a regulatory requirement, but rather gover nment financial assistance. The commenter concluded that without substantial federal financial assistance, no additional CCS projects on coal
- based EGUs are expected to be built in the U.S., and, as a result, there will be no further CCS development. Comme nter 9666 stated that EPA's proposed NSPS will have the opposite effect (to promoting technological development) by foreclosing further CCS demonstration projects at commercial power plants. According to the commenter, a standard that requires all new coal
- fired units to operate CCS cannot promote CCS if it simultaneously prevents the construction of any new coal
fired units, as EPA's proposed standard does. Commenters 9196, 9780 also stated that beyond the exorbitant costs of CCS, requiring new Subpart Da sources to use unproven technology to meet an unachievable emission limit with significant penalties for noncompliance will only discourage investment in these units. **Response 6.3 -**  **356:** See preamble section V. I.4 . We again note that AEP took exactly the opposite position in its earlier public statements on this issue , as did Alstom
. **Comment 6.3 -**  **357:** Commenter 10100 stated that the proposal will encourage the export of coal to China and other developing nations without creating incentives for commercialization of CCS to control coal
- fired CO 2 emissions. **Response 6.3 -**  **357:** See preamble section V.I.4. **Comment 6.3 -**  **358:** Commenter 9664 stated that the additional costs associated with moving the technology

forward are justified and reasonable. The commenter cited the RIA noting that sequestration costs can be defrayed with the rev enue of captured CO 2 to EOR operations. According to the commenter, , it is relevant to the technology
- forcing and forward looking aspects of section 111 standard
- setting that the costs associated with CCS technology applications are expected to decrease o ver time. **Response 6.3 -**  **358:** The EPA largel y agrees with these comments, although we note that costs of the standard of performance are reasonable even if those costs are not defrayed by a facility utilizing EOR opportunities. **Comment 6.3 -**  **359:** Commenters 9664 and 10108 cited Sierra Club v. Costle 657 F.2d at 341, 346
- 47 and S. Rep. No. 91
- 1196 (1970) at *16 noting that EPA can, and to be consistent with Congressional intent, must encourage emerging technologies through the form and structure of this standard. Commenter 10108 agrees with EPA' s conclusion that the proposed NSPS will advance these goals b y identifying CCS as BSER for coal
- fired power plants, lowering the cost of the technology

through learning
- by
- doing and encouraging further research and development6
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by DOE/NETL, referencing Sas kPower's investment in the Boundary Dam project that appears to be driven in part b y Canadian carbon pollution standards for new and existing power plants. **Response 6.3 -**  **359:** See preamble section III.H.5.d. **Comment 6.3 -**  **360:** Commenter 9514 stated that NSPS standards must be forward
- looking and technology
- forcing. Referencing Portland Cement Ass'n, 486 F.2d at 391 and Essex Chem. Corp., 486 F.2d 427, the commenter stated that the "best sy stem of emission reduction" need not be in actual commercial use in the regulated industry at the time th e standards are initially set. **Response 6.3 -**  **360:** The EPA largel y agrees with this comment. **Comment 6.3 -**  **361:** Commenter 8925 stated that by requiring CCS, the proposed rule raises the hurdle substantially

for companies interested in developing innovative coal technologies such as IGCC plants. The commenter noted that with significantly lower incremental costs of capture and lower heat rate penalties than pulverized coal plants, I GCC has been viewed as one key pathway forward on CCS, but there are onl y a few operating IGCC plants in the worl d so there is still much to learn about it. According to the commenter, experience
- based cost and performance improvements for IGCC will not be possible under the proposed regulation without incurring the additional cost, time, effort and risk of deplo yi ng CCS. **Response 6.3 -**  **361:** The standard of performance does not require use of CCS or any other technology . We specifically note that IGCC with natural gas co
- firing is a potential alternative compliance pathway . The EPA consequentl y does not agree with this comment. **Comment 6.3 -**  **362:** Commenters 9497, 10664 stated that the EPA's intention to promote CCS through the proposed rule goes counter to objectives and is a disincentive for the development of other technologies. Commenter 10664 stated that Congress did not seek to promote one technolog y over all others, and cited congressional testimony regarding the topic. Commenter 10239 stated that alternative control technologies are dismissed because they do not promote the development of CCS, which the commenter described as arbitrary , capricious , and unlawful for sev eral reasons. **Response 6.3 -**  **362:** The final standard of performance can be met by any means of a source’s choice, and there are alternative compliance pathway s that do not involve use of CCS. **Comment 6.3 -**  **363:** Commenters 9408, 9657 stated their concern that this rulemakin g may become an insurmountable barrier to the prospective construction and operation of new coal
fired electric generation units, thereby compromising a desirable level of energy supply diversity in our nation and in our community . The commenters stated th eir lack of support for policies that mandate fuel switching, directly or indirectl y, should be promulgated as a reasonable means of complying with an emission standard. Commenter 9426 stated that it is unlikely that electric generators would choose unpro ven CCS technology

if a less risky alternative in NGCC is available. The commenter stated that it is6
- 230

difficult to understand how the proposal would somehow cause generators to pursue coal with CCS over NGCC **Response 6.3 -**  **363:** See preamble section V. I.4. **Comment 6.3 -**  **364:** Commenter 9201 stated that EPA's rule does not incentivize technology and EPA's rationale is flawed. The commenter stated that there is no incentive to develop CCS, and additionally

creates a disincentive b y inducing construction of NGCC units that are not burdened with the co sts and technological uncertainties associated with CCS. According to the commenter, the proposed rule does not induce better performance from NGCC and the standard is substantially

higher than what can be achieved with the best existing technology . The co mmenter noted that they

are not suggesting EPA mandate CCS for NGCC units, but simply pointing out inherent contradiction between the agency's reasoning for setting a standard for new coal plants based upon CCS and the standard for NGCC units. The commenter provided the analogy to DOE's incentive example for lightbulbs in which EPA would in effect be requiring certain manufacturers of light bulbs to become more efficient while exempting others. The commenter concluded that EPA's reasoning is an arbitrary de cision and does not satisfy the legal requirements of CAA section 111. **Response 6.3 -**  **364:** See preamble section V.L. and V.I.4. **Comment 6.3 -**  **365:** Commenters 9666, 10662 stated that any CCS
- based standard unlawfully dictates the choice of technology that Subpart Da sources must use. Accordin g to commenter 9666, this violates section 111(b)(5) of the Act, which provides that nothing under section 111 shall be construed "to authorize the Administrator to require any new or modified source to install and operate any particular technological s ys t em of continuous emission reduction to comply with an y new source standard of performance." The commenter noted that the proposed NSPS for Subpart Da sources could not be met with any thing other than CCS. Commenter 10662 stated that under CAA Section 111(b )(1)(B)(5), EPA cannot require any particular s ys tem of continuous emission reduction. **Response 6.3 -**  **365:** The commenters are mistaken. The final standard of performance is a numerical limit which can be met by any means a source chooses. The EPA has further shown that there are alternative compliance pathway s available which do not need to utilize CCS, which compliance pathway s are also demonstrated, available at reasonable cost, and do not have collateral adverse environmental or energy utilization impacts. **Comment 6.3 -**  **366:** Commenters 966 6, 10662 stated that EPA cannot use section 111 to mandate the use of unproven control sy stems under the guise of "promoting technological development." Commenter 10046 stated that it is unlikely that Congress provided discretion in section 111(b) for E PA to impose a mandate that would retard development of the technology that EPA is trying to force.6
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**Response 6.3 -**  **366:** See preamble section III.H.5.d. and other comment responses in RTC 2 on this issue. **Comment 6.3 -**  **367:** Commenters 9666, 10046 stated EPA cannot select as BSER a technology that has not been adequately demonstrated based on an asserted interest in "promoting technological development." According to the commenters, requiring CCS will actually hinder its devel opment by

discouraging construction of new Subpart Da units. Commenter 10046 compared the EPA's FGD technology forcing NSPS with that for CCS, and noted that now, alternative fuels are available. **Response 6.3 -**  **367:** The EPA has not selected a BSER solely to promote use of a technology , and its determination would be the same whether or not it considered this factor. See preamble section III.H.5.d. **Comment 6.3 -**  **368:** Commenter 9666 stated the effective way to encourage technological innovation is to provide developers with greater regulatory f lexibility, as the D.C. Circuit recognized in Sierra Club by allowing EPA to promulgate a less stringent flexible standard that could be met b y units experimenting with promising (yet unproven) dry scrubber technology. 657 F.2d at 351. **Response 6.3 -**  **368:** The final standard of performance in fact can be achieved a number of different way s of which the EPA is aware. **Comment 6.3 -**  **369:** Commenter 9666 stated EPA provides no support for its assertion that "not identifying partial CCS as the BSER could potentially impede further utilization and dev elopment of CCS." 79 Fed. Reg. at 1480. According to the commenter, the Agency has identified several projects currentl y under construction or in development that plan to integrate CCS, despite the fact that those projects are not subject to any CO 2 emissi on limit based on the use of CCS, and therefore it is unclear why EPA believes the current regulatory status quo that has led to these projects would impede other similar projects from being developed in the future. Commenter 9426 stated that the EPA contradicts itself by stating that few if any

solid fossil
- fuel EGUs will be built in the foreseeable future, and that a standard for new coal
- fired EGUs based on partial capture "promotes deploy ment and further development of the technology ." Commenters 7977, 10662 stated that there is a distinction between technology forcing and encouraging technological innovation, and section 111(j) of the CAA specifically provides for the promotion, development, and deplo ym ent of innovative technological sy stems of continu ous reduction for technologies like CCS that have not been adequatel y demonstrated. The commenter stated that, section 103(g) of the CAA provides EPA with the authority to conduct a basic engineering research and technology program to develop non
- regulatory technologies and strategies. Commenter 10046 stated that if the EPA's proposal will not promote the development of CCS technology , then EPA has no legitimate basis to proceed.6
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Commenter 10046 stated that the EPA should analyze whether the performance sta ndard enhances or diminishes CCS technology or economic risk, or whether the addition of environmental compliance risk (requiring CCS) for one fuel (coal) but not the other (gas) does any thing other than force companies to build gas units and avoid coal un its. Commenter 10046 noted that the statue and applicable case law require EPA to set a different standard if in fact the standard it proposes to set would sty mie CCS development. The commenter provided citations to support their statement. **Response 6.3 -**  **369:** The EPA’s task is to identify a best sy stem of emission reduction adequately demonstrated and to set a standard predicated on performance of that technology . The EPA has done so here. The final standard of performance will encourage new sources

– indeed will compel th em – to emit less CO 2 than they would if doing business as usual. Moreover, it is well documented that a regulatory requirement often brings a great influx of technological innovation. See preamble section V.K. and L., and TSD documenting the history of technological innovation following the 1971 NSPS for this same industry
. We again note that AEP and Alstom, in prior public statements extolling CCS technology reliability

and cost
- effectiveness, indicated the importance of a firm regulatory framework to promote use of CCS. **Comment 6.3 -**  **370:** Commenter 9201 stated EPA's assertions about the proposed rule's ability to incentivize technological innovation are not adequately explained in the face of the unavailability of CCS technology

for commercial power generators. Thus, the commenter noted, EPA's decision to set CCS as BSER over other technologies that represent significant CO 2 reductions and incentivize technological innovation of efficient coal generation is unreasoned and arbitrary
. **Response 6.3 -**  **370:** CCS is an available technology
. **Comment 6.3 -**  **371:** Comm enter 10048 stated that in the absence of environmental benefits, it appears that EPA's overriding reason for proposing the rule is to provide an incentive to promote adoption of CCS technology ; however, as EPA is well aware, CCS is a complex, costly and l egally challenging technology

that will not be adopted when more cost
- effective and less complicated generation alternatives are available. **Response 6.3 -**  **371:** As shown in RIA 4, new non - compliant coal technology is not being constructed , for reasons unrelated to this NSPS . New coal capacity is a technology now being adopted as a means of preserving a diverse energy portfolio, or some other reason than lower cost. The promulgated standard of performance preserves that alternative by leaving new coal priced competitivel y w ith other baseload dispatchable non
-NGCC technologies
. Moreover, should there be very

s ignificant increases in natural gas prices, there may be renewed interest in new coal plants. Issuing a standard that allows construction of new high
- emitting coal plant s without a CCS requirement therefore poses a nontrivial risk of increased emissions and further exacerbation to climate. Given their long lifetimes, construction of new high
- emitting coal plants could lock in their higher emissions for many decades to com e. See preamble section V.K.6
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**Nationwide, Long -**  **Term Perspective Comment 6.3**  **- 372:**  Commenter 9735 stated that the proposed rule provides no graduated or realistic targets over the long
- term, but rather immediatel y sets a low baseline emissions target that cannot currentl y b e achieved on a large
- scale or cost
- effectivel y. The commenter further stated that it is necessary

to encourage investment in advanced emissions reduction technologies while working toward CCS. **Response 6.3 -**  **372:** The EPA has reasonabl y determined that parti al CCS, with highly efficient SCPC, is BSER now. The EPA must therefore establish a standard of performance reflecting performance of that BSER. **Comment 6.3 -**  **373:** Commenter 9664 discussed the authority of EPA to adopt standards and technologies without requiring a cost
- benefit analy sis at the plant level as long as the response to the problem and the pollution reduction benefits can be justified at the regional or national level through a broad assessment (see Sierra Club v. Costle, 657 F.2d. at 329
- 332, S. Rep. No. 95
- 127 (1977) and H. Rep. No.95
- 294 (1977)). **Response 6.3 -**  **373:** The EAP largel y agrees with this comment. **Comment 6.3 -**  **374:** Conversel y, Commenter 9666 stated that the Agency may not set an NSPS based on national
- scale considerations if it would impose unreasonable costs, environmental impacts, or energy

requirements at the individual plant level, rather that the CAA only permits EPA to consider long term effects once it has determined that source
- level impacts are consistent with the statutory

criteria for NSPS (also citing Sierra Club v. Costle, 657 F.2d at 330). The commenter suggested that EPA improperly focuses on the costs and effects of its CCS mandate on a nationwide, long
- term scale at the expense of considering its effects on individual new sources. **Response 6.3 -**  **374:** The EPA has considered both plant
- level impacts and natio nal impacts in its determinations here. **Comment 6.3 -**  **375:** Commenter 9774 states that the NSPS for coal
- fired power plants cannot be based on CCS at this time, and that EPA must correct the NSPS deficiencies and modify the rule to exclude sources that are inappropriately regulated in order to avoid significant issues within the utility sector, including possible delay s in CO 2 emission reductions. **Response 6.3 -**  **375:** The EPA disagrees. See preamble section V. **Comment 6.3 -**  **376:** Commenter 9425 suggested that these regulations may force several power plants to shut down in a relatively short amount of time. The commenter remarked upon the need for states to have enough time to work with EPA to understand the impacts to fuel diversity and energy reliability

in setting the standards, as well as the implementation and timing of the standards. **Response 6.3 -**  **376:** These standards appl y to new sources exclusively, or to modified and reconstructed sources. There is no question that such a source would be ‘shut down’ when not ye t in existence.6
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**Comment 6.3 -**  **377:** Similarly, Commenters 9201, 6429 and 9666 discusse d the potential impact of CCS on diversity

of fuel supply

for the electric grid in terms of both reliability and affordability . Commenter 9666 also stated that although the EPA recognizes that protecting fuel diversity is important and that the costs of CC S will render construction of new coal
- fired capacity infeasible under the proposed standard, EPA incorrectl y assumes that the CCS mandate will not increase energy

prices or change the structure of the energy sector. Commenters 9201, 6429 and 9666 suggest ed that because coal will be uncompetitive with natural gas due to CCS, the grid will become less diverse, more susceptible to price spikes and disruptions, and it will be less certain that additional natural gas
- fired capacity will reliabl y meet the basic demand for electricity. Commenter 9426 provided the price increases during the polar vortex as an example, and stated that the proposed standard will distort the true cost of natural gas. **Response 6.3 -**  **377:** Coal is already economically non
- competitive with natural gas. S ee RIA chap ter 4. See preamble section V.I.4 . as to wh y basing a standard of performance on partial CCS will not discourage new coal capacity or use of CCS . Again, AEP was of the considered public view that CCS represents a lifeline for the industry , not a millstone. **Comment 6.3 -**  **378:** Commenter 10870 also stated its concern that the Proposed Rule will result in the elimination of coal from the nation's fuel portfolio rather than more fuel diversity , leading to less reliable and less affordable electricity as well as less e ffectivel y controlled sources of power generation needed for the economy . The commenter further asserted that uncertainty of additional requirements under Section 111(d) will effectivel y end development of coal
- fired electric utility

units unless the Propo sed Rule is written to exclude any new requirements during the life of the plant. **Response 6.3 -**  **378:** The standard of performance adopted here does not apply to existing facilities. **Comment 6.3 -**  **379:** Commenter 10048 stated that the majority of renewable energy

options are not baseload resource s. Additionally the commenter remarked that no significant new nuclear generation is planned, therefore fuel diversity can be expected to decrease. **Response 6.3 -**  **379:** Public announcements including IRP **s** confirm that utilities are interested in technologies that could provide or preserve fuel diversity within generating fleets. The Integrated Resource Plan TSD notes examples where the goal of fuel diversity was considered in IRPs; in many cases, these plans considered new generation that would not rely on natural gas. In parti cular, several utilities that considered fuel diversity in developing their IRPs included new nuclear generation as a potential future generation strategy
. See also Global CCS Inst, “The Costs of CCS and Other Low
- Carbon Technologies” (2015) p. 1 finding th at “ [n]uclear generation plant as well as hydro and geothermal platn can also be cost competitive ins ome markets fiven thei high utilisation rates (i.e. can be oeprated 80 to 90 per cent of the time)”. **Comment 6.3 -**  **380:** Commenter 9666 remarked that EPA incorrectly assumes in Section II that in the future, coal units without CCS will not be competitive with natural gas units not subject to CCS. The commenter further suggested that coal only becomes uncompetitive once a costly and undemonstrated CCS is imposed.6
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**Response 6.3 -**  **380:** See RIA chapt er 4. **Comment 6.3 -**  **381:** Commenter 9666 also stated that requiring CCS will not promote coal
- fired generation b y eliminating future obligatory controls uncertainty as EPA purports since this would be true of any final action EPA takes, regardless of the level of control chos en. Furthermore, the commenter states that this rulemaking does not confer any advantage because any source that is subject to this proposed NSPS would not be subject to future NSPS controls or revised standards since the controls would apply onl y proacti vely , and sources could avoid falling under the revised standard b y foregoing modification or reconstruction. **Response 6.3 -**  **381:** See preamble section V.L and K. (documenting, among other things, the spurt in technological innovation after promulgation of NSPS based on FGC s crubber technology less well developed than CCS at a comparable point in the regulatory timeline), and see also statements of AEP that regulatory uncertainty

was a factor in the decision not to proceed with the Mountaineer demonstration project
. **Comment 6.3 -**  **382:** Commente r 9191 stated that each of the facilities cited by EPA involve unique circumstances that do not render CCS appropriate for nationwide application **Response 6.3 -**  **382:** The EPA disagrees. See preamble section V. **Comment 6.3 -**  **383:** Commenter 10052 stated that CCS is infeasible in much of the count ry due to pipeline capacity, site availability and demonstration projects. Similarly, Commenter 9408 stated that CCS will be particularly difficult to deploy

in some geologic formations and implored EPA not to promulgate any standard that relies on CCS in those areas. For example, Florida has an artesian aquifer that underlies the entire State and is a source of potable water for every community

in Florida. Because of the aquifer's relative importance, the commenter suggested that it is unlikely that subsurface CCS will ever be allowed in Florida, nor is the risk of potentially compromising the resource by injecting CO 2 into it or through it acceptable. The commenter also suggested it is improbable that other State would accept Florida's CO 2 emissions to be transported for permanent storage. **Response 6.3 -**  **383:** See Section V. M . of the preamble and the technical support document on geographic availability . Potential GS formations are widel y available in the United States. The EPA recognizes that geologic conditions to support C O 2 storage may not exist in all regions of the country . Where such capacity is unavailable, electricity demand in those areas can be served by coal
- fired power plants built in neighboring areas with geologic availability with generated electricity being su

pplied via transmission line, see Figure 1 of TSD on geographic availability , or the CO 2 can be transported to available GS sites via pipeline. For other of those areas, coal
fired power plants are either not being built due to state law prohibition s against building such units, or other available compliance alternatives exist allowing a new coal
- fired power plant meeting the promulgated NSPS to be sited. There are alternative means of complying with the final standards of performance which do not necessitate use of partial CCS, so any siting difficulties based on lack of a CO 2 repository wou ld be obviated. The EPA notes that Figure 1 of the technical support document on geographic availability shows6
- 236

the areas of Florida that are within 100 kilometers of a potential GS formation; electricity demand may

be served by

coal
- fired electricity

gene ration built in areas that are proximate with geologic sequestration, and this electricity can be delivered through transmission lines. **Comment 6.3 -**  **384:** Commenter 9426 stated that public education and communication between communities and potential storage project proponents is needed to move forward on a large scale so that landowners are comfortable with the process, monitoring and verification elements of CCS. The commenter provided fracking as an example of possible public reaction. **Response 6.3 -**  **384:** Public awareness and support have b een widel y recognized as critical components in the development of new energy infrastructure, including CCS deploy ment . Efforts have been made to design strategies for successful outreach to the public
. For example, under the DOE Regional Carbon Sequestration Partnerships, DOE has been engaging with local communities to educate and inform them about planned pilot and demonstration projects in their areas. DOE’s Best Practices for Public Outreach and Education for Carbon Storage Projects presents lessons learned through the planning and implementation of CCS projects, as well as best practices for community engagement. **Comment 6.3 -**  **385:** Commenter 10089 stated that given the currently sparse CCS market, the electric power sector would be compelled to work from ground zero to b ecome compliant with NSPS. The commenter recommended that further anal ys is is necessary to ascertain whether CCS is indeed the best sy stem of emission reduction for new power plants. **Response 6.3 -**  **385:** The EPA disagrees. See preamble section V. **Comment 6.3 -**  **386:** Commenter 0775 stated what while CCS may not meet desired cost and energy efficiency

goals today , the regulation is a safeguard against coal as the dominant energy source and stimulates CCS technology
. **Response 6.3 -**  **386:** The EPA disagrees with this comment on every count. Partial CCS is an adequatel y demonstrated technology within the meaning of section 111 (a) of the Act. The objective of a standard of performance is to have new plants perform to a level achievable by the performance of the BSER. It is not to be a safeguard against use of any part icular technology , industrial process, or fuel source, and the EPA has no such objective here. **Energy and Nonair Quality Environmental Impacts Comment 6.3**  **- 387:**  Commenters 9381, 9396, 9592, 9666, 9780 and 10100 stated that the subject has not been adequatel y assessed the as required by Section 111(a)(1). Commenter 9194 cited 1973 and 1999 court decisions requiring that EPA fully assess non - air and economic impacts. Commenters 9194, 9381, 9592, 9780 and 10100 noted that additional consideration of environmental impacts of CCS, such as reduced energy efficiency , increased coal use, increased water withdrawal and consumption, increased water discharges, and increased emissions of criteria and toxic pollutants, is required b y EPA to meet statutory obligations.6
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Commenter 9396 c ited a 2013 NETL report discussing the significant energy , efficiency , water use, air emissions and cost impacts that could result from partial CCS. **Response 6.3 -**  **387:** The EPA has carefully considered potential nonair impacts of the final standard of performance, as require d by CAA section 111 (a)(1). EPA has carefully considered the safety of transport and permanent sequestration of captured CO 2 and has found reasonably that the regulatory

structures of 49 CFR Part 195 (for CO 2 pipelines), and Class VIand Class II injecti on wells (for geologic sequestration and EOR, respectivel y), with the further complementary

monitoring and reporting standards of GHGRP subpart RR, assures safe transport and permanent sequestration. EPA has also projected that , under a set of assumptions where new non
- compliant coal
- fired capacity is added, there will be SO 2 (and consequent secondary PM) reductions associated with use of partial CCS (due to the need for ultrahigh purity solvent). See RIA chapter 5.3 and Table 5.1. Is sues of water use are addressed at preamble section V.O.2. **Comment 6.3 -**  **388:** Commenter 9396 cited a NETLreport to estimate that to meet EPA's proposed standard with an SCPC, it would require:

 a capture rate between 30 and 50%  an additional 180,000 to 300,000 tons of coal each year  a decrease in net fuel efficiency from 39% to 33
- 35% and heat rate from 8687 Btu/kWh to 9695
- 10379 Btu/kWh  an increase in water withdrawal of 16
- 30% and consumption by 14
- 26%  an increase of NOx, Hg, and PM by 2
- 7%  the capital cost b y 26
- 39%  the operating cos t by

30
- 43%  and cost between $79 and 102 per tonne of CO 2 avoided. The commenter asserted that these results indicate a full energy and environmental impact assessment is warranted and has not been conducted. **Response 6.3 -**  **388:** These estimates reflect full CCS. The final s tandard of performance has considerabl y reduced water use impacts, which the EPA has evaluated and found to be reasonable. See preamble section V.O.2. **Comment 6.3 -**  **389:** Commenter 9596 stated that EPA should withdraw the NPR in order to evaluate the potential impact of CCS on groundwater and other environmental factors because the current proposal is arbitrary and capricious, and not in accordance with the requirements of the statute. **Response 6.3 -**  **389:** EPA has carefull y evaluated the risks of injected CO 2 to underground sources of drinking w ater (which can include groundwater) in its rules for Class VIand Class II injection wells. Owners or operators of Class VI wells must develop and implement a comprehensive testing and monitoring plan for their projects that includes injectate analysis, mechanical integrity

testing, corrosion monitoring, ground water and geochemical monitoring,6
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pressure fall
- off testing, CO 2 plume and pressure front monitoring and tracking. Groundwater and geochemical monitoring is explicitly required. 67 Owners and operators must periodically review the testing and monitoring plan to incorporate operational and monitoring data and the most recent area of review reevaluation. 68 **Comment 6.3 -**  **390:** Commenter 10033 requested that EPA draw on lessons learned with MTBE to ensure that the benefits of CCS are carefull y weighed against the costs and risks of geologic sequestration and CCS. **Response 6.3 -**  **390:** Storage of a chemical in in
- ground, unregulated tanks is in no way comparable to the detailed and comprehensive regulatory requirements for CO 2 geologic sequestration in Class VI wells, or the regulatory requirements for use of CO 2 for EOR in regulated Class II injection wells. **Comment 6.3 -**  **391:** Commenters 7977, 9648 and 10681 stated that EPA has not addressed parasitic loads. Commenter 10681 further asserted that the final rule shou ld allow parasitic loads on an IGCC sy stem to be treated similarly to a utility boiler. Commenter 9648 stated that EPA must conduct a lifecycle energy

consumption and emissions inventory evaluation and demonstrate that the 25 percent and 50 percent partial capture rate associated with BSER for IGCC and conventional coal
- fired utility

boilers, respectivel y, are based on actual performance levels, and the risks associated with implementing a complex technology that delivers the needed emission reductions. Si milarly, Commenters 7977, 9196, and 9780 stated that EPA must investigate how the CCS energy penalty of approximately

30% may

impact the technical feasibility of CCS integrated with electricity generation and must be addressed by EPA. Commenter 10039 state d that the energy penalty is at least 40%, requires upsizing of EGU equipment, and results in higher emissions of pollutants. Commenters 9003 and 9648 also noted that additional energy requirements can increase criteria air pollutants and toxic air pollutant emissions, as well as raise nonattainment concerns. Commenters 10017, 10050, 10552 noted that it is inconsistent and wasteful for EPA to mandate a specific technology

(CCS) that consumes a large power load in order to operate. Commenter 7977 also discus sed the environmental impacts of increased coal use. Commenter 10618 cited the DOE and GAO estimates, up to 30% and 32% respectivel y, for the energy penalty associated with CCS. Commenter 8966 provided a citation stating that the energy penalty may range f rom 12 to 28%. Commenter 9772 cited a 2013 CRS Report identifying energy penalties from 16 to 40%. Commenter 10680 cited a CRS report identifying energy penalties 19 to 30%, or 10 to 100 times other currently employed control sy stems.

67 40 CFR §146.90. 68 40 CFR §146.90(j).6
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Commenter 8957 estimated that if plant that sequesters and retains 40% of its own emissions, it will only

result in a 12% reduction from the uncontrolled plant for an equivalent net electrical output. The Commenter concludes that therefore, CCS is not currently economically

viable due to the significant energy

penalty nor is it necessarily

environmentally

beneficial. Commenter 10048 stated that the additional power needed to offset the energy penalties, resulting in additional baseload units, carbon emissions and costs, should not be considered reasonable until the energy penalty is minimized. **Response 6.3 -**  **391:** The EPA has carefully addressed the issue of parasitic loads and finds the potential energy

impacts to be reasonable at a per plant level. See preamble section V.O.3. **Comment 6.3 -**  **392:** Conversel y, Commenter 10108 suggested that the BSER determination has met the needs to assess the environmental impacts and notes that the energy penalty is anticipated to decrease as coal plants as efficiency and the availability

of advanced technologies increase. **Response 6.3 -**  **392:** The EPA largel y agrees with this comment. **Comment 6.3 -**  **393:** Commenters 9777 and 9780 also provided referenced estimates of some potential environmental impacts, including a 90%, 87% and 46% increase in water consumption for PC units, for SCPC units and for IGCC plants, resp ectivel y, as well as water requirements to compress and transport supercritical CO 2 . Commenter 9777 also cited NETLwater consumption requirements for EGUs with CCS and stated that EPA should reconsider whether CCS is BSER due to water demands. **Response 6.3 -**  **393:** See preamble section V.O.2. **Comment 6.3 -**  **394:** Similarly, Commenters 9666 and 10039 stated that CCS will nearly double the amount of water required for energy generation at units subject to the proposed standard. Commenter 10039 stated that EPA must consider the impact on water supply and water quality
. Commenter 9497 stated that the proposed rule does not address how water requirements may affect reliability , especially in areas with water shortages. Commenter 9777 provided results from a study that indicate CCS would increase w ater withdrawal b y 5
- 7% and consumption by 88
- 100% by

2030. The commenter stated that water increases raise concerns about CCS feasibility due to water availability , water rights, and costs of long term water purchases, especiall y in states with water shortages. Commenter 9777 recommended that operational data from a full scale plant would help address concerns regarding water consumption. Commenter 9666 further stated that the placement of CCS needs to be balanced with water requirements and water availabi lity , and EPA cannot adopt an NSPS that precludes construction of new sources at water
- restricted areas in the U.S. in keeping with the CAA, relevant case law, and EPA's past practice (See Sierra Club, 657 F.2d at 330). **Response 6.3 -**  **394:** See section V.O.2 to the preamble to the final rule.6
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**Comment 6.3 -**  **395:** Commenter 9770 stated EPA's environmental assessments never looked at the water management issues that result from CCS. The commenter observed that the EPA and DOE have never inquired of states whether they would anticipate, given that more than half of the states in the U.S. are in their second ye ar of drought, whether this brackish water might be needed to augment surface and other groundwater resources. The commenter stated there are questions about the threat that injection of CO 2 under ground would pose to deep saline aquifers. According to the commenter, our municipal utilities have an obligation to protect existing and future drinking water resources located in deep saline aquifers, in addition to providing reliable, affordable and env ironmentally responsible electricity . The commenter agreed with AWWA regarding the potential threats to future municipal and private drinking water resources from CCS and about how those threats are relevant to EPA's BSER determination **Response 6.3 -**  **395:** See preamble section V.O.2 for the EPA’s consideration of the issue of water use. Drinking water resources are the focus of protection under the Class VI and Class II UI C regulations. Preamble section V.N. explains why those rigorous standards result in protection of underground sources of drinking water, and that the siting and monitoring regime which achieves that protection also prevents releases of sequestered CO 2 to the ambient air. **Comment 6.3 -**  **396:** Commenter 9666 also stated that EPA has incorrectly attributed a larger water consumptio n to CCS at gas
- fired power plants than coal
- fired power plants, thus ruling out CCS as BSER for gas and not for coal plants. However, water consumption would be expected to increase b y 70% at gas
- fired plants and 90% and 87% for PC and SCPS units. The commenter remarked that the BSER determination effectivel y bans new coal
- fired EGUs, reducing nation's baseload energy

diversity and almost exclusively promoting natural gas due to permitting burdens for nuclear and hydroelectric energy generation. **Response 6.3 -**  **396:** Water use issues are addressed at preamble section V.O.2. The final BSER determination does not ban new coal
- fired EGUs, and (as expressed b y AEP) may provide a means for continued use of coal in new facilities as part of the nation’s energy portfolio. **Comment 6.3 -**  **397:** Commenter 9195 provided the following list of questions in relation to sole source aquifers:

 How did EPA address the cross statutory issues related to the injection and sequestration of CO 2 if the injection must go through a sole source aquifer?  Please explain how EPA's Office of Air and Radiation and EPA's Office of Water communicated and considered the impact of the proposal on EPA's own special program dedicated to protection of sole source aquifers. **Response 6.3 -**  **397:** See preamble section V.N. **Comment 6.3 -**  **398:** Commenters 9648 and 9770 stated that EPA has not assessed the impacts of permanent storage of compressed gases. Commenter 9648 stated that the proposed rule transfers air pollution to other environmental media. Commenter 9648 further stated that altering pressure gradients could cause numero us health and environmental impacts.6
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Commenter 9648 also cited the SAB's concerns on cross
- media issues and recommended that EPA request that NRC conduct an assessment. Commenter 9648 also stated that a commercial sized partial CCS may not be feasible with power plants with limited space. **Response 6.3 -**  **398:** EPA has carefull y assessed the issues of geologic sequestration, and strongly disagrees with the commenters’ assertions that EPA has not studied the issue, and the cursory assertion in comment 9648 that geologic sequestration of captured CO 2 could lead to numerous adverse health and environmental impacts. 69 In particular, the Class VI standards require very proscriptive site evaluation and on
- going monitoring. Owners or operators of Class VI wells must develop and implement a comprehensive testing and moni toring plan for their projects that includes injectate anal ys is, mechanical integrity testing, corrosion monitoring, ground water and geochemical monitoring, pressure fall
- off testing, CO 2 plume and pressure front monitoring and tracking, and, at the discr etion of the Class VI director, surface air and/or soil gas monitoring. 70 Owners and operators must periodically review the testing and monitoring plan to incorporate operational and monitoring data and the most recent area of review reevaluation. 71 Robust m onitoring of the CO 2 stream, injection pressures, integrity of the injection well, ground water quality and geochemistry, and monitoring of the CO 2 plume and position of the pressure front throughout injection will ensure protection of USDWs from endangerm ent, preserve water quality , and allow for timely detection of any l eakage of CO 2 or displaced formation fluids. **Comment 6.3 -**  **399:** Commenter 10661 stated that EPA must address will increase in ammonia emissions, coal ash and boiler slag from CCS deploy ment, which cannot be captured using control technologies. **Response 6.3 -**  **399:** The NETL cost estimates include costs for disposal of fly ash and bottom ash. See NETL (July

2015) at p. 43. Moreover, ash is generated as a result of coal combustion, not capture of the resulting CO 2 . With respect to ammonia emissions, new steam generating EGUs that choose to comply with the final standard of performance by implementing partial post - combustion CCS are likely to use commercially
- available amine
- based capture s ys tems. Some concern has been raised regarding emissions of amines and amine degradation of amines (e.g., ammonia, NH3) from the capture process. To reduce the amine emissions, MHIintroduced the first optimized washing s ys tem within an absorber column in 1994, and developed a proprietary

washing system in 2003. In that s ys tem, a proprietary reagent is added to the water washing section to capture amine impurities such as amine, degraded amine, ammonia, formaldeh yde, acetaldehyde, carbonic acids and nitrosamines. 72 MHI has continued to improve

69 We note further that commenter 9648 (North Carolina DENR) did not submit any comments on the Class VI standards during the rulemaking developing those standards, even though the purpose of that rulemaking was to assure safety of geologic sequestration of captured CO2 from fossil
- fuel fired power plants. See , e.g., 75 FR at 77 233 (Dec. 10, 2010). 70 40 CFR §146.90. 71 40 CFR §146.90(j). 72 Sharma, S.; Azzi, M.; “A critical review of existing strategies for emission control in the monoethanolamine
based carbon capture process and some recommendations for improved strategies”, Fuel, 121, 178 (2014).6
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this technology

for further reduction of amine emissions and established an “advanced amine emission reduction sy stem”. Research performed b y MHIat Alabama Power’s Plant Barry indicated that an increasing SO3 content in flue gas caused a significant increase of amine emissions. During testing, at Plant Barry MHI applied its proprietary washing s ys tem and confirmed that the amine emission were drasticall y reduced. 73 Others have also studied emissions and control strategies and have determined that a conventional multi
- stage water wash and mist eliminator at the exit of the CO 2 scrubber is effective at removal of gaseous amine and amine degradation products emissions. Additional research continues in this area **Comment 6.3 -**  **400:** Commenter 9201 asserted that EPA failed to examine th e impacts of increased methane emissions from natural gas development needed to supply the power sector. Furthermore, the commenter suggested that the GHG reductions from new high performing SCPC or I GCC would be about 20 percent below the national average for the existing coal fleet. Commenter 9201 therefore remarked that if EPA adjusted the methane global warming potential used in assessment studies to the most recent factor, shale gas has a greater GHG footprint than coal used for electricity

over the 20
- ye ar time horizon. **Response 6.3 -**  **400:** The comment that the promulgated NSPS will lead to increase CH4 emissions due to increased use of natural gas has no basis. New natural gas capacity is being added for reasons unrelated to this standard of performance. See RIA chapter 4. The commenter also evidently

assumes CH4 emissions associated with natural gas production and transport are uncontrollable, which the EPA does not believe to be the case. **Comment 6.3 -**  **401:** Commenter 10680 stated that upstream emissions from coal mining, processing and transport will be considerabl y higher because CCS plants will consume more coal. **Response 6.3 -**  **401:** Issues of parasitic load are addressed at preamble section V.O.3. DOE/NETL estimates that a new SCPC unit would utilize about 4% more coal in order to meet the final 1,400 lb CO 2 /MWh standard (to provide the same net power output). However, since the EPA has specified that the BSER for new fossil fuel
- fired steam generating units is “a highl y efficient supercritical pulverized coal (SCPC) unit implementing partial CCS”, a new unit meeting the final standard of performance will utilize less coal than a comparabl y- sized existing coal
- fired plant that is less efficient. **Comment 6.3 -**  **402:** Commenter 10693 stated their support for policies that require significant control technologies and the phasing out of conventional coal fired plants due to the health and air quality

impacts associated with coal mining and use. Similarly , Commenter 8924 supported the EPA in addressing carbon pollution and requested that the final rule regulate coal fired plants to reduce emissions to the levels that they are capable of.

73 Kamijo, T.; et al., “SO3 Impact on Amine Emission and Emission Reduction Technology”, Energy Procedia, Volume 37, 1793 (2013).6
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**Response 6.3 -**  **402:** The final standards of performance represent a level of emission reduction capable of being achieved using a best sy stem of emission reduction adequately demonstrated. That is all that the EPA is empowered to do under section 111 (b). The standard has nothing to do with phasing out conventional coal fired plants, and, as AEP indicated in its public statements, may

provide a means for new coal capacity in the future. **Comment 6.3 -**  **403:** Commenter 6501 stated their sup port for the proposed CO 2 limits due to the health and environmental impacts of air pollution and climate change. **Response 6.3 -**  **403:** The EAP acknowledges the commenter’s support. **Comment 6.3 -**  **404:** Commenter 9516 stated that the proposed rule allows CCS sources to credit electricity from unre gulated sources used to power the gasifier and compressor when determining compliance. **Response 6.3 -**  **404:** The EPA notes that s team generating unit means any furnace, boiler, or other device used for combusting fuel and producing steam (nuclear steam generators are not included) plus any integrated equipment that provides electricity or useful thermal output to the affected EGU(s) or auxiliary

equipment. **Comment 6.3 -**  **405:** Commenter 9682 stated that in the context of GHG regulation under the NSPS program, the energy
- requirement and environmental
- impact assessments prescribed b y the statute are the same. The commenter noted that the whole reason for b urning and thus emitting carbon dioxide is that fossil fuels are stores of energy . As a result, the commenter stated that what should be two distinct inquiries into "energy requirements" and "environmental impacts" impermissibly

collapse, in the context of fossil
- fuel burning, into one and the same assessment. **Response 6.3 -**  **405:** The EPA has analyzed these two factors separately , and permissibly so. Issues of water use and safety of sequestered CO 2 are not the same issues as energy use due to energy required to operate CO 2 c ontrol technology. See preamble sections V.O.2. and 3. **Use of Purportedly**  **Extra -**  **Statutory "Purposes" to Justify Standard of Performance Comment 6.3**  **- 406:**  Commenter 9514 stated EPA properl y considered the costs of partial CCS in light of the benefits that will accrue from c onsidering the social cost of carbon and the co
benefits from reduced emissions of other harmful pollutants, including SO2, NOx, and PM2.5. The commenter also stated EPA also appropriately considered, in compliance with the CAA, the co
- benefits of reduced emissions of SO2 and NOx that would result from the proposed rule's CO 2 emission limits. The commenter stated EPA's recognition of co
- benefits is consistent with the methodology

it applied in the MATS rulemaking, which also addressed the rule's positive impacts on emissions of related pollutants. According to the commenter, this methodology

is also consistent with scientific studies linking policies to reduce greenhouse gases with shorter
- term air quality co - benefits. **Response 6.3 -**  **406:** EPA is finding that highly efficient SCPC and partial CCS is the BSER because it removes more emissions at reasonable cost (considering especially capital cost and LCOE, on a per plant basis), and does not have collateral adverse nonair health and environmental impacts, or impose undue energy burdens. This determination does not rest on6
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any consideration of monetized emission reductions, nor does section 111 (a) dictate any particular method (or metric) for considering costs. The EPA has also found that if new coal capacity is added, there are net quantified benefits under a range of assumptions, in the form of both CO 2 reductions and reductions in emissions of criteria pollutants controlled incidentally b y the standard. See RIA chapter 5. This may be another reason to find the standard t o be adequatel y demonstrated considering costs. The EPA notes that SO2 is a criteria pollutant (and indeed, already regulated under NSPS for this industry), so no issue is raised regarding considering benefits of control of a pollutant not otherwise within the scope of section 111 standards. **Comment 6.3 -**  **407:** Commenter 9514 stated that although EPA is not required to engage in a traditional cost
- benefit analy sis, the degree of the pollution reduction benefits that a proposed standard would achieve must be considered along w ith the costs of achieving it. The commenter referenced Sierra Club, 657 F.2d at 314, 327
- 28 (upholding costly SO2 standards that would provide significant pollution benefits); and Essex Chem. Corp., 486 F.2d at 437 (acid mist standards were reasoned and c ost benefit anal ys is was not required). **Response 6.3 -**  **407:** EPA believes that its cost anal ys is, and its conclusions that the costs of the final standard are reasonable and not exorbitant, are in accord with both of these cited cases. **Comment 6.3 -**  **408:** Commenter 9666 stated EPA does not separately measure the benefits associated with the control of CO 2 emissions that would purportedl y result from the proposed rule. Instead, the commenter noted, EPA estimates the combined benefits of reducing CO 2 , fine particulate matter, SO2, and NOx emissions. According to the commenter, if the purpose of the rule is to address CO 2 emissions from EGUs, EPA cannot properly introduce its estimates of the purported benefits of controls of other emissions. **Response 6.3 -**  **408:** The EPA disagrees with the commenter’s statement that EPA cannot properl y introduce estimates of benefits associated with reductions in emissions of pollutants other than CO 2 . As a preliminary matter, the EPA notes that the determination that the costs of the rule are reasonable are based on the anal ys is in sections V.H. and I. of the preamble to the final rule. However, the EPA has also found that if new coal capacity is added, there will be net quantified benefits under a range of assumptions, in the form of both CO 2 reductions and reductions in emissions of c riteria pollutants that will occur due to implementation of the standard. See RIA chapter 5. This may be another reason to find the standard to be adequatel y demonstrated considering costs. The commenter’s statement that a BSER determination is limited to a single pollutant and that the positive effects on emissions of another air pollutant cannot be considered when deciding what is “best” does not make sense . Suppose technology A removed 100 units of CO 2 and no other pollutants (or had a negative impact on other pollutants , and technology

B removed 99 units of CO 2 and significant amounts of other air pollutants as well. The commenter suggests EPA would have to ignore the impact of technology B on air pollutants other than CO 2 in deciding which one is the “best” s ys tem of emission reduction. This approach would not be consistent with the requirement that EPA must consider collateral impacts in determining which technology is “best” under section 111. See Essex Chemical Corp., 486 F. 2d at 439; Portland Cement. 486 F. 2d at 386. Moreover, the EPA notes that SO2 is a criteria pollutant (and indeed, already regulated under NSPS for this industry), so no issue is6
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raised regarding considering benefits of contro l of a pollutant not otherwise within the scope of section 111 standards. **Comment 6.3 -**  **409:** Commenter 9593 stated EPA cannot bolster its determination that partial CCS is adequately

demonstrated with an extra
- statutory assertion that it can choose a technology or set a related emission limitation in order to achieve "meaningful reductions." According to the commenter, the amount of reductions that may be achievable is unrelated to a determination that a technology

has been adequatel y demonstrated. The commenter stated EPA mu st set an emission limit at the level that is achievable b y the demonstrated technology, not a limit that would result in GHG reductions that EPA deems meaningful. Additionally, the commenter stated EPA's criterion related to attaining "meaningful" reducti ons also directl y conflicts with EPA's anal ys is that the proposed GHG NSPS, if adopted, will not reduce GHGs in any event because of what EPA predicts power plant deploy ments are likely

to be in the next several years. **Response 6.3 -**  **409:** The amount of emission reductions achieved is certainly a relevant factor in determining if a s ys tem of emission reduction is “best”. See. e.g., Sierra Club, 657 F. 2d at 326 (“we can think of no sensible interpretation of the statutory words ‘best technological s ys tem’ which would not in corporate the amount of air pollution as a relevant factor to be weighed when determining the optimal standard for controlling ... emissions”). For the same reason, lowest emitting performers are best in determining the MACT floor under CAA section 112 (d) (3). See NRDC v. EPA, 479 F. 3d 875, 880 (D.C. Cir. 2006. **Other BSER Options Comment 6.3**  **- 410:**  Commenters (1377, 5853, 6118, 6644, 6871, 8024, 8032, 8348, 8957, 9001, 9194, 9201, 9381, 9428, 9666, 9767, 9780, 10052, 10098, 10100, 10238, 10387, 10500, 10501, 10618, 10929) stated that the EPA should consider other technologies rather than CCS as BSER. Commenters (2470, 8348, 8501, 8923, 8949 , 8971, 9034, 9194, 9197 , 9201, 9381, 9407, 9472, 9472, 9593, 9595, 9596, 9665, 10017, 10048, 10098, 10100, 10466, 10500, 10680) noted that technologies such as SCPC, USCPC and I GCC generation have been adequatel y demonstrated and can serve as the basis for a BSER determination. Commenter (10618) stated that ultra
- supercritical technologies are beginning to emerge as a cost
- effective des ign preference, and have good prospects for growth. Commenters (9381, 9472, 10618) provided data showing CO 2 reductions from SCPC and USCPC designs compared to typi cal existing coal
- fired EGUs. Commenters (8348, 9197, 9665, 9666, 9772, 10388) recommended that EPA adopt a BSER determination for coal
- fired boilers and IGCC units based on the emission rates achievable b y IGCC, supercritical, and ultra
- supercritical technologies without CCS. Commenters (8024, 8957, 9001, 9428, 10048, 10238, 10387, 10501) sugge sted that EPA reconsider its proposal or withdraw and re
- propose this rule to include these existing technologies. **Response 6.3 -**  **410:** See preamble section V.P.1.6
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**Comment 6.3 -**  **411:** Commenter ( 10618) questioned the maturity and performance of the IGCC process, stating that while IGCC is techni call y feasible, it has not been adequately demonstrated. The commenter discussed the status of the Kemper and Edwardsport facilities, stating that both have experienced significant cost escalations throughout their design and construction and neither has b een demonstrated to be equivalent or more efficient than other coal
- based generation technologies. The commenter noted that a NETL database (cited in text) indicates at least 16 potential IGCC projects have been cancelled in the U.S. in recent years. **Response 6.3 -**  **411:** The EPA is not selecting IGCC as BSER. See preamble section V.P.1. **Comment 6.3 -**  **412:** Commenters (6962, 9768, 9766, 10029, 10035, 10664) suggested biotech uses for captured CO 2 . The commenters provided information about reuse to develop biofuels and other products, and recommen ded that these technologies be considered as BSER for carbon storage. Commenters (9766, 10029, 10664) noted that by foreclosing the beneficial reuse of captured CO 2 to produce algae
- based fuel, EPA has failed to take advantage of the opportunity and has mi sapplied Section 111. Commenter (10029) provided cost benefits of biotech uses for CO 2 compared to costs for carbon sequestration. The commenter asked that beneficial reuse technologies are not categorically excluded technologies and may be used by

affect ed EGUs, alone or in combination with other technologies, to meet the proposed CO 2 emission limit. **Response 6.3 -**  **412:** The final rule provides that ty pes of storage of captured CO 2 other than sequestration at an entity

reporting under the subpart RR rules may be utilized, provided that an applicant makes a case
- by
- case demonstration that the storage method is as effective as geologic sequestration. See §60.5555(g) of the final rule
. **Comment 6.3 -**  **413:** Commenters (9107, 9497, 10035, 10106, 10237) discussed alternative technologies to reduce CO 2 emissions from coal combustion. Commenters (9107, 9497) discussed a coal gasification processes. Commenter (10106) suggested co
- firing of coal and natural gas a s a form of emissions reduction. Commenter (10237) discussed concentrated solar power (CSP) as a means to achieve carbon reductions. Commenters (10664) suggested that an affected EGU should be allowed to use more than one technology

to achieve the standard **Response 6.3 -**  **413:** The final standard is a performance standard which can be met by whatever means the source chooses. EPA has specifically noted that natural gas co
- firing is a potential alternative means of compliance for both PC and IGCC facilities, so that EPA agrees with the suggestion in comment 10106. **Comment 6.3 -**  **414:** Commenters (7977, 10618, 10680) stated that a BSER determination based on high ly efficient generation technologies alone would produce significant emission reductions and other advantages. Commenter (9772) stated th at EPA should not take away options for improving the efficiency

of replacement baseload generation plants.6
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Commenter (10618) discussed the emission reductions possible with an NSPS based on the best performing existing units in the EPA's CAMD database. The commenter provided a table showing potential CO 2 reductions in the case of replacement of existing units with ultra
supercritical units, and discussed other environmental benefits resulting from higher efficiency technologies. Commenter (9486) compare d the energy requirements of CCS and those emitted by a well operated USCPC unit, and stated that the actual emissions of CO 2 from a newer technology coal fired EGU on a unit of energy delivered to the grid basis are essentially the same as those from a un it utilizing CCS. Commenter 10680 stated the parasitic load that CCS requires will increase emissions. Commenter (10618) stated that efficiency
- based improvements would be more readily transferred to existing units than CCS technologies. Commenter (9665) stated that these technologies, particularl y IGCC units, also can be constructed to be CCS ready , which would enable them to be retrofitted with CCS equipment in the future. Commenter (9772) noted that highl y efficient technologies would also lower barrier s to future implementation of CCS as that technology matures. Commenter (10618) stated that an NSPS based on higher efficiency technologies would drive future innovation, increase operating flexibility , and reduce development risks. Commenter (10618) stated that a BSER determination based on high efficient generation technologies would enable even more advanced generation and emission control sy stems, including CCS, to be developed, demonstrated, and commercialized. Commenters (8024, 9033) stated that a new generation of supercritical, ultra
- supercritical and IGCC units is needed to support the deploy ment of second
- generation CCS technologies, which DOE projects may

cost roughl y 50 percent less than current first generation technologies. Commenter (9033 ) has estimated that using best efficient technology and then upgrading the existing fleet, the industry can combine to exceed proposed targets for reduction in CO 2 prior to 2020 and the next NSPS review. Commenters (7977, 10618) stated that given the predicted high parasitic load of a CCS, higher efficiency technologies would use less coal, water, and raw materials with less resulting emissions, wastewater, and combustion by products. Commenter (10030) stated that an NSPS predicated upon efficiency could be defensible as BSER based upon technology and economics. **Response 6.3 -**  **414:** Use of highly efficient boilers is part of the BSER, but partial CCS is as well. See preamble section V.P.1. H owever, if a developer chose to construct highl y efficient SCPC using natural gas co
- f iring, the standard of performance is achievable, and such a unit can be designed to be CCS ready
.6
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**Comment 6.3 -**  **415:** Commenters (8348, 8923, 8957, 9033, 9201, 9381, 9590, 9593, 9665, 9772, 10100, 10680) noted that selecting high efficiency boiler designs as BSER would provi de the advantage of significant reductions of CO 2 emissions over older plant designs. Commenter (9201) stated that because most of the current coal
- fired EGU fleet is comprised of subcritical technology , a migration to new, higher efficiency SCPC technolo gy

as smaller and less efficient units are retired would produce real emissions benefits. Commenter (9665) noted that there would be no downside to that approach, because few coal
based units will be built in the near future. Commenters (9381, 10100) stated that for the same power output, a higher efficiency coal plant will require less CO 2 to be captured; this means a smaller, less costly capture plant; lower operating costs; and less CO 2 to be transported and stored. **Response 6.3 -**  **415:** The final standard of performance i s based on performance of a highl y efficient SCPC with partial CCS. This BSER will result in even greater emission reductions than SCPC alone, no matter how efficient. See preamble section V.K. **Comment 6.3 -**  **416:** Commenter (10017) stated that the reduction levels using current technology are not onl y adequate, but necessary in order to ensure that the EPA develops a standard that is consistent with the approach used to develop the natural gas NSPS. The commenter noted that the emissions of new SCPC and I GCC units when compared to the average emissions from coal
fired power plants represent a reduction of 25 and 36 percent respectively . The commenter stated that these reductions are more than twice the reductions proposed for natural gas plants. **Response 6.3 -**  **416:** There are persuasive reasons not to base BSER for NGCC plants on performance of CCS. See preamble section IX.C. **Comment 6.3 -**  **417:** Commenters (10098, 10618) stated that dismissal of other technologies is inappropriate. Commenter (10098) stated that basing the NSPS on energy efficiency

technologies would spur innovations that would allow power plant operators and contractors to meet GHG emission limits in the most cost
- effective manner. The commenter stated that the EPA failed to explore this possibility

in the proposed rule, making its rejection of thi s option arbitrary and capricious. Commenter (10618) stated that EPA's lack of evaluation of highl y efficient generating technologies is inconsistent with Section 111(b)(3), which requires EPA to issue and take into account information on technologies that could be applied to the specific source category for which an NSPS is being developed. Commenter (10017) stated that the NSPS is a technology
- based standard, not an air quality standard driven program. The commenter stated that the EPA should not use the NSPS in an attempt to reach some predetermined reduction standard or issue standards that support only certain industries or technologies. The commenter recommended that the EPA should recognize existing operating technology to set the NSPS standard.6
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**Response 6.3 -**  **417:** The EPA agrees that section 111 (b) is a technology
- based standard. Nonetheless, in determining what s ys tem of emission reduction is “best”, it is at the least reasonable to consider the extent of air pollution reduction. Partial CCS is a demonstrated techno logy

available for deploy

ment now at reasonable cost without collateral adverse impacts on other environmental media or on energy requirements. It achieves significantly more emission reductions than SCPC alone. See preamble section V.K. Partial CCS is therefore part of a best s ys tem. Commenter 10618’s reference to CAA section 111 (b)(3) is obscure. That provision requires EPA, from time to time, “issue information on pollution control technologies for categories of new sources and air pollutants subje ct to the provisions of this section”. This provision is unrelated to the process of setting a standard of performance, and in any case, the EPA has shown that partial CCS is a pollution control technology amendable for use (and actuall y being used) b y fo ssil fuel fired steam electric generating units. **Comment 6.3 -**  **418:** Commenters (10085, 10618) suggested that the EPA revisit the application of BSER and review information available through BACT determinations, EPA reports, demonstrated performance of international efforts, and the CAMD database. Commenter (10618) discussed their review of CAMD data for coal
- based EGUs, and the comparison of CO 2 emissions between units grouped by decade and the AEP Turk Plant. Commenter (10618) provided a table summarizing international effo rts evaluating highl y efficient generating technologies. Commenter (10618) provided a list of three EPA reports that evaluate highly efficient generating technologies. Commenters (9201, 10098, 10618) discuss EPA reports and guidance that found these techno logies to be effective methods of reducing GHG emissions. Commenters (9201, 10618) stated that consideration of these reports and other related information would clearl y indicate that highl y efficient generation technologies are the BSER upon which a balan ced NSPS could be based. Commenter (9201) provided information about emission rates for facilities using SCPC units from the EPA CAMD database. **Response 6.3 -**  **418:** See preamble section V.P. 1 and earlier comment responses in this unit. Please note in particular the anal ys is in section V.P.1 showing that new coal capacity would already reflect supercritical technology , so that a standard based on performance of that level of control would simply

ratify a status quo, not result in emissi on reductions over baseline emission levels. **Comment 6.3 -**  **419:** Commenters (10098, 10618) disagreed with the EPA's rationale to not promote highl y efficient technologies because a standard using highly efficient technologies could impede the advancement of CCS technology. Th e commenters stated that basing the NSPS on energy efficiency

technologies would spur innovations that would allow power plant operators and contractors to meet GHG emission limits in the most cost
- effective manner. Commenter (10618) stated that further de velopment of highl y efficient technologies could6
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actuall y benefit the development of CCS. Commenter (10618) asked if the EPA proposing an NSPS based on the use of the BSER, or is EPA proposing a CCS development rule. **Response 6.3 -**  **419:** The final standard of performance is b ased on the section 111 (a) statutory criteria: a best sy stem of emission reduction adequately demonstrated, and the level of performance achievable through use of that s ys tem of performance. **Comment 6.3 -**  **420:** Commenters (8032, 9201, 9590, 10092, 10097, 10098, 10395, 1061 8) stated that the EPA has ignored information about highly efficient generation technologies. Commenter (10618) stated that the EPA has not provided a serious, objective evaluation of the technology . The commenter stated that the EPA has not defined or i dentified highl y efficient generation technologies, identified or assessed key variables that impact efficiency , assessed overall environmental benefits, or quantified the magnitude of emission reductions with the use of energy efficiency

technologies, thu s providing no basis for the Agency to compare these technologies with CCS. Commenter (10618) noted that the EPA referenced nine international projects and databases listing dozens of other international efforts related to various aspects of CCS developme nt, but in the evaluation of highl y efficient generating technologies as the BSER, EPA referenced zero projects. Commenter (10098) stated that by failing to explore the use of energy efficiency

technologies, EPA's rejection of this option is arbitrary and capricious. **Response 6.3 -**  **420:** See preamble section V.P.1 and note that highl y efficient supercritical PCs represent a baseline of performance for a new source here. **Comment 6.3 -**  **421:** Commenters (9201, 10680) stated that the EPA dismisses emissions reductions from SCPC and IGCC as providing "little meaningful CO 2 emissions reductions." Commenter (9201) noted that the 40 percent reduction required from new coal plants in contrast to the proposed standard for new natural gas
- fired plants that are 25 percent higher than the performance of the ten best operating units. Commenter (10680) stated that the EPA's different approaches in setting the coal and natural gas standards cannot be reconciled and, as a result, are unreasoned and arbitrary
. **Response 6.3 -**  **421:** See preamble section IX.C.4. **Comment 6.3 -**  **422:** Commenter (9665) noted that EPA would be better served to adopt a non
CCS BSER standard for new fossil fuel
- fired utility boilers and Integrated Gasification Combined Cycle (IGCC) units. The commenter expressed concern that the partial CCS standard is legall y vulnerable and could j eopardize the validity of the entire NSPS rule. Commenter (10085) stated that to avoid legal scrutiny , the EPA should look at coal
- fired EGUs that have been constructed within the past ten years and look at what control technologies were determined to be best available control technologies (BACT) at the time of construction.6
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**Response 6.3 -**  **422:** The EPA believes it has made reasoned findings that partial CCS is part of the best sy stem of emission reductions for this source category
. **Comment 6.3 -**  **423:** Commenter (9665) recommended an emission li mit of 1,700 lb. CO 2 /MWh on a gross output basis for these high efficiency units. Commenter (9472) discussed the results of an attached report that anal yz ed CO 2 emissions data for all coal
- fueled units that have commenced operation since 2007. The comment er stated that the data was anal yz ed using EPA methodology to determine emissions rates that would be achievable over a ten
- ye ar period. The commenter stated that in the report, the following emissions rates are achievable for new coal
- fueled power plants without CCS:

- 1,915 lbs CO 2 /MWh for supercritical boilers burning bituminous and subbituminous coals;

- 2,080 lbs CO 2 /MWh for subcritical boilers burning bituminous and subbituminous coals; and

- 2,150 lbs CO 2 /MWh for all boilers burning lignite coals. The commenter recommended that the EPA should adopt the emissions limits for the particular subcategories set forth above. Commenter (9201) stated that emissions rates for conventional non
- CCS coal units are still too low given operational realities, and shoul d be set at a minimum between 1,800 and 2,000 lbs. CO 2 /MWh. Commenter (10664) suggested that the proposed rulemaking be revised to be outcome based. The commenter recommended that the EPA set the standard, provide a mechanism to demonstrate that the standard has been met, and allow reuse technologies to be an optio n for affected EGUs, alone or in combination with other technologies to achieve the proposed CO 2 emission limit. Commenter (9194) stated that the CO 2 emission rate achievable b y a new SCPC unit should be adopted for the GHG NSPS for coal
- fired EGUs. Commenters (8024, 9201) suggested that the EPA propose an alternative NSPS limiting CO 2 emissions to the emissions rate achieved b y new supercritical, ultra
- supercritical and IGCC coal technologies, which would be consistent with current EPA GHG BACT Guidance. C ommenter (10951) stated that EPA should be incenting the construction of a new generation of highl y efficient super
- critical and ultra
- supercritical coal plants. **Response 6.3 -**  **423:** See preamble section V.P.1. **Comment 6.3 -**  **424:** Commenter (9593, 9780) stated that the EPA can best move forward with the proposed NSPS by

adopting the emissions standards achievable b y supercritical coal
- fired boilers, which achieves significant reductions when compared to the subcritical boiler technology

in the existing coal
- fired fleet, and evaluating in the future whether CCS has become adequatel y demonstrated.6
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Commenter (9033, 9320, 9426) recommended EPA set CCS aside until the eight ye ar review of the NSPS to avoid conflict between EPA and DOE timelines for the commercialization of CCS technologies. Commenter (8348) stated that as CCS technology develops, the EPA can then give consideration to a more aggressive CCUS performance standard that could be applied to each EGU classification at a level of performance proven achievable for each particular classification, whether coal or natural gas
- fired. Commenter (8957) stated that if and when CCS becomes commercially viable, it may

be more efficient to set appropriate NSPS across all source categories, including NGCC. The commenter stated that until CCS is commercial ly available, EPA should not pursue it for this rulemaking. Commenter (3176) recommended further research and development for CCS without requiring CCS now. **Response 6.3 -**  **424:** See preamble section V.P.1. 

### 6. **3 .**  **7 EIA Analysis**  **Comment 6.3 -**  **425:** Commenter 8925 noted that based on EPA's reliance in the EIA upon the EIA Annual Energy

Outlook 2013, no new conventional coal facilities are projected beyond what is currentl y under development through 2020 and because coal + CCS is more expensive than conventional coal and provides no additional economi c value under current and proposed federal regulations, this implies no new coal with CCS would be built through 2040, in the absence of additional incentives (e.g., financial subsidies or emission limits). The commenter argued that no deplo ym ent of electric generating units with CCS for at least 8 and perhaps up to 26 or more ye ars suggests little financial incentive for commercial research or vendor activity , and that combined with uncertain funding for government
- funded research on CCS, this commercial s lowdown suggests slowing progress on CCS. **Response 6.3 -**  **425:** This comment reflects analy sis in RIA chapter 4, and is thus consistent with EPA’s anal ys is that no new non
- compliant coal would be built due to economic reasons. However, commenters (including commenters to the 2 012 proposal) indicated there are other reasons for adding capacity , including preserving fuel diversity , and as a hedge against rising natural gas prices. The final standard of performance is structured to assure that coal remains cost competitive with o ther low
- carbon baseload dispatchable non
-NGCC technologies. The on
going research into CCS, active vendor efforts in the field, and prior regulatory history indicate that a standard of performance can be a spur to development and deplo ym ent of the new po llution control technology which forms the basis of a standard of performance. See preamble sections V.F, V. I.4, and V.L
. **Comment 6.3 -**  **426:** Commenter 9201 stated EPA's assessment on the impact of its proposal relies upon flawed modeling and assumptions that produce a stati c default assumption that no new coal
- based power would be built even in the absence of this proposal. The commenter referenced that analy sis used in the MATS rule and noted that only 50 MW of coal capacity had been retired as of February 2014 as compared to the higher EPA estimates. Citing multiple6
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studies of natural gas demand, the commenter stated that EPA policies that force the retirement of coal base load power plants, such as EPA's proposed NSPS, pose a permanent structural barrier to assuring the el ectric grid remains diverse enough to minimize both reliability crisis and higher and more volatile prices that reverberate throughout the economy writ large. **Response 6.3 -**  **426:** The commenter is incorrect in stating that the standards set b y this rule “force the retirement ” of coal power plants or any generating capacity . The standards for new sources under 111(b) only impact newl y constructed generating capacity and have no bearing on existing generating capacity
. 

### 6. **3 .**  **8 Effect of the Proposed NSPS Rule on CCS Development,**  **Demonstration and Deployment**  **Comment 6.3 -**  **427:** Commenter 9033 asserted that requiring CCS for coal has the potential to distort the market because the extreme capital cost of the CCS equipment and additional operating cost, as documented b y the NETL studies, making NGCC more competitive than coal with CCS. **Response 6.3 -**  **427:** NGCC is already significantly more competitive than coal. See RIA chapter 4. Preamble section V.I.4 addresses the issue of whether the incremental cost of partial CCS could make new coal uncompetitive with NGCC, considering current and forseeable market conditions. **Comment 6.3 -**  **428:** Commenters 9592, 9683 and 10095 stated that imposing a mandate before CCS is ready

will result in project developers choosing a technology that is proven and has lower cost, which reduces the potential market for CCS technology developers and may

result in an abandonment of the CCS technology
. Commenter 9592 also provided a reference that IEA's 2012 Technology

Roadmap for High
- Efficiency Low Emission Coal
- Fired Generation stated that wide international deplo yment of ultra
- supercritical and advanced ultra
- supercritical units must precede the widespread deploy ment of CCS technology
. Commenters 8032, 9196, 9426 suggested that the proposed rule will actually slow the development of CCS and other clean coal technologies. The commenter insisted that creating a mandate will have the effect of forcing out investment and research into developing technologies and practices because they are not contemplated by the EPA rule. Commenters 9505, 10031, 10088 suggested that instead of encouraging development, the requirement for the deployment of partial CCS will foreclose further demonstration projects of this technology

at commercial power plants. The commenter further noted that significant penalties for noncomplianc e discourages [practically prohibits] any

future investment in such units. At a minimum, the commenter believes the mandate will significantly delay deplo ym ent of a cost effective and commercially available CCS technology
. Commenter 10046 stated that the availability , or lack thereof, of alternatives to building coal units with CCS systems is a key consideration in determining whether a mandate will force, and thereb y promote, the technology's development, or consign it to the dust bin. The commenter6
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further suggested that since EPA proposes to require that new coal plants add a technology that is decidedl y immature, the inevitable response will be to build new gas units exclusively
. Commenters 1959, 9407, 9471, 9194, 9596, 10500, 10952 stated that mandating CCS for new coal
- fired power plants before the technology is commercially

viable and adequatel y demonstrated could ultimately impede, rather than accelerate, its development. Commenter 10500 stated that hindering develop ment of CCS at home will increase worldwide emissions of CO 2 . **Response 6.3 -**  **428:** These comments are at odds with historic developments of a regulatory requirement spurring massive technological innovation and development. See preamble section V.L . The EPA notes that CCS technology is further developed than FGD scrubber technology was in 1971 when EPA based a standard of performance on that technology as BSER, and for this reason (among others) regards comments such as those of commenter 1959 as misplaced. **Comment 6.3 -**  **429:** Commenters 9326 , 9472 and 10095 listed several reasons why EPA should not base the standard for coal on CCS technology , including that the proposed NSPS will effectivel y ban new coal
- fueled power plants and therefore a more efficient second generation CCS will likely

nev er be demonstrated in the U.S. Commenter 9472 stated that overcoming challenges such as available space for CCS, proximity to pipeline infrastructure, suitable storage or EOR availability

has limited and will likely continue to limit the opportunity to dem onstrate second generation CCS on existing coal plants. Therefore, the commenter asserted that EPA is mistaken in stating that the standard serves as an incentive for future CCS technology development. Commenter 9326 also stated that the proposed rule elim inates the potential for modernizing the coal
- fired power fleet with modern high
- efficiency super - and ultra
- critical pulverized coal boilers. Commenters 8024, 10046 stated that this regulation will essentially stop the development of CCS. The commenter n oted that without new coal plants, it is unlikely technology

developers will continue to invest in CCS develo pment. Commenters 8024, 10036 noted that since the proposed regulation provides a significantly lower cost alternative (NGCC without controls) to the application of CCS to coal, there is unlikel y to be a market for at least 10 years, and most R&D cannot be sustained for that long. Commenter 10046 stated that the EPA should withdraw its proposal. **Response 6.3 -**  **429:** See preamble section V.I.4. Issues of siting availab ility are addressed in preamble section V.M. and the Geographic Availability TSD. **Comment 6.3 -**  **430:** Commenters 8501, 9201, 9422, 9734, 10036, 10243 asserted that EPA is providing a disincentive and likely freezing any

new investments in the development and deploy ment of CCS by

offering the choice between CCS
- controlled coal units and uncontrolled NGCC units.
. Commenter 10243 stated that without a strong financial mechanism to support CCS, the proposed standard does not allow for R&D time that will provide confidence to investors.6
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Commenters 9201, 9426 stated utilities are effectively barred from developing CCS projects by the combination of EPA's regulatory requirements, their need to respond to the fundamental economics and concerns of providing affordable power, the continued availability of the option to build NGCC units without any carbon constraints, and because utilities do not value fuel diversity simply for the sake of being diverse. As a result, the commenter asserted that coal generation is not incentivized to a chieve higher efficiency potential such as ultra
- supercritical coal, and the deploy

ment of CCS will vanish along with America's ability to be a leader in CCS development in the future. Commenter 9033 noted that in today's market of moderate natural gas pri ces, it is very unlikel y that any commission will allow the recovery of development costs on existing plants based on a new plant rule that allows uncontrolled natural gas alternatives that are obviously less expensive. Commenters 9326, 10036, 10046, 10880 stated that the regulations do not reflect the current status of the proven economic viability of CCs technologies for deploy ment across the broad range of coal generating equipment. The commenters noted that this creates a situation where it is highly unlikel y that power producers will be able to justify the financial risks associated with building a high
- efficiency power project without the assurance that the technology can meet the new standards. Commenter 10046 stated that a CCS
- based emission rate st andard such as the one proposed b y EPA will in fact lead to a delay in CCS investment, and consequently , will not promote the development of CCS, but retards it. The commenter further noted that since much of the US power industry

operates in deregulated m arkets, the financial risk concerns identified with CCS will hinder development of the technology in these markets. Commenter 10046 stated that a CCS mandate moves the CCS technology risk to cover the entire EGU, because the plant cannot be operated except in compliance with the CCS mandate. Commenter 10036 noted that in light of existing, alternative, lower cost fuel options, lack of adequate government cost
- share funding support to accelerated development and lower costs of CCS technology

simpl y extends the time when technology commercialization is probable. The commenter stated that the proposed rule limits investment choices because the timeline for potential return on investments is unknown or significantly extended. Commenter 8501 stated that the propo sed rule will likely defer investment in energy efficient coal based generation. **Response 6.3 -**  **430:** The final rule does not change the fundamentals of wholesale electricity markets. An independent power producer (IPP) developing an electric generation unit in a competitive wholesale electricity market bears the risk when considering whether to develop that resource. The IPP makes a decision to develop the generation based on its assessment of risk and its ability to recover costs through a bilateral contract or the spot market. A verticall y integrated utility, whether operating in an RTOI SO or more traditional market structures outside an RTO/I SO, would be subject to cost
- of
- service regulation by

a state PUC or other jurisdictional regulator in order to obtain cost recovery
. RTOs and I SOs have mechanisms in place to ensure6
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adequate resources to meet demand and reliabl y operate the grid (e.g., capacity and energy market rules that ensure generators have the opportunity to recover their costs, including fixed costs)
. Moreover, as shown in RIA chapter 4 and discussed in preamble section V.H.3, new non
compliant coal capacity is unlikely to be constructed in the foreseeable future for reasons unrelated to the present standard. Commenters 9201 et al. indicate , for example , that e ven ultrasupercritical capacity is not currently

financially

viable. **Comment 6.3 -**  **431:** Similarly, Commenter 8925 asserted their concern about the proposed rule's precedent, which could discourage companies from participating in future technology demonstration efforts b y usi ng onl y two partiall y constructed, government supported technology demonstration projects as a key part of its basis for establishing emission limits. Commenter 8348 stated that as written, the proposed rule will immediately eliminate coal as an option for new power plants with a resulting loss of interest b y the industry in continued CCUS research and development. The commenter goes on to stress the importance of investing in next generation carbon capture technology R&D. Commenters 9426, 10046, 10395 stated that the proposed rule discourages the private sector's willingness to invest in CCS technology development, and without that investment, the technology

may never be commercialized. Commenters 9407, 10952 disagree with the EPA that that "the industry needs a stick" to demonstrate CCS to the point of availability and cost reasonableness. The commenters stated that the projects EPA cites in the proposal in attempt to justify CCS as BSER all originated without the "stick" that EPA now believes i s necessary . **Response 6.3 -**  **431:** The AEP experience at the Mountaineer project suggests otherwise, when the company cited absence of a clear legal mandate for CO 2 reduction as a chief reason for abandoning the project. **Comment 6.3 -**  **432:** Commenter 9780 stated that only coal
- based units with CC S that receive government funding will be built in the future since the costs of CCS will prevent new coal
based units. Additionally, the commenter stated that current CCS projects will help DOE and private industry

study how to trim retail costs and reduc e costs for second
- generation carbon capture technology , suggesting that the technology is not adequatel y demonstrated. Commenters 10086, 10870 stated that the EPA is not expecting new coal plants to be built until 2022. The commenters stated that with no new plants being built, there will be no demand, or research and development, for CCS technology . The commenter stated that the capital cost cannot come down if there is no wide spread deploy ment of the technology
. **Response 6.3 -**  **432:** Research into CCS is dynamic and on
- going and the EPA does not expect it to cease. See preamble section V.H.8.b. **Comment 6.3 -**  **433:** Commenter 10952 (NRECA pp. 5
- 6) maintains th at a CCS mandate ultimately

would perversely

influence worldwide GHG emissions because of a chilling effect bringing about true CCS demonstration and commercialization. The commenter posits a case6
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whereb y China will add large volumes of new coal capacity, no U.S. domestic coal capacity is added, net CO 2 increases from Chinese coal combustion swamp U.S. reductions attributable to the difference between coal and gas
- fired EGU emission rates, the result being “a missed opportunity

to foster worldwide CCS appl ication, minimal and inconsequential reductions in U.S. CO 2 emissions, and an increase in worldwide CO3 emissions that without this proposal we could have been on tract (sic) to curb significantly going forward.” **Response 6.3 -**  **433:** As it happens, the United States and China have signed a bilateral agreement whereb y China has committed to significant reductions in CO 2 emissions over the next decades. To the extent potential international response to domestic actions is a relevant consideration under section 111 (a), this deve lopment is at direct odds with the commenter’s hy pothetical. **Comment 6.3 -**  **434:** C ommenter 7502 stated that it is evident that the proposed regulations would spur further innovation and investment in such technology [low carbon technologies] in the near future. Commenter 903 5 stated that the combination of a regulatory driver and financial support is needed to spur investment in CCS projects. The commenter suggested potential funding mechanisms. Commenter 9035 stated that Public Service Commissions have been reluctant to approve CCS construction, but should be more willing to approve ratepayer cost recovery for CCS projects if there is regulatory

certainty
. Commenters 9035, 10103 stated that in order to support a diverse set of affordable low
- emitting sources of electricity, further research, development and demonstration of CCS is needed. Commenter 9035 stated that the proposed rule should be assessed on its effectiveness in supporting, and not inhibiting, the deplo ym ent of carbon capture, CO 2 - EOR, and other carbon
cutting te chnologies. Commenter 10103 asked that the EPA ensure the CCS technology is appropriatel y proven and available for use. **Response 6.3 -**  **434:** The EPA largel y agrees with these comments, which provide support for the proposition that a regulatory standard promotes development o f the new technology on which it is based. 

### 6.4 **PROPOSED EMISSION L IMIT OF 1,100 LB**  **CO 2** 

### /MWH **Comment 6.4 -**  **1:** Several commenters (0784; 1902, 2471, 3236; 8957, 9033, 9192, 9472, 9497, 9602, 9678, 9725, 10050, 10085, 10097, 10104,10395, 10504, 10552, 10680; 10974; 11062; 1097 5; 11063; 10963) stated that the proposed limit of 1,100 lb CO 2 /MWh for coal based EGU is not achievable. One commenter ( 9033) stated that based on heat rates projected for IGCC and USC on lower rank coals, the 1800 lb/MWh standard is unachievable. The co mmenter provided a table of expected CO 2 emissions for selected US fuels for a modern PC power plant operating at full load conditions that shows that the 1800 lb/MWh limit may be achievable at full load conditions for bituminous coals, barely

achievable f

or subbituminous coals, and unattainable for lignites.6
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According to the commenter, the unavailability of CCS means no new units could even be considered. Two commenters (9497
- 5231; 10104
- 4644) stated that CCS has not yet been commerciall y proven and that s etting the standard at the current proposed level of 1,100 lbs/MWH will effectively ensure that no new coal
- fired plants are built, including promising high
- efficiency

technologies that would in themselves reduce CO 2 output, such as ultra
supercritical power plants. The commenter (9033) stated that EPA set the standard for theoretical best performing units in only two classes and fails to account for the change in heat rates of units that will occur and cause them to exceed the limit. According to the commenter, all combustion equipment incurs an increase in heat rate with time and operation and it is conceivable that units meeting the requirements when new will fail the standard over time. Commenters (9033, 9472) cite the following factors as impacting plant heat rate, and thus CO 2 emissions, making the proposed EPA limit difficult to achieve: Partial L oad Operation. Net plant heat rate increases as the plant operating load is reduced, with a corresponding increase in the specific CO 2 emissions. Base load Operation. All power plants have load variation that impact a plant's heat rate and CO 2 emissions. Cycling Operation. A typ ical PC cycling plant may operate 30% of the time at 100% load, 55% of the time between 50
- 7 5% load, with the balance at lower loads. The average capacity would be about 70% and the plant would have an average heat rate about 4
- 5% higher than at 100% load. Degradation Due To Plant Age. Normal wear and tear is to be expected which has an impact on the plant heat rate. Site Factors. Other factors can have a negative impact on plant heat rate and CO 2 emissions. For example, areas with limited water resources could require an air
- cooled condenser vs. water cooling. Local water temperature can also hav e an impact on condenser operating pressure and heat rate. The commenter (9033) provided a table summarizes the impact of an increase in plant heat rate due to the above factors on the specific CO 2 emissions for a state
- of
- the
- art USC PC power plant. A plant that is required to cycle would likel y have a heat rate 5% higher than its design 100% load heat rate. It is likely that the bituminous plant would also exceed the limit when site specific factors, impacts of startup, shutdown, and age deterioration are also factored in. The cycling impact could be more significant in the future as renewables assume a larger portion of total power generation. One commenter (10100
- 1182) stated that the use of cycling units is increasing and do not have the efficiency of b aseload units. According to the commenters (9033, 10085), the Clean Air Markets Database used b y EPA to support the proposed 1800 lb CO 2 /MWh limit shows that while there were a limited number of plants that met this target, the bulk of the reporting plants exceeded it by a wide margin.6
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The commenter (9033) compares the 4 SCPC plants that the EPA cited in justifying the proposed 1800 lb CO 2 /MWh target. What stood out was the high capacity factor for these four plants. The commenter stated that they were clearl y operating as base load plants, with capacity factors in the mid 80% for three of them and that none of them would have met the proposed target if they operated as ty

pical cycling units. The commenter (9033) notes that EPA states that marginal units can achieve the standard b y applying improvements, such as double reheat, coal drying (for lignites), and cofiring with natural gas. These modifications all add additional equipment at the expense of increased capital/operating cost and potentially decrea sed availability

and makes coal
- fired technology less competitive. Because permits are customarily permanent, the commenter (9033) stated that setting an output standard based on "as new" performance values for equipment that is known to lose efficiency ov er time will ensure that eventuall y no plant will meet its permit limits. One commenter ( 9472 ) stated that EPA should not base a standard for coal on CCS technology and should withdraw the proposed NSPS. The commenter provided information showing the proj ected CO 2 emission rate that would result in one exceedance in 10 and 20 years for each boiler category

(lignite, subcritical and supercritical). The commenter recommended the following emissions rates:
- 1,915 lbs CO 2 /MWh for supercritical boilers burning bituminous and subbituminous coals;
- 2,080 lbs CO 2 /MWh for subcritical boilers burning bituminous and subbituminous coals; and
- 2,150 lbs CO 2 /MWh for all boilers burning lignite coals. The commenter (9472) provided the following data:

- emissions data for s ubcritical and supercritical units firing PRB and eastern bituminous coal and at levels greater than 1,800 lbs/MWh.

- the relationship between annual CO 2 emitted and average heat throughput with the lowest emissions achieved at the highest heat throughput. The data for one unit show CO 2 emissions increasing almost continuously as heat throughput decreases, with recent data exceeding 1,800 lbs/MWh for the least heat throughput.

- full, high and low loads showing that for most units CO 2 emission rates increase when operating at less than maximum load and that CO 2 emissions can increase b y 100 lbs/MWh and in some instances b y as much as 200 lbs/MWh.

- the cumulative distribution of CO 2 data at or below a given CO 2 rate for three categories of EGU units: subcriti cal, supercritical and lignite
- fired boilers, comparing fuel ty pe (i.e. bituminous coal or subbituminous coal). Several commenters ( 6870 ; 9190 ; 9192 ; 9497 ; 9590; 9725; 6649; 10097 ; 10104 ; 10395 ; 10501 ; 10552; 10680) stated that EPA has proposed for new coal EGU' s a standard (1,100 lb CO 2 /MWh) that no existing coal base load EGU can achieve
- not even the newest demonstrated coal technologies such as supercritical pulverized coal (SCPC) and integrated ga sification combined cycle (IGCC). The proposed emission standard is at least 40 percent lower than the performance level that is achievable b y these demonstrated coal technologies. One commenter (9678
- 765) stated that EPA cannot promulgate a standard lower than 1,200 lb CO 2 /MWh if that6
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standard cannot be achieved by adequatel y demonstrated technology. Commenter (10504
- 3606) stated that new IGCC generation has an estimated emission rate of 1,700 lbs CO 2 /MWh, which far exceeds the proposed standard of 1,100 lbs CO 2 /MWh for coal
- fired units. Several commenters (1902; 8349; 9602; 9774 ; 10043; 10083 ; 10555; 10665 ) stated that the new coal limits cannot be met with the latest generation technology including those new coal technologies in Europe. The commenter has provided EPA the last 7 years of new plant information that demonstrates that none of these coal
- fired plants come close to meeting the 1,100 lb/MWh limit. EPA should withdraw and re
- propose the NSPS rule and set the standard based upon a new coal plant of 1950 lb/MWh, which is achievable. A limit of 1,950 lbs. CO 2 /MWh would make the rule consistent with demonstrated supercritical and ultra
- supercritical technology . No new coal plant could achieve a limit of 1,100 lbs CO 2/MWh without the use of CCS and no f

ull scale, commercial coal
- fired power plants operate in the U.S. with this technology
. Several commenters (2471; 8974; 10024; 10393) suggested a 1950 lb/MWh emission standard. One commenter (2471
- 4198) stated that this would still be technology
- forcing. E PA should consider allowing an EGU to meet part of the limit through financial carbon
- reduction mechanisms or instruments, such as through the purchase of Renewable Energy Credits. One commenter (7977) stated that EPA consider 1,700 lbs CO 2 /MWh as the lim it for coal
- fired boilers. This emission limit would accomplish nearly 20 percent CO 2 emission reductions compared to the national average of 2,100 lbs CO 2 /MWh for the current U.S. coal
- fired fleet. This standard is being achieved b y only the cleanest and most recentl y commissioned coal
- fired units in the nation, setting an aggressive target for new generation and requiring technology advancement through the New Source Review program. One commenter (9678) stated that EPA has not defined why reductions on th e level of those that could be achieved b y IG CC, supercritical, or ultra
- supercritical units are not significant. EPA does not explain why

a reduction of 700 lb CO 2 /MWh is significant, while a reduction of 400 to 500 lb CO 2 /MWh is not. Nor does EPA explain how this determination relates to the anal ys is contained in the RIA for the proposed rule (e.g., that, overall, the proposed standards will result in negligible reductions in CO 2 emissions). Thus, EPA's decision to consider only technologies that can achi eve an emissions standard of 1,200 lb CO 2 /MWh on a gross output basis does not appear legall y defensible. One commenter (9592
- 732) stated that EPA should have compared SCPC emissions to the ty pical CO 2 emissions rate of existing coal
- fired generating units . The CO 2 emission rates of a new SCPC unit are significantly lower than the typi cal existing coal
fired EGU and would meet EPA's desire for significant CO 2 emission reductions as shown by the table below. One commenter (10017; 10050) stated that EPA uses two distinct approaches for developing standards for fossil fueled EGUs. The standard for NGCC technology is based upon actual emission data while the standard for coal base load technology is based upon calculations for hy pothetical coal units using unpro ven CCS technologies. Consistent methods should be used for determining the proposed standards. One commenter (10050) stated that EPA rejects basing a coal base load plant standard on SCPC and I GCC as not providing as much emission reductions as practicabl e. The reductions achieved are real, substantial and as much as practicable with adequatel y demonstrated technology. For NGCC technology , EPA does not attempt to seek as6
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much reduction as practicable and instead allows emission levels 20 percent higher tha n the levels achieved b y the best performing units. EPA's different approaches in setting the coal and natural gas standards cannot be reconciled and, as a result, are unreasoned and arbitrary. One commenter (8937) stated that the proposal fails to establi sh a workable pathway for coal. Rather than restrict construction of coal fired EGUs to those that are fortunate enough to receive sufficient government assistance, EPA should set a standard that allows efficient coal based EGUs to be built while the CCS t echnology is being full y developed into a stand
- alone economicall y viable technology . As EPA has indicated on its' Clean Energy Site, the average CO 2 emission rate for coal fired EGUs in the U.S. is 2,249 lbs CO 2/MWh. That figure should be the starting point for establishing an interim target for new coal fired units while CCS is being fully developed and deployed. Two commenter (9736; 10876) stated that the proposed rules, when examined based on high heating value (HHV) heat rates
- appear to favor one CT design over another, which seem to preclude at least the frame
- design option from consideration for future capacity additions. This "disfavoring" of frame
- design units is short
- sighted as the optimum design for most NGCC units is based on use of both a frame
- design CT and a heat recovery steam generating (HRSG) unit. As EPA is apparentl y favoring NGCCs for new generation, this presents a dilemma for smaller entities that need additional generation: a near
- term solution to power supply needs
- absent the aforementioned "disfavoring"
- could be to install a frame
- design CT, with the goal of "stepping up" that unit to an NGCC unit at a later date b y adding a HRSG unit. In this fashion, the initial costs of installing new capacity would be lower, and power su ppl y capacity could grow as the community's needs grew. A higher standard be established that would not preclude frame
- design units. One commenter (0784) stated that EPA inadequately considered the total amount of carbon currentl y being released into the atmosphere with the closing of older coal
- fired electric generation units and the retrofitting of others. One commenter (9497) stated they have lignite reserves that may be amenable to UCG with CCS and reinjection back into the coal seam or use in EOR. EPA' s proposed rule would inhibit further research and development of this potential energy source by

setting an initially

insurmountable hurdle in the 1,100 lb/MWh CO 2 emission standard. This is a clear example of the potential innovation
- stifling impact of the proposed rule. UCG may represent a valuable technological path, but with a stringent CO 2 limit in place, there may be no viable way

to start on the path without violating the standard. The commenter requests that EPA modify its proposed rule to allow fo r RD&D and scale implementation of alternative coal based technologies, including UCG. One commenter (9723
- 6902) stated that a limit of not less than 2,200 lb/MWh should be considered b y the EPA for lignite coal
- fired EGUs. One commenter (0784) encouraged EPA to phase in carbon emission standards for new coal
fired generation units based on the best available proven technologies and suggested that 1,800 lbs/MWh is an appropriate initial point. One commenter (10618) stated that the rates being considered by EPA (1,000 to 1,200 lb/MWh) have not been proven to be technically feasible and have certainl y not been adequatel y demonstrated for coal
- based electric generation technologies. The commenter recentl y completed6
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construction of an ultra
- supercritical unit , which is employing state
- of
- the
- art advanced coal technology . Based on the subbituminous fuel used, the projections for load fluctuation and periodic unit startups, operations to date, and available information regarding equipment degradation over a unit s operational life, the commenter estimates that an annual gross CO 2 emission rate of 1,900 lb/MWh would incent the development of more highly efficient generation technologies, while properl y balancing the other factors (including costs) associated with the determination of the BSER. Commenters (9665; 10098) supports EPA's proposed compliance option under which utility boilers and IGCC units could average emissions on an 84
- month rolling average basis. Any source choosing the 84
- month alternative standard would be continuously mindful of the source's obligation to meet the standard over the long term. It would be highl y unlikely that a source would intentionally

operate a unit at less than the optimal level it could practically achieve since any "excess" e missions would need to be made up in later years of operation. A source that operated above the standard would be required to underrun the standard b y at least the same amount over the same period of time that it operated above the standard. Therefore, EPA should not establish an 84
- month alternative standard at a level lower than 1,100 lb. CO 2 /MWh. It is also unnecessary

for EPA to establish an upper limit on CO 2 emissions under the alternative standard, or to require compliance with the 12
- month standard. Again, a source is ultimately penalized under the 84
- month alternative standard if a unit exceeds the required standard by needing to offset the excess emissions with emission levels commensurately lower than the standard. This provides sufficient incenti ve for regulated sources to not exceed standards indiscriminately , but only where justified. One commenter (8024) stated there is no rational basis in climate change policy for exempting CO 2 emissions from natural gas generation while penalizing coal
- based generation with uneconomic NSPS. Comprehensive global climate modeling anal ys es show that methane leakage from natural gas exploration, production, transport, and generation processes can offset all or more of the CO 2 differential between coal and gas gen eration. The proposed rule is fundamentall y unsound for this reason. **Response 6.4 -**  **1:** The premise of most of these comments is that SCPC or I GCC boilers, operating alone, cannot achieve the proposed standard of performance, and because CCS is not feasible, this means these units cannot achieve the standard. CCS is in fact demonstrated and feasible, and the final standard of performance can also be achieved b y alternative means not involving CCS. **Response 6.4 -**  **2:** This final standard of performance for newl y constructed fossil fuel
- fired ste am generating units provides a clear and achievable path forward for the construction of such sources while addressing GHG emissions and supporting technological innovation. The standard of 1,400 lb CO2/MWh
- g is achievable b y fossil fuel
- fired steam generating units for all fuel ty pes, under a wide range of conditions, and throughout the United States. **Comment 6.4 -**  **2:** Two commenters (1624; 9423) favor an efficiency based standard. One commenter (9423) stated that EPA did not appropriately consider an efficiency
- based standard for PC and circulating fluidized bed (CFB) units but the standard for NGCC turbines is precisel y a standard based solel y upon efficiency . The heat recovery portion of a NGCC unit does not6
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reduce emissions, but instead improves efficiency in producing electricity

(or steam) b y extracting heat from the exhaust gas. EPA has relied upon defining an effi ciency level for NGCC units as BSER, yet rejects defining a standard based upon efficiency measures for coal
- fired EGUs. The commenter also stated that EPA is applying an emission standard based on combined cycle turbines to a completely different source ty

pe of EGU. IGCC units, the basis for the 1100 lb CO 2 /MWh limit, should be either listed as a separate source category or the BSER standard for IGCC should be listed in Subpart KKKK, because the source of emissions is from the combined cycled turbine and n ot the gasifier. Combined cycle turbines generally produce more electrical output per the same amount of fuel burned in an EGU that utilizes a simple steam cycle to produce electricity, because the combined cycle uses the steam cycle and a mechanical cycle to produce electricity. The claim that NGCC is inherently lower
- emitting is completely a function of the basis of the standard that EPA chose, which is an output based standard of lb C02/MWh. EPA is stacking both CCS and an "inherentl y lower emitting unit ," a combined cycle turbine, to establish an output based emission standard that EPA is erroneousl y appl yi ng to a completel y different source type of EGU (subcritical, supercritical pulverized coal boilers, and circulating fluidized bed units). One commenter (9426) stated that the EPA has proposed to apply to pulverized coal ("PC") units the 1,100 pounds of CO 2 per megawatt hour ("lb CO 2 /MWh") standard, which is based on technology

applicable only

to IGCC units. Any

standard that applies to PC units based on a finding that it is achievable with a technology that only I GCC units can use is also contrary to law. **Response 6.4 -**  **3:** Commenter 9426 states that the standard of performance can onl y be met using a technology

suitable only

for IGCC. The commenter is incorrect. Both pre - and post
combustion CCS are demonstrated technologies. This final standard of performance for newl y constructed fossil fuel
- fired steam generating units provides a clear and achievable path forward for the construction of such sources while addres sing GHG emissions and supporting technological innovation. The standard of 1,400 lb CO2/MWh
- g is achievable by fossil fuel
- fired steam generating units for all fuel types, under a wide range of conditions, and throughout the United States. Comments regarding there being “no requirement for emission reduction” have been addressed elsewhere. **Comment 6.4 -**  **3:** One commenter (10100) stated that, assuming that EPA finalizes a standard for coal
- fired EGUs based on partial CCS, they support a standard of 1,200 lb CO 2 /MWh for fossi l fuel
- fired utility

boilers and IGCC units. These standards are within the ranges proposed b y EPA and more accuratel y account for unit cycling, performance degradation, and other factors. If EPA does not adopt the higher performance standards, EPA shoul d consider a sliding scale based on generation thresholds to determine the performance standard for EGUs on an individualized basis. For example, the highest limit should apply to units operating at low capacity factors (i.e., in the 33 percent to 45 perc ent range). The emissions limit could be reduced incrementall y as the generation threshold increases. **Response 6.4 -**  **4:** The final standard of performance is less stringent than this commenter recommends, and so provides a greater degree of flexibility
. This final standard of performance for newl y constructed fossil fuel
- fired steam generating units provides a clear and achievable path forward for the construction of such sources while addressing GHG emissions and6
- 264

supporting technological innovation. The standard of 1,400 lb CO2/MWh
- g is achievable b y fossil fuel
- fired steam generating units for all fuel ty pes, under a wide range of conditions, and throughout the United States. **Comment 6.4 -**  **4:** One commenter (8957) stated separate emission limits must be established for e ach type of fossil fuel
- fired units. Additionally , dual fuel capability should be more adequatel y addressed for boilers and turbines. The requirement for a turbine to burn at least 90% natural gas to be an affected source needs to be removed. Most turbines are capable of firing multiple fuels without major modifications, so a turbine can simply fire 11% petroleum or other fuel to completely

avoid the regulation. EPA should set a performance standard of 1,000 lbs C02/MWh (gross) or 1,050 lbs C02/MWh (net) on a 12
- month annual average basis for NGCC and 1,800 lbs C02/MWh (gross) or 1,925 lbs C02/MWh (net) on a 12
- month annual average basis for coal
fired units. After it becomes an economically feasible control technology , CCS will become the BACT to reduce C02 emissions for both coal
- fired and natural gas
- fired power plants that are subject to the Tailoring Rule. The commenter agreed with EPA that NSPS should be the floor for determining BACT and when it becomes an economically feasible control technology , CCS will become the BACT for PSD permits. One commenter (10043) requested that EPA increase the emissions limit for new NGCC units from 1,000 to 1,250 lbs. CO 2 /MWh. While it is possible to purchase a new NGCC unit that meets the 1,000 lbs CO 2 /MWh threshold in the short term, it is unclear whether new NGCC units can sustain that high level when used to firm up delivery of wind and other intermittent generation sources One commenter (1009 5
- 2618) stated that for NGCCs, EPA must set an emissions limit that is achi evable and considers economic
- , environmental
- , and energy
- related impacts. EPA must explain how the standard is achievable under the most adverse conditions which can reasonably be expected to occur. Historical operating data show that many units operate above the proposed standard when experiencing adverse conditions. Also, the proposed standard is constricting considering the wide operational variability NGCCs experience over the units' lifespan and does not represent the best balance of economic, enviro nmental, and energy considerations. Finall y, EPA has created unintended consequences b y providing rolling three
- ye ar average applicability criteria. **Response 6.4 -**  **5:** This final standard of performance for newl y constructed fossil fuel
- fired steam generating units provides a clear and achievable path forward for the construction of such sources while addressing GHG emissions and supporting technological innovation. The standard of 1,400 lb CO2/MWh
- g is achievable b y fossil fuel
- fired steam generating units for all fuel ty pe s, under a wide range of conditions, and throughout the United States. See preamble section V.J and the ‘Achievability’ TSD available in the rulemaking docket. **Comment 6.4 -**  **5:** One commenter (7990) stated that EPA base the applicability requirements on the source's design and purpose prior to completion, because new EGUs must know what performance standards will apply to them during the licensing process. New EGUs undergoing New Source Review should be allowed to accept limits in operating permit conditions in order to remain below the Propose Rule's applicability provisions. This methodology is consistent with the current approach under the Title V program.6
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**Response 6.4 -**  **6:** The commenter is mistaken. The NSPS applies immediately
. This final standard of performance for newl y constructed fos sil fuel
- fired steam generating units provides a clear and achievable path forward for the construction of such sources while addressing GHG emissions and supporting technological innovation. The standard of 1,400 lb CO2/MWh
- g is achievable b y fossil fuel
- fired steam generating units for all fuel ty pes, under a wide range of conditions, and throughout the United States. **Comment 6.4 -**  **6:** One commenter (10119) stated that EPA fails to establish that fossil fuel
- fired boilers and IGCC facilities cannot achieve an emissions rat e lower than 1,100 lbs CO 2 /MWh for coal
- fired EGUs, which is based on a 25% CO 2 capture rate at a new IGCC facility . According to the commenter, using the same technology necessary

to capture 25%
- a single
- stage water - gas shift ("WGS") reactor and two
- stage acid gas removal sy stem - a facility would be expected to achieve a CO 2 emission reduction of up to 75%, or an emissions rate of approximately 380 lb CO 2 /MWh
- gross. The commenter stated that according to the proposed rule, an IGCC facility using this te chnology

thus could dial in a far greater amount of CO 2 capture and achieve a far lower CO 2 emissions rate than EPA has proposed. EPA's proposed emissions standards do not reflect a minimal 25% CO 2 capture rate and lack support. One commenter (10394
- 1700) stated that their state has established emission performance standards (EPS) at 1,100 lbs CO 2 /MWh of electricity for local publicly

owned electric utilities, which, unlike EPA's proposed limits, also applies to existing utilities, and in general includes e missions from boilers, combustion turbines, reciprocating or other engines and fuel cells. The commenter stated that the emission limit for large natural gas
- fired units (those with a heat input threshold greater than 850 MMBtu/h) should be more stringent than EPA proposed. The commenter recommends an emission rate limit of 950 lbs CO 2 /MWh. According to the commenter, several permits recentl y issued for large natural gas
- fired units have been for projects with lower emission rates and a recently permitted 1
- on - 1 combined cycle unit will meet the limit of 950 lbs CO 2 /MWh. The commenter stated that the limit for the smaller combined cycle units (heat input rating below or equal to 850 MMBtu/h) should be more stringent than proposed and be set at 1,050 lbs CO 2 /MWh. Based on the commenter's experience, the smaller combined cycle units can be less efficient than the larger turbines; however, their overall efficiency will still be higher than the simple cycle units. The commenter has recently permitted a 1
- on - 1 combined cycle unit that will meet the lower limit of 1,050 lbs CO 2 /MWh net (gross output), 12
- month rolling average, inclusive with manufacturer turbine degradation. **Response 6.4 -**  **7:** This final standard of performance for newl y constructed fossil fuel
- fired steam generating units provides a clear and achievable path forward for the construction of such sources while addressing GHG emissions and supporting technological innovation. The standard of 1,400 lb CO2/MWh
- g is achievable b y fossil fuel
- fired steam generating units fo r all fuel ty pes, under a wide range of conditions, and throughout the United States. **Comment 6.4 -**  **7:** One commenter (9406) stated that although the proposed emission limit for coal
- fired EGUs is based on the emissions reductions that can be achieved through CCS, EGUs are permitted to meet those standards using any combination of means. Although no new coal
fired EGUs are being planned, before the drop in natural gas prices, many states, including Pennsylvania, had informed developers that new coal
- fired plants would need t o be built to carbon capture ready standards. If a developer wanted to build a new coal
- fired power plant for6
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purposes of energy

diversity, it could readil y design it as a carbon capture ready plant and employ a wide variety

of other means already

describe d in GHG BACT determinations to achieve the proposed 1,100 lb CO 2 /MWh performance standard. For instance, many existing coal
- fired plants can co
- fire coal and natural gas to reduce emissions rates. Coal
- fired plants can also use biomass fuels produced b y s intering and other processes to reduce GHG emissions. At least one natural gas combined cycle plant combined solar power to reduce its overall GHG emissions produced per megawatt hour. A carbon capture ready supercritical coal
- fired unit, coupled with a hi ghly

efficient NGCC unit, solar, or wind capacity and using partial biomass fuel could likely

be designed to meet the proposed standard of performance. EPA could consider these alternative means of meeting its proposed standard. **Response 6.4 -**  **8:** The EPA largel y agrees with this comment. Co
- firing with natural gas is an alternative compliance pathway for meeting the final standard for both SCPC and I GCC. **Comment 6.4 -**  **8:** One commenter (8020; 8939; 10103 ) supports allowing plant owners to choose either compliance option: 1,100 pounds of C 02 per Megawatt
- hour ("lb/Mwh") over a 12
- operating month rolling average, or between 1,000 and 1,050 lb/Mwh over an 84
- operating month rolling average. One commenter (1900) stated that while a 1,100 lb CO 2/MW h
-gross averaged over a 12
- month operating period seems adequate, perhaps it could be extended to 24 months to give these companies more time to meet this demand. It may also be appropriate to set the limit for the rolling 7
- ye ar average to a stricter amount, perhaps closer to 950 lb CO 2 /MWh. This would cause EGU companies to take more immediate action so they don't have to meet such a strict limitation in the future. By

setting a larger gap between the limitations, more action is likely to be taken in a shorter amount of time. **Response 6.4 -**  **9:** The EPA is not finalizing the option of the 84
- month compliance period. **Comment 6.4 -**  **9:** One commenter (7977) stated that pursuant to Section 111(b) of the CAA, EPA must set an achievable standard for fossil fuel units that: is consistent with Con gressional intent; encourages the use of local fuels; expands energy resources that could be burned in compliance with emission limits; and makes technology and fuel choices less restrictive. **Response 6.4 -**  **10:** The commenter states a number of factors which are not enumerate d in section 111 (a) , including encouraging the use of local fuels, and making technology choices and fuel choices less restrictive. These factors are not part of a best s ys tem of emission reduction, as defined in section 111 (a). **Comment 6.4 -**  **10:** One commenter (9513) s tated that EPA needs to pay attention to detail and cannot forego the opportunity to reduce hundreds of thousands or millions of tons of CO 2 emissions simply

because those opportunities don't generate reductions of hundreds of millions of tons by themselve s. For example, the agency proposes to establish the new emission limitations to two significant digits where 1,000 lbs/MWh is represented as 1.0 x 103 lb/MWh and sources are allowed to round down to comply . This would relax the NSPS by an additional 1
- 5 p ercent (depending on whether EPA allows sources to appl y the rounding to the test results expressed in Imperial (English) or metric units). To illustrate, an emission rate of 1049.99 would6
- 267

round down to 1000 and comply with the proposed limit if expressed in U.S. units. If the determination is in metric units the effect would be smaller. The commenter anticipates that this issue will be highl y controversial, and yet EPA has not analyzed the impact. **Response 6.4 -**  **11:** This final standard of performance for newl y constructed fossil fuel
- fired steam generating units provides a clear and achievable path forward for the construction of such sources while addressing GHG emissions and supporting technological innovation. The standard of 1,400 lb CO2/MWh
- g is achievable b y fossil fu el
- fired steam generating units for all fuel ty pes, under a wide range of conditions, and throughout the United States. **Comment 6.4 -**  **11:** One commenter (10047) recommended that EPA revise the proposed standard for coal
- fired EGUs to a level equal to that met by the very lat est and most efficient units permitted in the United States, and that it continue to monitor the progress of CCS or other CO 2 control technologies, such that if a control technology is shown to be effective and economical in the future, EPA will be positio ned to revise the NSPS as appropriate. Whereas coal
- fired units were originally

designed for an operating life of 35 years, recent history has shown that units can operate as long as 50 to 60 years through life
- extension projects. Thus, there is the specter of half
- century consequences of this NSPS. I f EPA sets the CO 2 standard at a level reflecting efficiency , it must be positioned to revise the standard quickl y should CCS or some other control technology

be shown to be economically viable in the future. O ne commenter (10869) stated that the proposed optional limits (1100 or 1000
- 1050 lb CO 2 /MWh) could potentially allow a plant to implement CCS technology to reduce their emissions after the initial operation date. This approach recognizes the current state of CCS technology

while providing an incentive to make it more widely available on a faster timeline than may have been the case without the carbon standard. The final standard should include firm timelines for power plants to demonstrate that they are usi ng CCS and impose penalties if not implemented on time. The 40% rate of carbon capture implied by this standard is low. Note that installing CCS at a power plant will impose an efficiency penalty that would raise overall emissions. CCS capture rates will n eed to be 85% or more if this technology is to help contribute to U.S. power sector emissions reductions of 90%t or more b y 2050. EPA will need to provide a pathway to a more ambitious level of carbon capture for coal
- fired power plants; otherwise we risk locking in long
- lived carbon
- intensive energy sources. **Response 6.4 -**  **12:** Note that the EPA must review section 111 (b) no later than 8 ye ars, and so will monitor on
- going technical developments, as comment 10047 urges. **Comment 6.4 -**  **12:** One commenter (10606) stated that to provide an opport unity for new natural gas - fired steam boilers to be constructed, EPA should promulgate an appropriate CO 2 emission limit for natural gas
- fired boilers, taking into account the maximum thermal efficiency of such a boiler. Natural gas burning emits CO 2 at a rate of approximately 53 kg/MMBtu, equivalent to 116.7 lb CO 2 /MMBtu heat input. Therefore, an appropriate optional standard, based on heat input, would be 120 lb CO 2 /MMBtu (12 month rolling average) and would account for variations in the heating value and methane content of natural gas. A standard based on gross output would be approximately 1,300 lb CO 2 per MWh (12 month rolling average). This proposed standard would allow the development of natural gas
- fired steam generation in the future, while li miting6
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CO 2 emissions to about one
- half the amount that would be produced with coal
- fired generation facilities. **Response 6.4 -**  **13:** This final standard of performance for newl y constructed fossil fuel
- fired steam generating units provides a clear and achievable path forward for the construction of such sources while addressing GHG emissions and supporting technological innovation. The standard of 1,400 lb CO2/MWh
- g is achievable b y fossil fuel
- fired steam generating units for all fuel ty pes, under a wide range of conditions, and throughout the United States. This standard is applicable to all new fossil
- fuel fired steam generating EGUs

– including those firing natural gas. **Comment 6.4 -**  **13:** One commenter (10606) stated that an auxiliary or backup EGU should be exempt from the CO 2 emission standard. Backup EGUs will be package boilers in almost all cases, due to the relatively low cost of such units. However, a package boiler could not compl y with the proposed limit of 1,100 lb CO 2 /MWh gross output. **Response 6.4 -**  **14:** Applicability issues are addressed in the pr eamble sections III.C and III.D. 

### 6. **4 .1 Achievability of Proposed Standard with CCS Technology**  **Comment 6.4 -**  **14:** Several commenters (9666, 9472, 9650, 10039; 10618; 10552; 10240 ; 10050 ; 10052 ; 8937 ; 9034; 10100 ; 5731 ; 9780 ; 9194; 9592; 9197; 10023; 9397; 8906; 10870 ; 8974 ; 9422 ; 10520 ; 9471 ; 10051 ; 10048 ; 9003 ; 10952 ; 10466 ; 0587 ; 9192 ; 8032 ; 10392; 9780; 10662; 7977; 8971 ) disagreed with EPA that BSER for coal fired EGUs is CCS. Industry , in parallel, the U.S. Department of Energy , along with other public and private effor ts, have recognized that potential CO 2 emission reduction technologies, including CCS for fossil fuel
- based electric generation processes, must overcome significant development barriers if they are to have any chance of becoming a technically feasible and commercially viable control option. No CCS technologies have been demonstrated in a full y integrated end
- to - end configuration at scale on a coal baseload EGU. There are no commercial ventures in the United States that capture, transport, and inject industrial
- scale quantities of CO 2 solely for the purposes of carbon sequestration. Currentl y, there are no commercially viable power plant projects that employ permanent carbon sequestration. Of the examples provided b y EPA in the proposed NSPS, none of the proj ects are currently operating. One commenter ( 9780 ) stated that the only U.S. project already

under construction, Southern Company's Kemper project, has seen significant cost overruns in the past 18 months. None of the other cited U.S. projects have achiev ed financial closure or broken ground, with the exception of the W.A. Parish facility , which chose to commence construction of the natural gas turbines earl y because it made economic sense to do so independent of the CCS project, which is still on hold. No ne of these projects is in operation. Kemper is not only a first
- of
- a - kind project, but also a one - of
- a - kind project. Due to its many site
- specific characteristics, the Kemper project cannot be consistently

replicated on a national level. In its reliance o n the Kemper project, EPA has ignored the unique nature of this project and has not explained how Kemper reasonabl y can serve as a model for other new EGUs in the rest of the country
. One commenter ( 9192 ) hosted a first
- of
- its
- kind project at the Pleasant Prairie Power plant to test a chilled ammonia scrubber technology to separate and capture up to 90 percent of the CO 26
- 269

emissions from a small portion of the flue gas from one of the boilers. The project did not include storage of any captured CO 2 . The proje ct demonstrated that the process was capable of removing 90% of incoming CO 2 from a slip stream of the host power plant's flue gas. The project operated at up to a flue gas flow equivalent of 1.7 MW electric power generation. This project represented an early step in developing a commercial
- scale technology to capture CO 2 emissions from existing coal
- fired power plants. The pilot project confirmed the predicted performance of the chilled ammonia carbon capture sy stem at an operating power plant. To date nei ther this technology

nor any other has been retro
- fitted at full scale at a commercially operating power plant. Therefore, the project did not demonstrate that carbon capture and storage is the best sy stem of emission reduction. One commenter (10618) operated the first integrated CCS project in the world on a coal
- based generation plant. The commenter stated they provided comments on the 2012 proposal to alleviate misconceptions by EPA by placing into proper context the scope and outcome of its CCS program . The current proposed rule continues to misrepresent the scope, results, and lessons learned from the Mountaineer Plant CCS project. In their submittal, the commenter provided a number of qualifications regarding the results of that CCS project. While the project was successful, it is a far cry from being representative of what's required for full
- scale deploy ment. Commenter (10039) stated that EPA's finds CCS as BSER for coal fired EGUs in the absence of any operating data from any CO 2 sources of the size of a pulverized coal EGU (above 3,000 mmBtu/hr heat input). US EPA does not present any data in the rule docket from the ty pe and size of sources it proposes to require to meet the BSER limits of this proposed rule because neither carbon capture nor geolo gi cal sequestration have ever been implemented at a coal fired EGU greater than 100 MW before. One commenter (9666) stated that EPA's achievability determination is not supported by any technical or statistical analy sis of emissions data from units impleme nting CCS because no such data exist. According to the commenter, EPA relies on a 2011 cost and performance report b y DOE that assumes the performance of various CCS configurations and is not based on information gathered from actual operating experience. The commenter further stated that EPA's only achievability

anal ys is is based on its estimates of CCS performance using pre
- combustion CO 2 separation technology , which can be implemented only at IGCC units and that EPA nowhere anal yz es whether the proposed 1,100 lb/MWh limit is achievable for units firing PC. One commenter (9472) stated that EPA is proposing to set a stringent CO 2 performance standard which no new coal
- fueled plant any where in the world has come close to meeting based on CCS technology

that is not adequatel y demonstrated. The commenter stated that the EPA record shows that there are no coal
- fueled power plants in the US
- or even in the world
- that are currentl y operating with a full
- scale commercial application of CCS. According to the commenter, the flaw in the EPA proposal is concluding that CCS is adequately demonstrated based on the assumption that a few planned, but unbuilt, full
- scale CCS project will successfull y demonstrate in the future the effectiveness and reliability of this emerg ing, but unproven technology . The Agency

is proposing to set a CO 2 performance standard based on mere speculation or conjecture.6
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The commenter (9472) stated that EPA cannot base its BSER determination on small or experimental projects that seek to demonstrate CCS at pilot scale, for example, plants at Vattenfall, Germany; Southern Company's Plant Barry ; and AEP sponsored Mountaineer Power Plant. The commenter stated that these pilot
- scale slipstream projects have proven that CCS is a potentially

viable technology

but is insufficient to demonstrate that CCS can be implemented at full
- scale utility

applications. The commenter (9472) stated that EPA cannot base its BSER determination on a few industrial applications of CCS. According to the commenter, none of the industrial projects referenced b y EPA involve the full
- scale commercial application of a CCS technology on a power plant that sells electricity into the grid and therefore cannot constitute an "adequatel y demonstrated" technology

that can be used to se t performance standards for coal
- fueled power plants under section 111(b) of the CAA. For several industrial CCS projects cited by EPA, the commenter described how such facilities differed from coal
- fueled power plants. One commenter (10952) stated that th e proposed NSPS for coal
- fired EGUs requiring carbon capture is not supported by the existing state of carbon capture technology as applied to EGUs, and EPA does not have the discretionary authority to impose it. One commenter (9426) stated that because th e various CCS processes have never been demonstrated together, and because even pilot scale operations have been done on only some of the various coal types and ranks, the industry has limited insight into the effects of combustion, unit operation, and load cycling on the capture plant, which in turn will affect the compression, which in turn will affect the pipeline and injection operation. The lack of operating experience and the impact of different ty pes and ranks of coals are but a few of the unknowns and risks associated with CCS projects. According to the commenter, technologies are in the earl y stage of development or are conceptual and demonstration projects are expected to be initiated in the 2030 to 2035 time period. A demonstration project can take 7
- 10 years to be designed, built, and operated enough to be helpful in the design of commercially deployed replicants and prove that commercializing CCS technology is significantl y more involved than stringing together existing pieces of hardware and de claring victory
. One commenter (9424) stated that CCS, particularly sequestration, is poorly

understood and has known and unknown negative environmental effects. Opposition to enhanced oil recovery (EOR) and hydraulic fracturing would certainl y increase were subsurface inj ection of carbon dioxide expanded to include storage and disposal. The small number and size of carbon dioxide storage projects in operation, often at preexisting oil and gas production sites, do not justify widespread implementation of the technology for sequestration. The commenter disagrees that this circular logic justifies selection of a BSER that is so poorly understood. We respectfully request that EPA increase the proposed emissions limit to 1,950 lbs CO 2 /MWh, while continuing carefully controlled and monitored demonstrations of CCS sy stems. One commenter (10395) stated that EPA should determine that, for pulverized coal facilities, it is not feasible at this time to set a standard of performance. Then, at a future time when CCS becomes an "achievable" and "adequately demonstrated" technology as defined by

the definition of "standard of performance" at Section 111 (a)(1), the Administrator may make a change as set forth in Section 111(h)(4).6
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One commenter (9426) stated that even if CCS were demonstrated to be technicall y feasible, if the many implementation issues are not resolved satisfactoril y, a CO 2 emission standard based on CCS would not be achievable. One commenter (7977) stated that currently , there are no control technologies employe d that allow any new commercial
- scale coal
- fired boilers and IGCC units to achieve the proposed standards. EPA fails to justify its determination and proposed limitations with any real test data that indicate whether a source is capable of achieving compli ance. **Response 6.4 -**  **15:** The commenters are mistaken. Partial post and pre
- combustion CCS is demonstrated at full scale (preamble sections V.D. and E), as is sequestration of captured carbon in deep saline formations. Preamble section V.N. **Comment 6.4 -**  **15:** One commenter (10039) stated that EPA has not accounted for performance degradation of emission units or control sy stems (CCS) in any of the performance standards proposed. The commenter stated that given EPA's position that projects that impact life extension or recapture degraded perfo rmance and/or load at EGUs are modifications, EPA must include expected degradation of these units and control devices over the life of the EGU in its calculation of the achievability of the standard. EPA needs to collect data on the achievability of the s tandards over the entire plant life cycle to determine the achievability of the proposed EGU standards. **Response 6.4 -**  **16:** The final standard is achievable over a range of operating conditions. **Comment 6.4 -**  **16:** One commenter (10555) estimated that transporting captured CO 2 from Milwaukee, W I to Decatur, IL, the closest CO 2 storage site, could cost as much as $405 million. A separate Wisconsin Public Service Commission report estimated that the total cost to construct a pipeline network dedicated to CO 2 transportation could be between $550 mi llion and $1 billion. Both key

energy and environmental regulatory agencies concluded that the transportation component of CCS alone may hinder its commercial viability in Wisconsin. The WDNR notes that the EPA is not projecting the path of technological development for CCS in the reasonable way that is required b y the Clean Air Act taking into account best available control technology determinations. Further, the commenter requests that the EPA amend the currentl y proposed 1,800 lb CO 2 /MWh threshold based on the assumption that a supercritical coal boiler can meet the limitation. Two Wisconsin supercritical coal boilers at We Energies are only achieving an average emission rate of approximately 1,950 lb CO 2 /MWh. **Response 6.4 -**  **17:** See preamble section V.I.5. The EPA’s cost es timates do in fact include costs associated with transportation and storage of CO 2 . Potential GS formations are widel y available in the United States. The EPA recognizes that geologic conditions to support CO 2 storage may not exist in all regions of the co untry . Where such capacity

is unavailable, electricity demand in those areas can be served by coal
- fired power plants built in neighboring areas with geologic availability with generated electricity being supplied via transmission line, see Figure 1 of TSD on geographic availability, or the CO 2 can be transported to available GS sites via pipeline. For other of those areas, coal
- fired power plants are either not being built due to state law prohibition s against building such units, or other6
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available compl iance alternatives exist allowing a new coal
- fired power plant meeting the promulgated NSPS to be sited. There are alternative means of complying with the final standards of performance which do not necessitate use of partial CCS, so any siting difficultie s based on lack of a CO 2 repository

would be obviated. **Comment 6.4 -**  **17:** One commenter (9426) stated that the integration of CCS systems with coal
based generation technologies creates a number of practical development challenges, such as differences in operating philosophi es between a steady- state chemical production process (like CCS) and a dy

namic load
- following process (like power generation). Parasitic energy consumption, phy sical space requirements, power plant integration, and flue gas compatibility all pose obstacles to the capture of CO 2 at a power plant. The reliability of a CCS system could be affected b y problems arising in each CCS process. Because full scale carbon capture, compression and transportation, and storage have not been integrated on a power plant, it is unknown how the three processes will interact. **Response 6.4 -**  **18:** All of these operations are integrated at commercial scale at Boundary Dam, recentl y designated as POWER magazine’s power plant of the ye ar due to successful operation of CCS at full commercial scale. 

### 6.5 **OTHER SUBCATEGORIES Comment 6.5**  **- 1:**  One commenter (9664) stated that while subpart Da applies to new liquid oil
and gas
- fired units, EPA appropriatel y emphasizes coal
- and petcoke
- fired units because no new utility steam - generating units designed to be fired primarily wi th liquid oil or gas have been built for many ye ars and none are expected to be built in the foreseeable future due to the significantly lower costs of building Subpart KKKK combustion turbines. **Response 6.5 -**  **1:** There is no need to subcategorize b y fuel. The standards are achievable across a wide range of operating conditions and fuel ty pes. **Comment 6.5 -**  **2:** One commenter (9321; 10618) stated that EPA must provide special consideration for coal refuse fired units and that the proposed GHG standards would discourage the development of new c oal refuse fired units. According to the commenter, the quality of the coal refuse is highl y variable with the heating value of coal refuse decreasing while the sulfur content has increased. EPA must provide new units with the operational flexibility to burn the wide range of coal refuse and encourage the development of new units. Because of their environmental benefits of coal refuse fired EGU's, EPA should adopt a subcategory for coal refuse fired EGUs. The combustion of coal refuse stock piles results in uncontrolled emissions and abandoned mine sites release methane. The commenter hopes that EPA will continue to see the value of eliminating these uncontrolled emissions by allowing the use of coal refuse as a fuel in EGUs. The commenter recommends that EP A support removing coal refuse piles by either exempting or sub
- categorizing waste coal fired EGUs. An environmental benefit of exempting CFB coal refuse units from the rule would encourage new construction. For economic reasons, such as fuel consideratio ns and plant size, coal refuse EGU's using CFB technology cannot appl y capital intensive carbon sequestration or advanced efficiency (heat rate) technologies to reduce the greenhouse gaseous at the plant sites and should be excluded from the proposed rule. The commenter stated that capture percentages will be extremely difficult to achieve in a CFB boiler6
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burning coal refuse that also injects limestone into the boiler to control SO2 emissions. The commenter stated that EPA should extend special consideratio n for coal refuse
- fired EGUs as they did in the NSPS for SO2, PM and NOx. The carbon sequestration that occurs as a result of the carbonation/mineralization of ash from coal refuse fired units is another example of the multimedia environmental benefits pro vided b y coal refuse fired plants. One commenter (8957) supports an exemption for waste coal facilities given the environmental benefits. If an exemption cannot be granted to waste coal
- fired facilities, the commenter recommends a separate subcategory for this technology . Coal refuse piles naturally combust and burn slowly

emitting C02 and other air pollutants The commenter hs been mitigating this environmental impact b y combusting coal refuse in circulating fluidized bed (CFB) boilers. Since coal refuse pi les produce C02 naturall y, the CFBs generate electric power and steam for use while providing benefits to the economy without increasing the net C02 emissions and the ash generated through this process is alkali in nature, and is often sought for use in re claiming abandoned mines and mine lands. Due to the multiple environmental benefits of remediating coal refuse piles, EPA should establish an exemption for EGU s that burn over 75% coal refuse on an annual basis. The advantages in using coal refuse to create electricity is that a mining waste facility would produce no net GHG emissions in the long term and emissions would be no greater than the short
- term emissions of a combined cycle gas plant. Remediation would stop current and future C02 emissions result ing from the uncontrolled combustion of waste piles. Should an exemption not be granted to waste coal
- fired facilities, the commenter recommends setting limits for bituminous gob and anthracite culm at 2,200 lb C02/MWh (gross) or 2,350 lb C02/MWh (net)
. **Response 6.5 -**  **2:** Th e rationale for not exempting coal refuse
- fired EGUs is in the preamble to this final rule. **Comment 6.5 -**  **3:** One commenter (10554) stated they see no legitimate basis for coal refuse to be subcategorized and they should be treated in the same manner as all other coal
- fired EGUs. One commenter (3862) stated that since industrial units are more likel y to experience load fluctuations and more startup and shutdowns, a review should be made of the available data to determine whether these operational factors for industrial units dictate an exemption or sub
categorization with different limits based on more potential variability
. **Response 6.5 -**  **3:** There is no need to subcategorize by fuel. The standards are achievable across a wide range of operating conditions and fuel ty pes. The rationale for no t exempting coal refuse
fired EGUs is in the preamble to this final rule. This final rule only covers EGUs, not industrial units. **Comment 6.5 -**  **4:** Two commenters (9471, 9780) stated that in determining the appropriate BSER and resulting emissions standards for new fossil
- b ased steam EGUs, EPA should consider fundamental design and process differences between the different units subject to subpart Da. The commenters stated that significant differences in design and operations between IGCC and pulverized coal boilers should b e recognized, as should the differences among coal types. The commenters stated that subcategorizing based on boiler and fuel type would ensure that any resulting standards are achievable. Further, the commenters suggested that any resulting6
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standards coul d not be deemed to be achievable unless EPA could demonstrate that all operating periods, including periods of startup and shutdown, were considered when setting the standards. Several commenter (9777; 10388; 10606; 10618; 10965) stated that EPA should establish separate standards for coal
- fired and gas
- fired units. EPA should establish an NSPS subcategory that is specific to IGCC as these processes are fundamentally different from other coal generation technologies. The commenter describes wh y a separate subcategory is needed and the issues to be considered in establishing a separate subcategory
. **Response 6.5 -**  **4:** The final standard of performance is achievable and adequatel y demonstrated consid ering operation with different types of coal. See preamble section V.J. and Achievability TSD. The final standard is also achievable with an SCPC with partial CCS or co
- firing, and an IGCC with co
- firing of natural gas (or CCS, if the source chooses). **Comment 6.5 -**  **5:** Tw o commenters (10088, 10667) stated that if EPA does not provide a lignite subcategory , operators of these power plants would be forced to forgo maximizing use of this domestic, plentiful, and affordable resource. This will signal the end of such co
- located mine mouth plants as well as the ability to recover potentially

sizable investments in their mines because of the limitations placed on an operator's ability to maintain, expand or add capacity to use these local, domestic, and sizeable fuel supplies. Thi s would be incredibly burdensome on Texas units, which rely

heavily on their lignite reserves. One commenter (9777) citing a study by Cichanowicz and Hein found that coal composition, load factors, boiler design and coal moisture all affect C02 emissions and recommends that coal ty pes should be further subcategorized. **Response 6.5 -**  **5:** The EPA does not agree with this comment. The EPA examines the issue of alternative coal ty

pes in section V.J. and finds that the standard of performance is achievable using any coal ty

pe, an d has accounted for the increased capture rate (and additional cost0 if other
- than
- bituminous coal is used. With regard to use of lignite, lignite drying is a normal technology

which allows efficient combustion of lignite coal. 

### 6. **5 .1 Coal**  **- Fired Projects U**  **nder Development Comment 6.5**  **- 6:**  One commenter (9403) stated that for plants that have proceeded in their development beyond the point when CCS could be incorporated into the plant design (assuming it could be incorporated at all), imposition of a CO 2 standard that depend s on CCS technology would effectivel y prevent construction of the facility. This would result in significant costs to the project investors, both in terms of lost sunk costs and lost opportunity costs. Given that EPA has identified at most three projects that are presently under development, any

reductions in CO 2 emissions achieved would be minimal. This is especiall y true given that any plant that is constructed will be subject to existing source standards EPA promulgates under Section 111(d). The commenter stated that they executed binding contracts for the purchase and erection of the Plant Washington boiler prior to publication of the proposed rule and believes these contractual obligations are more than sufficient to constitute commencement of construction for purposes of the NSPS program. The commenter anticipates that Plant Washington will be an existing source subject to any

existing
- source standard EPA may promulgate under Section 111(d) of the Clean6
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Air Act. The commenter stated that they addressed their permit status in comments (an attachment to these comments) on the previous proposed rule and unlike the previous proposed rule, the current proposed rule would allow Plant Washington to obtain the pollution
- control guarantees necessary

to move forward. The commenter recentl y sought and received an extension of the construction deadline in its PSD permit, which is currently undergoing public comment. EPA should adopt its proposal and create a sub
- category for the three projects identified in the Propo sed Rule, which would allow for development of a site
- specific CO 2 standard based on BSER for each facility
. Regarding EPA's proposal to consider a subcategory for three coal
- fired projects currently under development with construction permits, including the proposed Wolverine EGU project in Rogers City, Michigan, the proposed Washington County EGU project in Georgia, and the proposed Holcomb EGU project in Kansas, one commenter (9666) stated that it is rational for the Agency to exercise its section 111 di scretion by subcategorizing this category and excluding the three coal
- fired power plants that are so far along in the permitting process that this proposal would make it impossible for them to be completed. One commenter (8909) agreed with EPA's proposal [not proposing standards for "transitional units", i.e. fossil fuel
- fired EGU projects presentl y under development that were fully permitted but had not yet commenced construction at the time of the proposal], especially given the sparse universe of potential "transitional" sources. In the unlikely event that any

transitional EGU commences construction, EPA should develop a GHG NSPS specifically for that source. One commenter (10394) stated that EPA's proposed approach will create uncertainty in projects which may

have already

undergone full permitting, but are undergoing financing prior to commencement of construction. The commenter recommends that EPA propose a deadline similar to the GHG Title V Tailoring Rule, so that it provides a future date for an E GU which has been full y permitted, but has not yet commenced construction to become subject to the new standard. Otherwise, the EGU be subject to any GHG standards that EPA develops for existing EGUs. One commenter (9599) supports EPA's decision not to su bject the Holcomb 2 project in Kansas to the proposed GHG NSPS. The commenter submitted background information including actions taken to date, timelines, sunken costs incurred, PSD permitting activities, and contractual activities. **Response 6.5 -**  **6:** See preamble section III.J. **Comment 6.5 -**  **7:** Two commenters (9514; 10119; 2983) did not support the exemption of transitional sources. Commenter 9514 supported EPA's decision to "discard the transitional source classification, to abandon its approach of using sunk costs to determine BSER for these sources, and to apply the proposed standard to plants that are designed to meet it, such as the Texas Clean Energy Project." There is no legal justification for creating a separate subcategory based solel y on "the stage of a source's development." Commenter 9514 noted that "Section 111 does not provide EPA with discretion to establish a special standard for a particular source that cannot be6
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distinguished by

typ e, size, or class." The commenter does not share EPA's apparent concern regarding the extent that [its]own actions related to the MATS rule may have hampered developers' efforts to commence construction provide a basis for special treatment of these sources. As shown above, EPA's actions were not the cause of the developers' delay . Rather, the projects were mired in legal issues and/or have been lacking in investor interest for ye ars - issues entirely unrelated to the MATS rule. In any case, this is not a relevant factor to EPA when making a BSER determination or setting a performance standard. Commenter 9514 stated, "To rely on a forthcoming 111(d) standard as an excuse for exempting certain new sources from a 111(b) standard also creates bad precedent that could be applied beyond the context of this particular rulemaking." Commenter 10119 st ated that there is no factual basis for exemption of transitional sources and results in a lack of notice to the public. Any attempt by

EPA to exempt these transitional sources based on the relative size of its projected investment loss would be perpetuall y behind and constantly

require, as it does here, to rule blindly and without factual basis for some sources. EPA's lack of facts also, by necessity, translates into lack of notice to the public and the inability to comment, automatically invalidating the action for that reason alone. The commenter stated that EPA is not, and should never be, in the business of carving out one
- off exemptions from NSPS standards based on a concept as nebulous as lost business opportunities. Moreover, EPA should not create in centives for the most powerful individual facility owners to seek to exert undue influence over its decisions. Congress has drawn a bright line about who is covered b y proposed new performance standards, and EPA is required to enforce it. Commenter 9514 asked that EPA define the timeframe and process for determining the status of the transitional sources and offered support for the classification of the transitional sources as new sources. The commenter stated that in the final rule, EPA should make clear the process by which it will make this determination, including the time frame for this decision and the opportunity

for public participation. As a number of the Joint Environmental Commenters explained in their 2012 comments on the initial NSPS proposal, state environmental agencies have not been reliable in enforcing EPA's guidance or other authorities interpreting this definition. Indeed, the state of Kansas recently enacted into law a provision that purportedl y gives the state permitting agency authori ty to regulate greenhouse gas emissions from sources under development and requires the state agency to base its regulation on a variety of factors not permitted under the CAA. Given the history of state backing of these plants, including issuance of decis ions later struck down by state courts, it is especiall y inappropriate to rely on the states to enforce the definition here. EPA must therefore make clear both the timeline and process for EPA to determine the final status of these plants. Commenter 9514 offered support that each of the three transitional sources should not be considered existing sources. Overall:

- significant evidence shows that none of these three sources is poised to begin construction at any time in the near future Tw o Elk:6
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- Has a permit that has now lapsed due to lack of construction activity for many years

- Two Elk's 2003 PSD permit has expired due to lack of construction since 2007

- EPA's intention is ambiguous: not mentioned in Federal Register as a transitional so urce but was mentioned in the September 2013 PUD TSD Plant Washington:

- Plant had not commenced construction by April 13, 2012: "the PSD permit authorizing construction of Plant Washington was not final or legally effective until June 15, 2012"

- The reco rd lacks any evidence that P4G has retained an EPC contractor, a necessary first step in designed and building an electric generating unit.

- Ithas not secured contracts to construct the balance of the plant

-Nor has it sought or obtained an NSPS applicabi lity determination form EPA.

- The plant has requested an extension from the Georgia Environmental Protection Division of the commence construction deadline for its preconstruction air permit under the closely analogous provision of the PSD program, acknowl edging in September 2013 that: 1. it had not obtained vendor guarantees 2. it had not secured necessary construction financing 3. it had not completed designs for the plant 4. it had not finalized construction arrangements Holcomb 2:

- Developers assert in February 13, 2013 letter that its sunk costs are sufficient to have 'commence[d] construction but the commenter noted that EPA's regulations defining commencement of construction do not include a developer's sunk cost amount the factor s relevant to such a determination

- Plant has not begun a continuous program of ph ysical construction.

- The Holcomb developers have not received necessary approval from the Rural Utilities Service.

- The Holcomb Project may not commence construction without a valid PSD permit."

- Tri
- State submitted a resource plan update to state regulators in 2012 representing that no new coal
- fired generating capacity
- not the Holcomb project nor any other coal
- fired Facility
- is either needed or expected to be added to Tri
- State's portfolio within the next 20 years. Wolverine:

- Mentioned in Federal Register but has been cancelled [Reference: 79 FR 1461
- 62] **Response 6.5 -**  **7:** See section III.J. **Comment 6.5 -**  **8:** One commenter (10098) stated that because of the unique impact of Section 111(a)(2) on new sources, which are subject to the rule at the time of proposal, this proposed rule is causing harm now. Upon proposal, any new facilities must commit resources to meet the stringency

of the proposed standard. **Response 6.5 -**  **8:** This effect is created b y statute, which fixes an NSPS trigger date, and is not a consequence of anything specific to the present action. **Comment 6.5 -**  **9:** Commenter 10119 pointed out that "transitional relief" from the proposed rule will create many negative incentives, such as discouraging industry from anticipating changes in6
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legal rules, affording exempted facilities relief from regulations with which others must comply , creating an unequal competitive playing field; depriving the public of the regulation's benefits while bestowing a windfall on the exempted facili ties, discouraging early adoption of improved and advanced technology, shielding exempted sources from market pressures that would otherwise promote technological advances and environmental benefits more quickly and broadl y, creating expectations that laws will change or can be avoided; creating disincentives for voluntary and earl y compliance; and rewarding lobbying. **Response 6.5 -**  **9:** See section III.J. **Comment 6.5 -**  **10:** Commenter 10119 stated that while EPA has the authority under section 111(b)(2) to create a new subcategory for Wolverine, Washington County and Holcomb, doing so would create a category because these three projects might suffer opportunity costs arising solely as the result of the specific timing of proposal of the instant new standard. Therefore, the commenter ass erted that no other future project could ever qualify , creating an exemption rather than a subcategory

and retarding rather than encouraging the development of improved technology
. **Response 6.5 -**  **10:** See section III.J. The EPA does not see that exempting plants that may never operate, but if they

do may be unable to meet the standard of performance based on previousl y approved designs, would not otherwise compromise the national standard. As noted in the preamble to the final rule, the EPA would carefully examine whether t hese plants (should they oeprate0 can achieve the standard of 1400 lb CO 2 /MWh.