Either Class VI or Class II wells may be used for the purpose of complying with this rule. This rule does not require Class II wells to transition to Class VI.
Commenters 9472 and 10098 stated that changing well class is a major business decision carrying many long-term financial and regulatory obligations and would likely require an EOR operator to obtain additional property or other legal rights, all of which create significant uncertainty and materially impact an EOR-to-geologic storage operator's business model. The commenters further asserted that if the source of CO2 can contribute to an Agency decision that a Class II well needs to be re-permitted as a Class VI well, then EPA's Class II to VI Guidance has created a disincentive to using CO2 from a new coal-fired EGU. Taken with the RCRA conditional exemption, the Class II to VI Guidance and the proposed NSPS requirement for an EOR operator to comply with Subpart RR reporting requirements create a strong set of disincentives for accepting a CO2 stream from an EGU subject to the NSPS when other CO2 sources are available.
Commenter 10786 discussed the permitting delays and regulatory risks associated with forcing the operation to convert to Class VI, which may preclude timely access to oil.
These comments are misplaced. No change in well class would result from the standards of performance adopted pursuant to section 111(b). On April 23, 2015, the EPA's Director of the Office of Ground Water and Drinking Water issued a memorandum to its regional UIC Program Directors reflecting the principle that geologic storage can continue to be permitted under the UIC Class II Program and the of anthropogenic CO2 in EOR operations does not necessitate a Class VI permit. See section V.N.5.a of the preamble for a summary of the memorandum. The memorandum is available at: http://water.epa.gov/type/groundwater/uic/class6/upload/class2eorclass6memo.pdf. With respect to the RCRA conditional exclusion, see previous response.
Commenter 10786 stated that the underlying but unstated premise of the NSPS is that approved State-based Class II programs are somehow ineffective at preventing injections that endanger USDWs; however, all approved State-based Class II programs already have been determined by the Agency to be effective at meeting that goal.
The commenter is mistaken that the premise of the NSPS is that Class II programs are ineffective at protecting USDWs. Geologic storage of CO2 can continue to be permitted under the UIC Class II program. EOR wells across the United States are currently permitted as UIC Class II wells. CO2 storage associated with Class II wells is a common occurrence, and where injected through Class II-permitted wells for the purpose of oil or gas-related recovery CO2 storage can occur in a manner protective of underground sources of drinking water.
Commenters 8974, 10033 and 10393 stated that CCS should continue to be considered an experimental technology at this time because CCS could pose significant risks to drinking water sources if rushed prematurely to commercial scale. Commenter 10033 stated that it is quite possible that rushing CCS to commercial scale without adequate research and safeguards could make large amounts of US drinking water permanently unsuitable for use as community water supplies through altering the aquifer's chemistry. Commenter 10393 noted that their combined municipal utility has an obligation to protect existing and future drinking water resources located in deep saline aquifers, in addition to providing reliable, affordable and environmentally responsible electricity.
The EPA appreciates that drinking water resources must be protected. The EPA's UIC Program requirements  - for well Classes I through VI (inclusive of Class II enhanced recovery injection wells)  -  are designed to ensure that USDWs are protected regardless of formation type. See Preamble at Section V.N.1. In short, the UIC Class VI rule was developed to facilitate GS and ensure protection of USDWs from the particular risks that may be posed by large scale CO2 injection for purposes of long-term GS. The Class VI rule established technical requirements for the permitting, geologic site characterization, area of review (i.e., the project area) and corrective action, well construction, operation, mechanical integrity testing, monitoring, well plugging, post-injection site care, site closure, and financial responsibility for the purpose of protecting USDWs. UIC Class II regulations issued under section 1421 of SDWA provide minimum federal requirements for site characterization, area of review, well construction (e.g., casing and cementing), well operation (e.g., injection pressure), injectate sampling, mechanical integrity testing, plugging and abandonment, financial responsibility, and reporting. Class II wells must undergo periodic mechanical integrity testing which will detect well construction and operational conditions that could lead to loss of injectate and migration into USDWs. Section 1425 of SDWA allows states to demonstrate that their Class II program is effective in preventing endangerment of USDWs. These programs must include permitting, inspection, monitoring, record-keeping, and reporting components.
The comment that these injection technologies are not available at commercial scale is misplaced. See Preamble sections V.M and V.N. The EPA has issued six Class VI injection well permits under the Class VI requirements, including for injection of anthropogenic CO2 from a coal-burning steam electric facility.
Commenter 6948 stated that for a CCS survey of the 50 states no state has yet received delegation of the Class VI UIC, although one state has an application pending for delegation of the program.
The EPA encourages states to apply for primacy for all well classes, including Class VI. The EPA is in the process of reviewing North Dakota's application for primacy and believes that the best implementation approach is for states to administer both the Class II and Class VI UIC programs. The process of approving primacy for a state to implement the regulations for specific classes of injection wells is not a delegation, rather it is an approval by a rule-making process required by the Safe Drinking Water Act and outlined in the UIC regulations.
Commenter 8032 noted that Class VI injection wells will have to be used since there are not sufficient Enhanced Oil Recovery sites for all of the power generation facilities that will have carbon capture systems. These sites also may not be close to the power generation facilities making them infeasible. Class VI injection wells will have to be carefully designed or there could still be a release of CO2 in to the atmosphere which will be counterproductive, costly and dangerous. Class VI wells must be designed to handle the unique nature of CO2 including the relative buoyancy of CO2, its mobility in the subsurface, its corrosive nature in the presence of water, and the large injection volumes anticipated at these sites.
The EPA agrees that it is important to ensure that CO2 is safely stored, does not impact USDWs and is not released to the atmosphere. Under SDWA and its Underground Injection Control Program, the EPA established minimum Federal requirements to ensure that geologic sequestration (Class VI) wells are appropriately sited, constructed, tested, monitored, and closed to ensure protection of drinking water. The UIC Class VI regulations contain monitoring requirements to protect underground sources of drinking water, including a requirement that Class VI owners or operators develop, implement and maintain a comprehensive testing and monitoring plan, which includes testing of the mechanical integrity of the injection well, ground water monitoring, and tracking of the location of the injected CO2, using direct and indirect methods. Permittees are also required to perform post-injection monitoring and site care to track the location of the injected CO2 and monitor subsurface pressures in relation to USDWs.
Commenters 9666, 9780, 10098, 10239 and 10660 asserted that the EPA has ignored significant legal and logistical barriers to geologic sequestration by focusing solely on federal regulations under the UIC program, GHG Reporting Rule, and RCRA. Commenter 8966 stated that geologic sequestration is subject to state and local laws that are likely to confound operators unless national legislation is available to address property rights and other legal constraints.
Commenters 9666 and 10098 stated that the proposed rule assumes there is a full infrastructure and regulatory framework in place even though it may take years to put into place.
Commenter 10098 then stated that the analysis of the legal issues surrounding geologic sequestration, consisting of Class VI well permits, reporting requirements, and RCRA exemptions, is myopic. The commenters then discussed the potential barriers to obtaining contracts for offsite land acquisition, funding, timing of available transportation infrastructure, and developing a site for secure long term storage without state or federal eminent domain as natural gas pipelines have.
Commenters 10098 and 10239 provided examples of permitting decisions rejecting CCS in part because it was not clear that the applicant could obtain the necessary rights of way in part due to the lack of proven geology favorable for long-term storage and other uncertainties.
Commenter 10137 stated that there are uncertainties surrounding whether subpart RR would constitute waste disposal. The commenter further stated that it appears that subpart RR is inconsistent with typical oil and gas leases if subpart RR converts a hydrocarbon recovery operation into a waste disposal site, because typical leases come to an end and the property reverts to the owner following oil and gas completion. Commenters 10137 and 10786 also noted that the underlying mineral leases pursuant to which EOR operators are authorized to conduct oil recovery operations are granted for the purpose of hydrocarbon recovery and do not authorize the lessee to convert the owners' property into a waste disposal site. Commenter 10786 stated that declaring some CO2 streams to be a "solid waste" under RCRA will make that CO2 stream unsuitable for injection and associated long-term storage in Class II mineral recovery operations, which the NSPS fails to acknowledge.
Two commenters (9731, 9666) stated that compliance with subpart RR will transform an EOR operation from a resource recovery operation/maximization into a waste disposal operation.
The EPA has addressed the issues related to state and local laws in the Section 6.3 topic titled Other CO2 Transport and Geologic Sequestration Legal and Regulatory Issues. With respect to injection-related permitting, in the time since the commenter submitted comments Class VI permits have been issued to two applicants by the EPA. Both applicants, Archer Daniels Midland (ADM) and FutureGen Alliance, addressed siting and operational aspects of GS (including issues relating to the perceived barriers mentioned by the commenter) in their permit applications. The fact that these applicants pursued permits indicates that they regarded any potential property rights issues as resolvable. Analyses of other (non-injection related) permitting decisions with respect to application of CO2 capture and transport were conducted on a site-specific basis and considered site-specific factors in the analysis and were conducted under a different set of criteria than required under the CAA. Eminent domain issues are addressed in the Section 6.3 topic titled Geologic Sequestration Property Rights.
Reporting under subpart RR does not cause an activity to become a waste management activity. In the preamble for the Final Rule for RCRA Conditional Exclusion of CO2 as a Hazardous Waste in January 2014, the EPA stated that sending CO2 streams to Class VI wells for purposes of GS does constitute solid waste disposal. The EPA also noted that should CO2 be used for its intended purpose as it is injected into UIC Class II wells for the purpose of EOR/EGR, it is EPA's expectation that such an injection process would not generally be a waste management activity, and that in any case, the rulemaking did not alter the regulatory status quo of anthropogenic CO2 injected for EOR (which has been done for decades without RCRA obligations being considered to impact or impede those operations).
Commenter 9683 asserted that the proposed rule does not recognize the legal and regulatory structure needed for CCS, therefore impeding CCS's availability.
The EPA believes that the Safe Drinking Water Act (SDWA), Resource Conservation and Recovery Act (RCRA) and Clean Air Act (CAA) will provide the necessary regulatory framework while ensuring environmental protection and the permanence of CO2 storage. The specific protections offered under these regulations are addressed elsewhere in this section and in preamble section V.N.
Commenter 9666 summarized West Virginia Chamber of Commerce survey of the state laws, regulations, and CO2 which found that states do not have adequate regulatory mechanisms in place to support CO2 sequestration. The survey found that no state has yet received delegation of the Class VI Underground Injection Control ("UIC") program related to underground CO2 injection; only 5 states have addressed what property rights must be secured for the geologic storage of CO2 in pore space; only 7 states have developed any streamlined procedures for acquiring pore space; only 4 states have developed programs addressing the mitigation of the long-term post-closure liabilities that are associated with facilities that store CO2 in geologic formations; and only 12 states have provided any streamlined process for the siting or construction of pipelines used to transport CO2.
Commenters 10033 and 10618 stated that to date, the EPA has not issued a single final Class VI permit and only a handful of states are pursuing primacy. The commenter further discussed if a permit is obtainable given the area required to accommodate the CO2 storage volume associated with a coal-based generation unit. With regard to the permit process, the commenter discussed the time required to prepare an application as well as process and issue a permit. Commenter 10618 cites an example of a 2011 permit application still under technical review to support the statement that the regulatory process is likely to be prohibitive. Commenter 10033 also asserted that at a minimum, there should be several years of successful administration of Class VI permits and associated commercial demonstration-scale projects before the EPA or any other agency considers requiring the implementation of CCS technology on a wider scale.

Commenter 10618 states that with regard to the EPA Class VI injection well monitoring and care requirements, a number of uncertainties during and beyond a 50 years post-injection period must be addressed including transfer of liability after closure, financial responsibility requirements and duration, and post-closure monitoring requirements and duration.
Commenter 9666 is correct that no state has yet received primary enforcement authority (primacy) for the Class VI UIC program. However, the EPA is in the process of reviewing North Dakota's application for primacy and believes that the best implementation approach is for states to administer both the Class II and Class VI UIC programs. The EPA encourages states to apply for primacy for all classes, including Class VI.
In the time since the commenter submitted comments, the EPA has issued six final UIC Class VI injection well permits for two projects. The fact that these applicants pursued and received permits indicates that they were able to resolve any issues related to the project area or "Area of Review" (referred to by the commenter as "the area required to accommodate the CO2 storage volume"). The EPA believes that the regulatory framework currently in place, and the experience gained from the recent permit application reviews, permitting, and demonstration Under the Class VI regulations, the owner or operator of a GS site is released from Class VI related post-injection site care responsibilities upon site closure.
Commenter 9426 stated that specific implementation regarding the permitting of Class VI CO2 storage wells is also uncertain and unquantified, as regulatory agencies are just now beginning to address specific requirements regarding how these permits can be issued.
The EPA has issued six final UIC Class VI injection well permits for two projects and has developed a series of technical guidance documents and tools to provide information and possible approaches for addressing various aspects of permitting, constructing, operating, monitoring and closing a Class VI injection well.
Commenter 10618 stated that uncertainties regarding the extent of EOR exemption from RCRA, such as RCRA applicability when the EOR process ends or if the process becomes solely a geologic storage operation, could actually discourage the use of anthropogenic CO2 for EOR operations.
In January 2014 the EPA issued the Final Rule for RCRA Conditional Exclusion of CO2 as a Hazardous Waste in order to facilitate the deployment of geologic sequestration. The rule establishes a set of conditions under which CO2 streams injected into UIC Class VI wells are excluded from the RCRA subtitle C regulations' definition of hazardous waste. In the preamble to the rule, the EPA explained that sending CO2 streams to Class VI wells for purposes of GS is considered solid waste disposal, since the CO2 stream is being "discarded" (see RCRA section 1004 (27)). However, that rule also creates a regulatory exclusion from classification as a hazardous waste, so no RCRA subtitle C regulatory obligations are triggered when the CO2 stream is managed in accordance with the conditions. With respect to beneficial use (rather than disposal in Class VI wells) of captured CO2, the RCRA conditional exclusion rule does not alter the regulatory status quo. The EPA also stated in the preamble that should CO2 be used for its intended purpose as it is injected into UIC Class II wells for the purpose of EOR/EGR, it is EPA's expectation that such an injection process would "not generally be a waste management activity."
Commenter 10098 discussed EPA's determination that conditionally exempted captured CO2 streams that are injected into Class VI wells, not those injected into Class II wells are a RCRA solid waste. The commenter suggested that CO2 injected into a Class II well for EOR could, in some situations, be considered a waste management activity and creates uncertainty and a significant disincentive for operators utilizing CCS-derived CO2 for EOR purposes. Commenter 9734 also stated that there is regulatory uncertainty surrounding the underground sequestration of CO2 due to EPA's determination that sequestered carbon is a solid waste.
Furthermore, the commenter suggested that the informal "safe harbor" for traditional EOR may only apply to the practice of injecting natural CO2, not captured CO2 streams. Therefore, if an oil and gas operator wants to use a CO2 stream from a new coal-fired EGU for EOR operations and avoid RCRA rules, the commenter stated that it may need to persuade the permitting agency that its EOR operations are not waste management activities or perform RCRA hazardous waste analyses on all accepted CO2 streams. The commenter stated that no standardized analyses exist for this material, so an EOR operator would need to develop them. The commenter also asserted that if a CO2 stream tests hazardous, the EOR operator needs contractual rights to reject and return the non-conforming CO2 stream.
As just stated, these concerns are not borne out by actual experience. The RCRA subtitle C regulations have not been an historic impediment to use of anthropogenic CO2 for EOR, and nothing the EPA has said in this rulemaking or the RCRA rulemaking conditionally excluding CO2 sequestered in Class VI injection wells alters the present status quo. The EPA stated in the preamble of the Final Rule for RCRA Exclusion that should CO2 be used for its intended purpose as it is injected into UIC Class II wells for the purpose of EOR/EGR, it is EPA's expectation that such an injection process would not generally be regarded as a waste management activity.
Commenters 10098 and 10239 asserted that if geologic storage is a form of waste management, as the EPA contends it is, then even incidental leakage of this CO2 stream could form the basis for RCRA liability and result in citizen suits. The commenter stated that the operator would not be covered by the RCRA conditional exemption if the CO2 stream was injected into a Class II well.
The status of captured CO2 used for EOR in Class II is unaltered as a result of the conditional exclusion for CO2 disposed in Class VI wells, and likewise unchanged by anything in the standards adopted pursuant to section 111 (b). Class II wells have been injecting anthropogenic CO2 for decades under this existing regulatory structure without RCRA obligations being considered to impact or impede those operations.
Commenter 10618 stated that uncertainties regarding the extent of EOR exemption from RCRA, such as RCRA applicability when the EOR process ends or if the process becomes solely a geologic storage operation, could actually discourage the use of anthropogenic CO2 for EOR operations.
The EPA's recent RCRA conditional exclusion rule applies only to CO2 streams that are injected into UIC Class VI wells (among other conditions). In the final rule preamble, the EPA discussed its view that supercritical CO2 streams injected into UIC Class VI wells for purposes of geologic sequestration are RCRA "solid waste." 79 FR 354-55 (Jan. 3, 2014). However, that rule was not intended to, and does not affect the regulatory status of CO2 streams that are injected into other well classes, including UIC Class II wells. Id. at 355. The EPA stated that, should CO2 be used for its intended purpose as it is injected into UIC Class II wells for the purpose of EOR/EGR, it is EPA's expectation that such an injection process would not generally be a waste management activity, and that interested persons should consult with the relevant regulatory authority. Id. Use of anthropogenic CO2 for EOR is long-standing and has flourished in all of the years that EPA's subtitle C regulations (which among other things, define what a solid waste is for purposes of those regulations) have been in place. The subtitle C regulatory program consequently has not been any impediment to use of anthropogenic CO2 for EOR. Thus, the EPA views the commenter's concerns as exaggerated, and not supported by experience.
Greenhouse Gas Reporting Program
Commenter 9664 stated that they do not agree with EOR operators that have asserted that requiring compliance with the reporting and monitoring, reporting, and verification (MRV) plan requirements of subpart RR would result in operators avoiding the purchase of captured CO2. The commenter stated their belief that it is not inconsequential that available sources of naturally mined CO2 are declining, and that there is significant demand for anthropogenic CO2. Therefore, it is unlikely that existing operators would prefer to go out of business rather than access the market for anthropogenic CO2, simply because of the need for better reporting of the amounts of CO2 managed in EOR activity. The costs of opting into subpart RR by an existing EOR operator with a Class II permit are simply not significant, particularly when compared to the potential revenue from the sale of the produced oil, as provided by EPA calculations in the Energy Information Administration (EIA) for subpart RR rules.
The BSER determination and regulatory impact analysis for this rule relies on GS in deep saline formations. However, the EPA also recognizes the potential for sequestering CO2 via EOR and allows the use of EOR as a compliance option.
The EPA agrees with the commenter's assertion that subpart RR requirements will not result in EOR operators avoiding the purchase of CO2 from affected EGUs. The cost of compliance with subpart RR is not significant enough to offset the potential revenue for the EOR operator from the sale of produced oil for CCS projects that are reliant on EOR. First, the costs associated with subpart RR are relatively modest, especially in comparison with revenues from an EOR field. In the economic impact analysis for subpart RR, the EPA estimated that an EOR project with a Class II permit would incur a first year cost of up to $147,030 to develop an MRV plan, and an annual cost of $27,787 to maintain the plan; the EPA estimated annual reporting and recordkeeping costs at $13,262 per year. Monitoring costs are estimated to range from $0.02 per metric ton (base case scenario) to approximately $2 per metric ton of CO2 (high scenario). Using a range of scenarios (that included high end estimates), these subpart RR costs are approximately three to four percent of estimated revenues for an average EOR field, indicating that the costs can readily be absorbed. 75 FR 75073.
Furthermore, there is a demand for new CO2 by EOR operators, even beyond current natural sources of CO2. For example, in an April 2014 study, DOE concluded that future development of EOR will need to rely on captured CO2. Thus, the argument that EOR operators will obtain CO2 from other sources without triggering subpart RR responsibilities, which assumes adequate supplies of CO2 from other sources, lacks foundation.

In addition, the Internal Revenue Code section 45Q provides a tax credit for CO2 sequestration which is far greater than subpart RR costs. Section 45Q(a)(1) allows a credit of $20 per metric ton of qualified CO2 that is captured by the taxpayer at a qualified facility, disposed of by the taxpayer in secure geological storage, and not used by the taxpayer as a tertiary injectant. Section 45Q(a)(2) allows a credit of $10 per metric ton of qualified CO2 that is captured by the taxpayer at a qualified facility, used by the taxpayer as a tertiary injectant in a qualified enhanced oil or natural gas recovery project, and disposed of by the taxpayer in secure geological storage. The section 45Q credit for calendar year 2015 is $21.85 per metric ton of qualified CO2 under  section 45Q(a)(1) and $10.92 per metric ton of qualified CO2 under section 45Q(a)(2).
. Commenters 9664 and 9514 stated that as proposed, EPA's rule text does not impose any additional requirements on the affected facility to demonstrate that the CO2 has in fact been transferred to a facility that is compliant with subpart RR, that would be incorporated for example into its PSD and Title V permits for the facility. The requirement that the emitting EGU assure that captured CO2 is managed at an entity subject to subpart RR of the GHG reporting rules is exclusively an element of enforcement of the EGU standard.
Commenters 9514 and 9664 requested revisions to 40 CFR 60.46Da(h) &(i) (concerning reporting and recordkeeping requirements). The commenters recommended amending 40 C.F.R. section 60.46Da(h)(5) in order to clearly establish an enforceable requirement that owners and operators of projects injecting CO2 underground that are permitted under UIC Class II and that receive CO2 captured from EGUs to meet the proposed performance standard will also be required to submit and receive approval of a subpart RR MRV plan and report under subpart RR.
The commenters interpreted that the EPA means, by using the term "GS" in the regulatory text, to refer to any kind of sequestration, whether by injection into a Class VI permitted well or by injection for enhanced oil recovery via a Class II permitted well. However, the commenters noted the term "GS" is a defined term in the Safe Drinking Water Act UIC program context that is limited to CO2 injection for the primary purpose of long-term containment from the atmosphere, and does not encompass CO2 injection for the primary purpose of enhanced oil recovery, even where incidental long-term containment of the injected CO2 occurs as a result of that EOR activity. As a result, the commenters provided the following suggested revisions: "If your affected unit captures CO2 to meet the applicable emissions limit, your affected unit must use either (i) onsite or offsite GS, pursuant to a permit issued under Class VI of the Safe Drinking Water Underground Injection Program, and that reports in accordance with the requirements of 40 C.F.R. Part 98, subpart RR, or (ii) send the captured CO2 for use in enhanced recovery of oil or natural gas, through injection permitted under Class II of the Safe Drinking Water Act Underground Injection Program for that purpose and that reports in accordance with the requirements of 40 C.F.R. Part 98, subpart RR."
Additionally, the commenters stated that it is a necessary part of the documentation of the achievement of the emissions standards that such reporting must become a condition of the Title V permit for the facility.
The final rule requires that any affected EGU unit that captures CO2 to meet the applicable emissions limit must transfer the captured CO2 to a facility that reports under GHGRP subpart RR, where sequestration is part of the compliance path. In order to provide clarity on the requirement, the EPA reworded the proposed language under §60.5555(f) to use the phrase "If your affected unit captures CO2" in place of the phrase "If your affected unit employs geologic sequestration". This revision is not a change from the EPA's initial intent.
The EPA disagrees that the rule does not provide enforceable reporting and recordkeeping requirements related to the amount of CO2 that is being sent by an EGU to a facility that is compliant with subpart RR. The revisions being finalized at § 98.427(d) specifically provide that EGUs that are capturing CO2 and sending the CO2 to a facility that is subject to subpart RR "must retain records of CO2 in metric tons that is transferred to each subpart RR facility".
See preamble section XII. Implications for PSD and Title V Programs of the preamble for further discussion on PSD and Title V permits.
Commenters 9664 and 9514 asserted that the EPA must add provisions to require any EGU meeting the standard through long-term containment in a subsurface geological formation (either through GS or in enhanced oil recovery), to provide documentation showing that the volume of captured CO2 necessary to achieve the standard has been injected onsite to a facility permitted under the UIC program and reporting under subpart RR, or transferred to a facility that is permitted under the UIC program and reports under subpart RR.
Commenters 9664 and 9514 suggested the following amendments to Subpart PP reporting requirements at 40 CFR 98.426 to reflect EPA's intent that captured CO2 will be permanently sequestered:
"Section 98.426 Data reporting requirements.
* * * *
(h) If you capture a CO2 stream from an electricity generating unit that is subject to subpart D of this part you must transfer the captured CO2 to a facility or facilities subject to subpart RR of this part, and you must:
(1) Report the facility identification number associated with the annual GHG report for the subpart D facility,
(2) Report each facility identification number associated with the annual GHG reports for each facility to which CO2 is transferred, and
(3) Report the annual quantity of CO2 in metric tons that is transferred to each facility."
The EPA disagrees with the commenter's suggested changes to 40 CFR Part 98 subpart PP. The suggested change would require all EGUs who capture CO2  -  new, modified, and existing  -  to send all of the captured CO2 to a facility subject to 40 CFR Part 98 subpart RR (Geologic Sequestration of Carbon Dioxide). The EPA believes that the current language in 40 CFR Part 98 is appropriate because the GHGRP covers not only EGUs that are subject to the NSPS, but also existing EGUs. It also allows EGUs to send some captured CO2 to other end uses.
Commenter 9766 stated the EPA has ample authority to establish monitoring and reporting requirements under Section 111 and therefore is not restricted only to the existing Greenhouse Gas Reporting Program to ensure proper monitoring and reporting of the disposition or fate of CO2 once transferred from an affected EGU.
The EPA agrees that it has the authority to establish reporting requirements under Section 111 for EGUs. However, the EPA believes that the existing UIC and GHGRP requirements help ensure that sequestered CO2 will remain in place, and provide the monitoring mechanisms to identify and address potential leakage using SDWA and CAA authorities.
Commenter 1637 stated that there are only requirements that the source report under the GHG reporting rule 40 CFR 98 subpart RR if it is disposed onsite or subpart PP if disposed offsite. This reporting provision only requires a report of where it goes. It could all go to a facility that simply releases it to the atmosphere without any penalty to anyone. A requirement to dispose of it only to a facility that is injecting the CO2 and reporting under subpart RR should be plainly stated.
The EPA does not agree with the commenter's interpretation of the requirements in the rule but does agree generally with the commenter's conclusion that the final rule requires all affected units to send captured CO2 to a facility that is compliant with subpart RR of the GHGRP.
Commenter 9664 found EPA's intention to require any new fossil fuel-fired boilers or IGCC employing CCS to meet the standard to send captured CO2 only to a facility that reports under subpart RR is reasonable and stated that the EPA properly relies on the subpart RR MRV plan to verify that the CO2 captured from an affected unit is injected underground for long-term containment.
The commenter stated that for long-term containment occurring incidental to or in addition to EOR operations, a UIC Class II permit and the CAA subpart RR rules establish a similar framework and that since in the near term it is highly likely that EOR will be used to isolate captured anthropogenic CO2 from atmospheric release. It is therefore important for the EGU operator subject to this rule, be able to demonstrate that captured CO2 is sent either to a Class VI GS facility or to a Class II EOR facility reporting under subpart RR.
The commenter further stated that EOR using mined natural CO2 presents the same risks of CO2 to atmospheric release, as does the use of captured CO2 from a power plant, and for that reason, and because there are no significant economic or technical impediments to requiring all EOR activity to report using subpart RR, the commenter urges the EPA to revisit the UU v. RR distinction, in the context of its reporting rules, and require RR reporting for all enhanced oil recovery activity permitted under UIC Class II.
The EPA appreciates the commenter's shared view that relying on subpart RR to verify that the CO2 captured from an affected unit is injected underground for long-term containment is reasonable. The EPA agrees, and the final rule requires, that regardless of the class of well, Class II or Class VI, any facility receiving CO2 from an EGU that is capturing CO2 to meet the standards of this rule must comply with subpart RR requirements. The EPA does not agree with the commenter's suggestion to require all EOR facilities to report under subpart RR, and the comment is beyond the scope of this rulemaking in any case. Should the EPA be deemed to be required to answer the comment, the EPA maintains that the current subpart UU and subpart RR monitoring and reporting requirements are appropriate.
Commenter 10618 stated that reporting tools upon which the EPA is relying have never been used. According to the commenter (10618), for calendar year 2012, only two facilities submitted any information to EPA's GHGRP for carbon injection activities. Both of these facilities have been granted research and development exemptions for GHG reporting, and both of them reported only the volume of GHGs received at the facility under subpart UU, not the detailed information required by subpart RR. The commenter (10618) continued that there were no estimates of the amounts of GHGs actually successfully sequestered, and neither facility has developed the kind of monitoring protocols required under subpart RR. Similarly, commenter 10095 stated the EPA cannot ignore that no injection site, of any size to date, has demonstrated the injection, storage, and monitoring of CO2 under subpart RR requirements. According to the commenter (10618), the remaining facilities listed in EPA's reporting tool are only subject to subpart UU, and are only required to report volumes of "new" CO2 received at the facility, not the amounts that are used in, recovered, and recycled through EOR or other operations, nor any amounts that may be emitted from those operations. As a result, the commenter stated that no useful information about the actual amounts of CO2 in recovered oil and gas, or emitted to the surface in connection with an EOR operation, has ever been submitted to the EPA. Based on this information, the commenter (10618) concluded that the EPA has no basis for its assumptions regarding the ability of EOR operators to successfully design a monitoring program that would meet the requirements of subpart RR.
One commenter (9666) stated that none of the 1,000 million metric tons of CO2 injected to date have been subject to subpart RR. About 120 million have been reported to the EPA since the reporting rules took effect beginning in 2011, all of which has been reported under subpart UU and not a single ton has come under the subpart RR rules. There are no approved MRV plans for CO2 injection in EOR operations for reporting under subpart RR. Hence, rather than being "adequately demonstrated", the subpart RR rules and procedures are unused, uncertain and unworkable for EOR operations.
The EPA disagrees that subpart RR is unworkable. First, subpart RR is built upon an understanding of the mechanisms by which CO2 is retained in geologic formations, which are well understood and proven. See Preamble section V.N.3. Second, international experience with large scale commercial GS projects has demonstrated through extensive monitoring programs that large volumes of CO2 can be safely injected and securely sequestered for long periods of time at volumes and rates consistent with those expected under this rule. This experience has also demonstrated the value and efficacy of monitoring programs to determine the location of CO2 in the subsurface and detect potential leakage through the presence of CO2 in the shallow subsurface, near surface and air. These projects have demonstrated that comprehensive monitoring can be accomplished at saline and EOR sites. With respect to EOR, and as discussed in Preamble section V.N.3, CO2 from the Great Plains Synfuels plant in North Dakota has been injected into the Weyburn oil field in Saskatchewan Canada since 2000. Over that time period the project has injected more than 16 million metric tons of CO2, with extensive monitoring by U,S. and international partners which has demonstrated that no leakage has occurred. The EPA also notes that the DOE has created a network of seven Regional Carbon Sequestration Partnerships (RCSPs) to deploy large-scale field projects in different geologic settings across the country to demonstrate that GS can be achieved safely, permanently, and economically at large scales. In April 2015, DOE announced that CCS projects supported by the department have safely and permanently stored 10 million metric tons of CO2.
One commenter (10095) noted that the EPA references the geologic storage opportunities in Canada and Dakota Gasification synthetic natural gas plant's utilization of EOR in the Weyburn oil field in Saskatchewan, Canada. According to the commenter, if the EPA intends to require any reporting, much less subpart RR, the EPA must elaborate on how it intends to enforce reporting requirements in other countries or eliminate these potential storage opportunities and plants from the Agency's analysis.
The commenter appears to misunderstand the discussion of the Great Plains Synfuels plant in North Dakota and Weyburn oil field in Saskatchewan, Canada, which provides an example of how geologic sequestration has been demonstrated. CO2 from Dakota Gasification has been injected into the Weyburn oil field in Saskatchewan Canada since 2000. Over that time period the project has injected more than 16 million metric tons of CO2. It is anticipated that approximately 40 million metric tons of CO2 will be permanently sequestered over the lifespan of the project. Extensive monitoring by U.S. and international partners has demonstrated that no leakage has occurred.
One commenter (10618) stated that it appears that 85 facilities listed as being subject to subpart UU required no "new" CO2 (i.e., not the amounts that are used in, recovered, and recycled through EOR or other operations, nor any amounts that may be emitted from those operations) for their operations during the entire year, leading one to question the availability of EOR opportunities for the large amounts of CO2 that would be captured at even a single, partially controlled coal-fired steam generating unit. Based on this information, the commenter (10618) concluded that the EPA has no basis for its assumptions regarding the availability of sequestration at EOR operations.
40 CFR Part 98 Subpart UU requires the reporting of the amount of CO2 received for injection. The data element referenced by the commenter was previously determined to be confidential business information (CBI) at the facility level. 77 FR 48072 (August 13, 2012) Therefore the data is not made available on a facility-by-facility basis. The amounts reported by facilities are CBI and not zero. According to data reported to the GHGRP, approximately 60 million metric tons of CO2 were supplied to EOR in the United States in 2013.
Commenter 9196 stated that the proposed rule relies heavily on the potential for power plants to sell CO2 to EOR operators as a means of defraying the tremendous costs of CCS, however, EOR operators are signaling that the subpart RR requirements in the proposed rule may be prohibitive. Broad coalition of groups, from EOR operators to electric power providers, has raised concerns about EPA's plans. The commenter requested that the EPA address the following concerns:
   a. 	Please explain in detail the new requirements for EOR operators that would accept CO2 from power plants?
   b. 	Have you spoken with any groups potentially impacted by the new subpart RR reporting requirements? How have you taken their concerns into consideration?
   c. 	Would reporting under subpart RR potentially trigger the transition of an EOR well from Class II to Class VI under the UIC program-as EPA draft guidance suggests?
   d. 	A significant part of EPA's economic justification for the proposed rule relies on the assumption that the CO2 from power plants will be a valued commodity used in EOR operations. How do the economics of the proposed rule change if this is no longer an option?
   e. 	Can you commit that EPA will not use reporting under subpart RR to push any EOR operations into Class VI.
The EPA does not agree with the commenter's statement that the proposed rule relies heavily on the potential for power plants to sell CO2 to EOR operators. EOR facilities may facilitate early mover projects, but the proposal and final rule rely on CO2 being sent to deep saline formations, as indicated by the discussion in the preamble and the Regulatory Impact Analysis.
The EPA also offers the following responses to the commenter's questions.
   a. Under the rule, any facility receiving CO2 from an EGU that is capturing CO2 to meet the standards of this rule must comply with the existing requirements of subpart RR.
   b. Subpart RR of the Greenhouse Gas Reporting Program is not new. Rather, the regulations promulgating Subpart RR were finalized in 2010. The EPA reviewed and responded to public comments as part of the rulemaking that promulgated the Subpart RR requirements. As part of the notice-and-comment process of this rule, the EPA has reviewed and considered public comment on the proposal.
   c. Reporting under subpart RR does not trigger the transition of a Class II well to a Class VI well. See preamble section V.N.5.a.
   d. Facilities using carbon capture are doing different things with the captured CO2, ranging from EOR to storage to using it for food products. While it is true that selling captured CO2 for EOR can generate revenue and help offset the costs of capturing carbon, this does not mean plants can only build in areas near EOR. In estimating costs for the proposed rule, the EPA considered various scenarios. See the Regulatory Impact Analysis for more discussion on the scenarios which the EPA considered and their estimate impacts. In estimating impacts, and in assessing costs for purposes of determining if partial CCS is BSER adequately demonstrated, the EPA relied conservatively on the case where CO2 would be sent to a deep saline GS formation. Therefore, the commenter is simply incorrect in stating that EPA's economic justification for the rule relies on the assumption that the CO2 from power plants will be used in EOR operations.
   e. An EOR project may be permitted as UIC Class II and report under Subpart RR. The regulatory provisions regarding transitioning from UIC Class II to UIC Class VI are set forth at 40 CFR 144.19. Reporting under Subpart RR of the Greenhouse Gas Reporting Program is not one of the factors specified in 40 CFR 144.19(b).
One commenter (10034) stated that the information collected through the GHGRP can be used to measure some of the agency's anticipated outcomes.
The EPA agrees with the commenter that the information collected through the GHGRP can help measure and track some of the EPA's anticipated outcomes. The EPA is finalizing changes to the reporting requirements of subpart PP of the GHGRP to help track these outcomes.
Commenter (4733) stated that the EPA issued subpart RR to complement the UIC Class VI Rule. Compliance with subpart RR will allow GS operators to provide proof of sequestration, eliminating another barrier to CCS.
Similarly, commenter 9035 stated that the EPA has provided a pathway for demonstrating the geologic storage of CO2 utilized in EOR by meeting certain requirements of the Underground Injection Control Program and the Greenhouse Gas Reporting Program.
The EPA agrees that subpart RR complements the UIC Class VI regulations. The EPA also agrees that subpart RR will provides a mechanism for demonstrating the efficacy of GS, including in conjunction with EOR.
Commenter 9666 stated the reporting obligations under subpart RR are poorly defined, and may discourage CO2 injection facilities from accepting CO2 generated by sources subject to the proposed NSPS, particularly EOR facilities, which are not currently required to report under subpart RR. According to the commenter, because no entity has reported data to the EPA under subpart RR, there is lingering uncertainty as to what would be required from a subpart RR monitoring, reporting, and verification plan. Other commenters (9201, 9683, 10036, 10098, 10137, 9731, 10095) also expressed concerns with the potential uncertainty and risks compliance with subpart RR creates for EOR operators.
One commenter (10098) opined that requirements to comply with subpart RR opined that this is problematic because there are no standards governing what may constitute an incomplete or otherwise unacceptable MRV plan, nor any timeline for approval, creating a completely open-ended and undefined regulatory framework.
The EPA does not agree that the reporting obligations under subpart RR are poorly defined. There are clearly defined reporting requirements outlined in 40 CFR Part 98.446. As part of these requirements, the EPA has provided flexibility to reporters in regards to annual monitoring reports (40 CFR 98.446(a)(12)); the EPA views this as a way to balance the burden in reporters as each sequestration site is unique as opposed to a uncertain requirement.
There are also clearly defined requirements for what must be included in a complete and acceptable subpart RR MRV Plan. The EPA identified all required components in a subpart RR MRV Plan in 40 CFR Part 98.448(a). In outlining these requirements, EPA's approach allows for site-specific flexibility for MRV plans and does not prescribe particular monitoring technologies. The approach also allows the owner or operator to leverage the site characterization, risk assessment, and/or monitoring required by other authorities as the foundation for demonstrating compliance with the MRV plan requirements of 40 CFR Part 98, subpart RR.

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

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

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

Commenter 9197 stated the proposed rule does not adequately consider the potential for downstream outages to impact EGUs' ability to consistently meet the proposed NSPS-an issue that would not affect the demonstration projects or industrial facilities on which the EPA relies because these facilities can simply shut down when sequestration is not available. According to the commenter, the EPA has not addressed the possibility that a CO2 pipeline, EOR operator, or geologic sequestration well operator could experience technical or other difficulties that would prevent these third parties from taking a regulated EGU's CO2.
Commenter 10095 described the Final Determination of Compliance for HECA's proposed polygen facility, which specifies HECA's proposed GHG BACT analysis for its CO2 Recovery and Vent System that includes the ability to vent captured CO2 during periods when compression, transportation, or the delivery system is unavailable due to cold gasification block startup, CO2 compressor or pipeline unplanned outages, or third party CO2 off-take issues. The commenter urged EPA to consider how these types of risks can impact compliance with the proposed rule.
The EPA believes that the rule provides sufficient flexibility to avoid the compliance issues described by the commenters. In the event that there is a malfunction condition, the EGU would not be immediately required to shut down or be required to shut down within a certain specified period of time. EGUs that are unable to export their captured CO2 emissions could continue to operate without capturing their CO2 emissions in accordance with the terms of their operating permits and in accordance with numerical CO2 emissions limit to which the facility is subject.
Commenter 10083 discussed the difficulties associated with deploying CCS in the West, such as complexity and time to obtain permits, complexity and costs of assessing storage suitability, and costs of covering liability risks related to transport and injection.
The EPA has responded to the issue of permits in the Section 6.3 topic titled Safe Drinking Water Act's Underground Injection Control (UIC) Program and Resource Conservation and Recovery Act, geologic sequestration assessment in the Section 6.3 topic titled Geologic Sequestration, and liability in the Section 6.3 topic titled Liability. The EPA notes that issues of liability will involve site-specific resolution if and when they arise in particular proceedings.
Commenter 9731 stated that the commenter opposes any efforts that would make CO2-EOR more costly or burdened by an unworkable regulatory framework.
The EPA believes that the Underground Injection Control (UIC) Class VI rule and Subpart RR of the GHG reporting rules do not place an excessive burden on EOR operators. The existing framework offers an integrated and complementary set of regulations that ensure an appropriate level of verification and accounting of CO2.
Citing a Congressional Research Service report, Commenter 9423 stated that legal and regulatory uncertainties may make broad community acceptance of CCS a challenge.
According to commenter 9666, public opposition to permitting CO2 storage sites due to safety related concerns has occurred recently in Europe. The commenter concluded that public acceptance can be a major issue at any proposed site.
Public awareness and support have been widely recognized as critical components in the development of new energy infrastructure, including CCS deployment. Efforts have been made to design strategies for successful outreach to the public. For example, under the DOE Regional Carbon Sequestration Partnerships, DOE has been engaging with local communities to educate and inform them about planned pilot and demonstration projects in their areas. DOE's Best Practices for Public Outreach and Education for Carbon Storage Projects presents lessons learned through the planning and implementation of CCS projects, as well as best practices for community engagement.
Commenter 9426 stated that without a strong price signal for CO2, only public funding will possibly advance CCS and funding is highly uncertain.
As discussed in the proposal, the 2010 Interagency Task Force on CCS report recognized that, as an alternative to a strong price signal for CO2, a regulatory framework that promoted CCS was a mechanism for encouraging the commercial deployment of CCS (79 FR 1480). This rule is an important component in developing that framework, which could, even in the absence of a strong price signal for CO2, advance CCS.
Commenter 8949 stated that an environmental and cost impact assessment of the development and implementation of a CCS regulatory structure, either at the federal or state level, should be included in the agency's decision making process.
In its regulatory impact analysis, the EPA determined that identifying partial CCS as the BSER for coal-fired power plants would not have adverse impacts on the power sector, national electricity prices, or the energy sector. Furthermore, this rule relies on existing regulatory frameworks under the UIC Program and GHG Reporting Program.
Commenter 10618 asserted that the EPA should have listed a new source category that includes all of the affected facilities necessary to effectively control CO2 emissions rather than relying on the existing source category described under Subpart Da. The commenter stated that EPA's assertion that it is regulating the same source categories currently regulated under Subpart Da is inaccurate because those sources do not include the CO2 transport and sequestration or end use processes necessary to segregate the captured CO2 emissions from the atmosphere.
Furthermore, Commenter 10618 disagreed with EPA's reliance on the GHG Reporting Program to track the captured CO2 that is geologically sequestered as a means of avoiding redefining the source category. The Commenter stated that without an effective method to establish an enforceable standard for sequestration, such as requirements for successful sequestration and a better reporting tool, EPA's proposal to require capture and reporting of CO2 emissions is ineffective and arbitrary.
 The EPA disagrees with the commenter's assertion that it is not regulating the same source categories currently regulated under subpart Da because those sources do not include the CO2 transport and sequestration or end use processes necessary to segregate the captured CO2 emissions from the atmosphere. The subpart Da requirements for criteria pollutants similarly do not include requirements for transportation and storage of particulate matter, SO2 scrubber residuals. We have described separate requirements for transportation and storage of captured CO2 in the preamble section V.N. and elsewhere in this response to comments document. The EPA also disagrees with the commenter's assertion that there is no effective method to establish an enforceable standard for sequestration. Separate regulatory requirements exist under SDWA's UIC program that regulate the entities involved in geologic sequestration of carbon dioxide. And the current rule requires that the emitting EGU assure that captured CO2 is managed by an entity subject to the GHG reporting rules. The primary intent of the requirement that the emitting EGU make this assurance is to account for captured CO2 that is geologically sequestered. See the Section 6.3 topic titled Greenhouse Gas Reporting Program and preamble section V.N.2 for discussion related to the GHG Reporting Program.
Commenter 9407 stated that there are geographic locations where insufficient EOR and deep well sequestration infrastructure prohibits NSPS compliance, but where coal-fired plants are required to satisfy local needs. The commenter asserted that the proposal is unlawful because the requirements prohibit source locations where CCS infrastructure is unavailable, despite the location's need for a reliable grid source or economic development.
A few states do not have geologic conditions suitable for GS, or may not be located in proximity to these areas. Where GS capacity is unavailable, electricity demand in those areas can be served by coal-fired power plants built in neighboring areas with GS. For other of those areas, coal-fired power plants are either not being built due to state law restrictions, or other available compliance alternatives exist allowing a new coal-fired power plant meeting the promulgated NSPS to be sited. The EPA has also noted compliance alternatives that will allow affected new facilities to meet the final standard without the use of CCS technologies  -  notably by using natural gas co-firing.
Commenter 8743 argued that EPA's description of legal precedent regarding the absence of a requirement under CAA section 111 that a New Source Performance Standard be able to be met by every new source in the source category misconstrues legislative intent. Commenter 8743 states that the legal precedent that the EPA relies on, which relates to attaining National Ambient Air Quality Standards, to justify this assertion is misplaced and cannot be properly applied to the emissions standards for CO2 for which no ambient air quality standard or distinct air quality related value exists. Commenter 8743 concludes that the EPA has overstepped by disadvantaging large geographical areas that are technically and economically precluded from CCS, which the commenter believes the EPA acknowledges by trying to argue that there is no requirement that a New Source Performance Standard be able to be met by every new source in the source category.
The EPA believes that a new steam generating affected source could meet the promulgated standard and be located anywhere in the country. There is available sequestration capacity in most areas of the country, and there are alternative ways a new EGU could meet the standard, not involving sequestration, should a new source decide to locate in an area where these sequestration opportunities are unavailable. See Portland Cement Ass'n v. EPA, 665 F. 3d 177, 191 (D.C. Cir. 2011), holding that the EPA could adopt section 111 standards of performance based on the performance of a kiln type that kilns of older design would have great difficulty satisfying, since among other things, there were alternative methods of compliance available should a new kiln of this older design be built. The court also noted that it was highly unlikely that such a new kiln would ever be constructed and that the EPA could consider this in adopting a standard of performance reflecting a different type of kiln design. Similarly here, there is significant doubt that a new steam generating unit would be sited in one of the few areas without ready access to sequestration or EOR opportunities (and commenters have supplied no information indicating that such a possibility actually exists). Finally, the promulgated standard of performance can be met without capturing CO2 or sequestering it, using alternative means of control which have no associated geographical constraints.
6.3.6 CCS Is/Is Not BSER
Commenters 7977, 8032, 8501, 8949, 8973, 9194, 9197, 9318 9422, 9505, 9590, 9596, 9600, 9678, 9683, 10033, 10036, 10050, 10051, 10087, 10618 disagreed with the choice of partial CCS as BSER.
Commenters 8973 and 9318 strongly objected to EPA's consideration of "partial CCS" as BSER for new coal plants and new integrated coal gasification/combined cycle (IGCC) plants, as the same technological immaturity, accessibility, and transportation arguments (used for full CCS) can certainly be made for these units. In addition, the commenter stated that the cost-effectiveness of partial CCS--particularly if involving permanent geologic sequestration and not temporary enhanced oil recovery (EOR)--is entirely unproven and not commercially available, regardless of type.
Commenters 7977, 8501, 9197, 9683, 9677, 10033, 10050 10137, noted that CCS was not adequately demonstrated, citing feasibility and costs as additional problems. Commenter 9678 recommended that the EPA adopt standards that are achievable using state-of-the-art technologies. Commenter 10134 stated that the EPA did not properly evaluate the two options of highly efficient generation technologies and efficiency measures in comparison to CCS. Commenter 9194 noted the need for vendor performance guarantees. Commenter 10134 stated that the EPA did not properly evaluate the two options of highly efficient generation technologies and efficiency measures in comparison to CCS. Commenters 9422, 9596, 10051 recommended that the EPA reconsider CCS as BSER, and issue a new proposed rule.
Commenter 7977 stated that the selection of CCS as BSER for coal-fired EGUs is arbitrary and capricious.
Commenter 10089 provided general support for the proposed rule as a step in the right direction to reduce the greenhouse gas emissions of the electric power sector, suggested that CCS may not be BSER, given the cost impacts.
First, partial post-combustion CCS is demonstrated at commercial scale, and has been operated successfully at the Boundary Dam facility since October 2014.  Permanent sequestration in Class VI deepwells is likewise demonstrated.  See preamble section V.N.  Vendors are providing guarantees for CCS.  See preamble section V.F. The EPA carefully considered the issue of compliance costs, and based its cost estimates on updated costs reflecting recent vendor quotes and performance information and application of the Shell Cansolv amine scrubbing process that is currently being used at the Boundary Dam Unit #3 project.  Based on this most up-to-date information, the EPA adjusted the final standard of performance to 1,400 lb CO2/MWh from the 1,100 lb CO2/MWh proposed.  The EPA's analysis of why the cost of this standard are reasonable under section 111 (a) is found in sections V.H and I. of the preamble to the final rule.
Commenters 4814, 7977, 9426, 9590, 10043, 10047, 10135, 10466, 10929 stated that CCS is developing but is not is not technologically or economically viable at this time, and thus should not be a basis for a standard.
Commenter 4814 summarized work developing CCS technologies. The commenter noted that these projects are bringing CCS closer to economic and commercial viability over the next decade.
 These comments were unduly negative.  CCS is clearly technically viable as it is being implemented now. For example, the Boundary Dam Unit #3 facility is operating successfully at full scale. The EPA has also determined that a new unit can utilize partial CCS to meet the final standard of performance at reasonable cost. The EPA has also issued six Class VI permits for underground injection.  See generally preamble section V.
Commenter 9678 stated concern that EPA's determination that partial CCS is BSER for coal and IGCC units is flawed and will not survive judicial review. According to the commenter, EPA has not shown that CCS for coal units is adequately demonstrated and relies on arbitrary presumptions in reaching its conclusion and these inadequacies in EPA's analysis may make the proposed standard vulnerable to remand on judicial review, which would delay the promulgation of the rule and the associated benefits of having a final rule in place. To ensure that the rule is legally defensible, the commenter recommended that EPA establish a standard for coal and IGCC units that is not based on CCS, but is instead based on other adequately demonstrated emissions control technologies.
According to commenter 9505, the agency's BSER determination will not survive judicial review, as it is contrary to the statutory text and a wealth of evidence, and is not supported by reasoned decision-making. The commenter stated section 111 of the Clean Air Act does not permit EPA to force an experimental technology through an NSPS, although this is precisely what the proposal attempts to do. Accordingly, the commenter recommended EPA reverse its determination that CCS is the BSER for the proposed NSPS.
Partial CCS is an adequately demonstrated control technology.  See preamble section V.D.  The EPA does not believe that basing a standard on performance of "capture and CO2 compression technologies [that] have commercial operating experience with demonstrated ability for high reliability" is arbitrary and capricious.  See NETL (2015) at p. 36.  See also statement of Alstom senior Vice President for Power and Environment Policies Joan MacNaughton (August 4, 2011): "The technology works."   See: www.alstom.com/Global/US/Resources/Documents/Press%20Releases/PR_JMacN_CCSbriefing_FINAL.pdf
Commenters 9725, 10050 stated that the EPA has used estimates from hypothetical IGCC and SCPC units with CCS, not actual operating experience. The commenters stated that the EPA's approach is unprecedented, unlawful and a stunning departure from over 40 years of regulatory history that relies upon actual emission data from representative units operating with adequately demonstrated technology.
Commenter 10039 stated that the EPA cannot attribute all new coal fired generation as unequivocally base load for purposes of justifying CCS as technically feasible for this source, and not include intermediate (load following) and peaking units.
 Partial CCS is demonstrated at commercial scale in this industry (Boundary Dam, in particular), and (for pre-combustion, should this be pursued) in a related, transferrable context (Dakota Gasification).  These are not hypothetical facilities.  EPA's cost estimates reflect the most up-to-date information available: recent vendor quotes and performance information and application of the Shell Cansolv amine scrubbing process that is currently being used at the Boundary Dam Unit #3 project.  The EPA does not unequivocally attribute all new coal-fired generation unequivocally as base load units for the purpose of justifying CCS as technically feasible. The EPA does believe, given current and projected market conditions, that a project developer would be most likely to build a new unit for the purposes of providing high capacity factor, base load generation. Still, the EPA has shown that the promulgated standard is achievable for an affected EGU using the BSER under a range of operating conditions and that the 12-month average is indicative of, and accommodating for, variable operations (and excursions).  In confirmation, as shown in the Technical Support Document, actual 12-month averages of two recent highly efficient SCPC are close to those projected here.
.  See preamble section V.J and New Steam Achievability Technical Memorandum (July 2015).
Commenter 10618 stated that EPA's position on the feasibility and adequate demonstration of CCS in the proposed rule are in many ways contradictory to its assessment of the technology in the PSD and Title V Permitting Guidance for Greenhouse Gases document. The commenter provided numerous excerpts from the document in which EPA suggests that CCS be considered in a BACT analysis and that CCS will likely not apply because it is not technically feasible and/or because it is not cost-effective - both reasons also support the conclusion that CCS has not been adequately demonstrated. The commenter concluded if the level of development is insufficient to generally apply CCS as BACT, it is also insufficient to support the determination that CCS is the BSER.
   With regard to the commenters who stated that a BSER for EGUs that is based on partial CCS would be inconsistent with BACT determinations in previous GHG PSD permits, it is important to recognize that a BACT determination is a case-by-case analysis and that technological capabilities and costs evolve over time. Thus, language from an historic guidance document, providing context for case-by-case application rather than for national rulemaking, hardly has determinative effect here.  Moreover, the commenters quote selectively from that guidance.  In fact, the 2011 GHG Permitting Guidance states that "although CCS is not in widespread use at this time, EPA generally considers CCS to be an `available' add-on pollution control technology for facilities emitting CO2 in large amounts and industrial facilities with high-purity CO2 streams." GHG Permitting Guidance at 35. The Guidance goes on to note that CCS may not be available at modified sources, or in other specific circumstances. Id. at 36 ("While CCS is a promising technology, EPA does not believe that at this time CCS will be a technically feasible BACT option in certain cases....EPA recognizes the significant logistical hurdles that the installation and operation of a CCS system presents and that sets it apart from other add-on control that are typically used ... Logistical hurdles for CCS may include obtaining contracts for offsite land acquisition ..., the need for funding..., timing of available transportation infrastructure, and developing a site for secure long term storage. Not every source has the resources to overcome the offsite logistical barriers necessary to apply CCS technology to its operations, and smaller sources will likely be more constrained in this regard"); id. at 42-3 (noting that CCS may be expensive in individual instances and thus eliminated as a control option for that reason under step 4 of the BACT analysis, noting further that revenues from EOR may offset other costs).  See also UARG v. EPA, 134 S.Ct. 2427, 2448 (2014) (noting that EPA's GHG Permitting Guidance states that carbon capture is reasonably comparable to more traditional, end-of-stack BACT technologies, and that petitioners do not dispute that).  See generally, preamble section XII.C.
As explained at preamble section V.I.5, in determining that partial CCS is BSER for new fossil fuel steam electric plants, EPA has carefully considered the issue of logistics (including cost estimates for land acquisition, transportation, and sequestration) and costs generally. Nor would new plants face the same types of constraints as modified or reconstructed sources in a BACT determination, since a new source has more leeway in choosing where to site. Moreover, the GHG Permitting Guidance considered BACT determinations for all types of sources, not just those for which EPA has determined in this rule that partial CCS is the best system of emission reduction, and the concerns voiced in the Guidance thus must be considered in that broader context.
Commenter 10618 stated that EPA's evaluation of each of the four factors in the BSER determination is flawed due to:
   * a series of premature, inaccurate conclusions on the development, demonstration, and performance of advanced generation and CCS technologies;
      Response: The EPA disagrees.  See preamble sections V.D and E.  See also NETL (2015) p. 36 characterizing CCS as a technology with "commercial operating experience with demonstrated ability for high reliability".
   * minimal consideration and an abrupt dismissal of widely-acknowledged barriers to CCS becoming a technically feasible and adequately demonstrated control option;
      Response:  See previous response.
   * an inadequate consideration of the lessons learned from actual projects and the conclusions reached by major public and private assessments of CCS development;
      Response: The "major public and private assessments" that were mentioned largely referred to full, rather than partial CCS (see preamble section V.F).  The EPA has carefully considered lessons learned.  It is for this reason that the agency sought out and utilized the most recent cost information on post-combustion CCS, basing its cost estimates on those from vendors supplying the technology in commercial use at the Boundary Dam #3 facility.  See also preamble section V.I.2. indicating consistency of NETL cost estimates with those of other leading experts in the field, as well as with those of recent industry cost estimates.
   * an inconsistent use of criteria to perform the BSER analyses and to inform the Administrator's judgment within this proposal and compared to other rulemakings;
      Response:  See Portland Cement v. Ruckelshaus, 486 F. 2d at 389 (NSPS are judged on their own merits, not by comparison with NSPS established by EPA for other source categories).
   * an inadequate evaluation of the impacts to all sources within the source category; and use of underlying energy policy goals that do not allow for an objective evaluation of BSER in accordance with the Clean Air Act.
      Response: the commenter is mistaken.  The NSPS is justified, and may only be justified, by the statutory criteria set out in section 111 (a).
Commenter 9664 stated EPA correctly bases the level of the proposed standard for new subpart Da fossil fuel-fired boilers and IGCCs on the application of partial carbon capture and sequestration as the Best System of Emission Reduction. According to the commenter, EPA's careful consideration of the cost, energy, and non-air quality, environmental impacts of CCS satisfy the statutory requirements for the Agency to balance these required statutory factors in designating a CAA section 111 BSER.
Commenter 101008 stated that EPA has given sufficient consideration to the statutory factors in making its BSER determination. The commenter referenced several court decisions to support their argument. The commenter noted that in determining that partial CCS is BSER for coal-fired power plants, EPA appropriately weighed the efficacy of achieving emission reductions as its prime consideration. The commenter added that in its BSER analysis, EPA ruled out highly efficient coal-fired generation without CCS in part because that technology alone would not result in significant reductions of CO2. According to the commenter, CCS is by far the most effective process available for reducing carbon pollution from new coal-fired power plants, and this factor thus weighs highly in favor of EPA's BSER determination.
Commenter 9514 stated EPA is justified in setting CCS as the BSER for new fossil fuel-fired boilers and IGCCs. According to the commenter, CCS provides significant emissions reductions and co-benefits, CCS systems are available for fossil fuel boilers and IGCCs and the technologies have been utilized in industrial applications for decades, and the costs are reasonable and can be accommodated by industry.
Commenters 8020, 8939, and 8967 stated that using partial CCS strikes a good balance between economics and the environment, and that the technology will help to prevent significant amounts of C02 from being emitted into the atmosphere.

The EPA largely agrees with these comments, although the final standard of performance strikes a somewhat different balance than struck in the proposal, albeit using the same methodology.
Commenters 8501, 9194, 9201, 9426, 9671, 10618 disagreed with the difference in the way that CCS was or was not determined to be BSER for subpart Da and subpart KKKK units.
Commenters 9194, 9201, 9426, 9671, 10618, stated that CCS is currently inappropriate as BSER for both gas-fired and coal-fired EGUs.
Commenters 8995, 9194, 9201, 9426, 9671, 10039, 10618, 10876 stated that many of the reasons the EPA cites for rejecting full or partial CCS technology as BSER for natural gas-fired stationary combustion turbines are equally applicable to IGCC and fossil fuel-fired boilers, yet the Agency reaches a different conclusion for the two sources. Commenter 10039 noted that the EPA errs by saying CCS is feasible at coal fired units regardless of dispatch order despite its acknowledgement that load following may (and likely will) adversely affect the efficiency and reliability of a unit with carbon capture systems.
Commenter 8501 stated that there is little evidence to support a distinction between coal-based generation to NGCT for the technical challenges and costs for CCS, and stated that the EPA fails to distinguish why CCS is not BSER for a natural gas-fired plant.
Commenter 10618 discussed the differences in discussions of CCS as applied to subpart Da and subpart KKKK units, noting that there was very limited discussion about broader industrial CCS experience in the BSER analysis for NGCTs, but there was for coal-based generation. The commenter stated that the literature review was unevenly applied to the two source categories. The commenter stated that large-scale demonstration projects have not yet occurred for either of the two source categories.
Commenter 10618 stated that although the Econamine capture system that has been used by NGCC processes has yet to be demonstrated on a single coal-based generating unit, EPA assumes in its cost analysis for the BSER that new pulverized coal units with CCS will be equipped with the Econamine system.
Commenter 9201stated that the way the EPA has weighed the factors to determine that CCS is BSER is unreasoned and an abuse of discretion.
Commenter 10017 stated that there is a significant difference in the reductions required in CO2 emissions between subparts Da and KKKK.
A discussion of the EPA's final rationale regarding CCS as a component of BSER for combustion turbines is provided in the final preamble at section IX.C.4.
Commenter 9600 stated that the EPA has not documented its extrapolation of technology performance in other industries to that for coal-based generation. The commenter stated that as a result, there is no reasonable basis to conclude that carbon capture is technically available at a reasonable cost for use as BSER in the immediate future and perhaps not available as a BSER for many years to come.
 First, post-combustion CCS is demonstrated at commercial scale at a source (Boundary Dam) that is a full-scale, fully integrated coal-fired EGU.  No inter-industry transfer of technology is at issue.  Pre-combustion CCS (should a source consider that alternative compliance pathway) is likewise demonstrated at full commercial scale.  See preamble section V.E.2.a for why this same technology and performance is transferable to an IGCC generating electricity.
Commenter 10618 stated that the EPA's consideration of emission reductions is flawed because the agency uses ambiguous criteria to determine emission reductions. The commenter stated that the EPA fails to fully consider the magnitude of emission reductions that may be achieved from highly efficient processes alone, and utilizes loose, qualitative statements on CCS related emission reductions. The commenter stated that the EPA provides no information on the baseline used to assess emission reductions and provides no information on the types of criteria considered in determining "significant" and "meaningful."
 See preamble section V.K quantifying the difference between a highly efficient SCPC and a highly efficient SCPC meeting the standard of performance based on the BSER.  See also RIA chapter 5 quantifying the benefits of that difference in performance and showing that those benefits exceed regulatory costs under a range of assumptions.
Commenter 4710 stated that the EPA has chosen to disregard DOE and OMB statements and documents that do not support CCS readiness, economics or feasibility.
 Those statements referred to full CCS, not partial CCS.  DOE's latest statement regarding CCS reliability ("demonstrated ability for high reliability") is found at p. 36 of its July 2015 NETL study.
Commenters 9195, 9201, 10036, 10239, 10395 noted that the EPA has changed BSER in this proposal from the determination of BSER in the 2012 proposal.
Commenters 10239, 10395 stated that the EPA has provided no rational explanation for the change.
Commenter 9195 asked for the basis for the change.
Commenter 10239 stated that nothing has changed since 2012 to make CCS BSER, and noted that the EPA does not cite any new information or new projects in this rulemaking that were not available to it in the 2012 proposed rule. The commenter stated that there is no rational basis for the EPA to reverse course and conclude that CCS is adequately demonstrated and is BSER for coal-fired EGUs without some new data or evidence of changed conditions. The commenter stated that such a conclusion is fundamentally at odds with the most basic principle of administrative law that, when an agency changes its position, it must supply a reasoned analysis for doing so.
 The EPA indicated in its 2012 proposal that CCS was a feasible technology option for new power plants in the original proposal, so much of this comment rests on a mistaken premise.  See 77 FR at 22414-417.  The agency withdrew the 2012 proposal largely in response to industry comment that future new fossil-fuel fired steam electric capacity (i.e. coal-fired) was possible and therefore that separate standards for utility boilers and IGCC, on the one hand, and NGCC units on the other, was warranted. 79 FR at 1432. The EPA did not find that CCS was the BSER in that 2012 proposal because the proposed standards were for a combined category that included both NGCC units and steam generating units. In the current action, the EPA proposed and is finalizing separate standards of performance for both stationary combustion turbines and steam generating units, with separate BSERs for each. With respect to CCS, among the developments that have occurred since the 2012 proposal are the successful operation at commercial scale of post-combustion CCS and issuance of six permits for deep well injection of captured CO2, as well as more recent cost information reflecting operating experience.  The EPA has fully articulated its basis for the final standard reflecting an adequately demonstrated BSER, and this extended discussion amply indicates why EPA is adopting a different assessment than found in the 2012 proposal.  See preamble section V.
Commenters 9001, 9428, 9595, 9601, 10238, 10358, 10387, 10501 stated that although CCS holds promise for the future, the technology for electric generation today remains both costly and unproven.
 See preamble section V.
Commenters 10083, 10606 asked that regional impediments to CCS be considered, particularly the lack of good CO2 sequestration sites.
 See preamble section V.M.
Cost
Commenter 9666 stated that EPA's attempt to calculate the cost of CCS is inadequate, as there are no commercial units operating to provide experience from which to validate designs that were developed for small-scale. The commenter noted that although no commercial-scale CCS project has been completed at a coal-fired or IGCC unit, and thus no reliable indicator of the full cost of CCS at this scale exists, some cost information is available for the Kemper County IGCC unit, which is scheduled for completion in 2015. According to the commenter, during the course of Kemper County's construction, the project's costs have escalated from an estimated $2.4 billion in 2010 to $5.5 billion at the latest estimate in 2014, representing several successive cost increases. The commenter recommended  a more robust approach for determining casts would be to solicit price quotes for power generation equipment in the present economic and fuel price environment; employing several sources of such data (e.g., not a single proprietary database); and conducting a rigorous peer review.
Commenter 9666 also stated that due in part to a lack of relevant operating experience, CCS remains exorbitantly costly to install and operate. The stated the uncertainty surrounding the actual cost of any IGCC project incorporating CCS presents another hurdle to financing and constructing these units. According to the commenter, developers will find it difficult to obtain financing due to their inability to predict the actual cost of any IGCC project involving CCS. The commenter stated that the costs of CCS are so high and uncertain that the proposed IGCC standard will effectively prohibit the construction of any new Subpart Da IGCC unit. The commenter also stated in addition, at all of the commercial-scale projects that have been proposed, the CCS system is justified in the fundamental business case for the project because the separated CO2 stream will be used directly by another industrial process, such as enhanced oil and gas recovery. According to the commenter, such opportunities are limited and only a few early projects would be able to take advantage of these opportunities.
Commenter 9033 also stated that it is unaware that any supplier of this technology is ready or able to offer commercial guarantees for such full-scale systems of carbon capture. The commenter noted that all utility generators require extensive performance guarantees and warranties which cannot be offered without proper demonstration at scale. According to the commenter, all the projects that form a basis for the EPA rule would require extensive revenue sources from niche market opportunities like EOR and chemicals and large federal subsidies, none would stand alone on a common commercial basis which would in turn mean that no new coal burning plant could be permitted or financed. Hence the commenter noted it is unlikely that such systems will be available prior to the EPA obligatory eight-year review of this proposed NSPS.
Commenter 9486 stated they are not certain that an accurate costing estimate can be performed at this time given the state of CCS technology and lack of full scale implementation at a coal-fired power plant. The commenter also expressed concerns with U.S. EPA's reasoning that the costs for CCS will decrease as the technology advances. As U.S. EPA stated, the current economics dictate that very few coal-fired power plants will be constructed even without the requirement to add CCS. According to the commenter, if there is no market for CCS technologies at coal power plants, the cost will remain high for CCS technologies. The commenter concluded that the unproven full scale costing of CCS makes it extremely difficult, if not impossible, to accurately evaluate and determine the cost impacts of this rule.
Commenter 8966 stated the costs of CCS technology are difficult to quantify, in part because there are no examples of currently operating commercial-scale coal-fired power plants equipped with CCS. The commenter stated however, AEP's experience with installation of a validation-scale chilled ammonia-based CCS system at its Mountaineer Plant is particularly valuable in gaining insight into the potentially massive costs of a commercial-scale CCS system.
Commenter 10100 stated there are no commercial ventures in the United States that capture, transport, and inject industrial-scale quantities of CO2 solely for the purposes of carbon sequestration. The commenter also stated that commercial-scale CCS demonstration projects are nascent, and of the five CCS projects that DOE has supported with significant financial incentives, only one appears to be moving forward. Commenter 10391 stated that although no full-scale operational CCS system at a coal-fueled power plant exists in the U.S., EPA conveniently excluded "first of its kind" costs from its rulemaking consideration. According to the commenter, when evaluating increased costs and risks, pilot CCS and experimental projects are largely irrelevant because these projects have been government subsidized. Similarly, EPA likely undervalues regulatory hurdles and risks and overvalues potential revenues from CO2 waste stream sales for possible use in enhanced oil recovery (EOR) fields.
Commenter 9427 stated that instead of focusing on comparative costs for levels of emissions limitations within the Subpart Da source category for justifying a standard level, EPA inappropriately focused on comparing the cost of coal-fired steam generating units using "partial CCS" with costs for another source category or with costs for electricity generation with technologies that are not even regulated under Section 111 to show that coal with partial CCS is "competitive" with other technologies. According to the commenter, because the construction is not complete and operation has not yet begun on actual projects employing CCS cited by EPA in its proposal, the actual costs of projects are completely unknown at this time. Commenter 9505 stated none of the pilot projects described in the proposal actively capture CO2 from plant exhausts or store CO2 in the ground, and because CCS is not operational at these pilot projects, there is no data about continuous operations, commercial scalability, or costs. Hence, the commenter stated, these experimental projects cannot form the basis for a finding that the technology is available.
Commenter 9666 also stated the cost of CCS at smaller demonstration facilities cannot be reliably scaled up to inform predictions about the cost of CCS at commercial units. Indeed, all that is known about the cost of CCS is that it is exorbitantly high. The commenter also stated EPA's estimate of the baseline cost of coal fired power generation is incorrect, which also skews its assessment of the proposed standard's relative cost.
Commenter 10043 stated that because CCS is neither commercially available nor proven at the appropriate scale or size needed by the four pilot projects, the EPA's cost analysis, upon which the EPA based its conclusion that CCS technology has been adequately demonstrated, is highly questionable. The commenter also noted that EPA is contradictory in foretelling reductions in the capital costs of CCS because of research, development and implementation of the technology while also estimating that no new coal-fired power plants will be constructed
  Commenter 9666 refers to the cost overruns at the Kemper facility.  The Kemper site undoubtedly experienced massive cost overruns, but did so for reasons that are not generally applicable, and which cannot legitimately be used as a basis for assessing costs for other facilities.  For example, as documented in detail in the April 15, 2014 Independent Monitor's Prudency Evaluation Report ("Independent Monitor's Prudency Evaluation Report for the Kemper County IGCC Project", prepared by Burns and Roe Enterprises for Mississippi Public Utility Commission staff), at least partly in an effort to obtain an annual tax credit, the project team chose to adopt "a compressed schedule which led to a just-in-time approach to engineering, design, procurement and construction...".  Report, p. 14.  In essence, basic engineering decisions were not made in advance of construction: "By committing to this approach, engineering and design changes which are a normal result of detailed engineering and design were occurring at the same time as, rather than ahead of, construction activities." Id. p. 6.  In BREI's opinion, "several areas were not adequately addressed, executed or implemented in a reasonable manner."  These areas include: project planning/scheduling. The development of a risk management program with sufficient detail and look ahead time horizon, the late development of the original integrated EPC schedule with adequate resource loading, commodity cost estimating and monitoring (which controlled the project estimated cost to the certification estimate of $2.4 billion until the original low contingency was depleted), and the implementation of SCS's and MPCo's internal procedures and policies (or failure to implement certain policies and procedures), and other areas discussed in this report.  All of the areas listed above which were not addressed, executed or implemented in a reasonable manner raise serious doubt to BREI as to the appropriateness and reasonableness of those actions taken by MPCo in implementing this Protect." Report, pp. 14-15. Moreover, the Report indicates all issues with cost related to the gasification unit, not to carbon capture and sequestration.
Commenter 9666 also urges that costs reflect CCS used at full commercial scale, and that costs should not be extrapolated from small scale designs.  Commenters 10391, 10043 and 9505 made a similar comment.  The EPA has carefully considered comments that costs should be assessed reflecting technologies being used at full commercial scale.  For the final standard, the EPA made particular use of the most recent NETL cost estimates for post-combustion CCS, which reflect up-to-date vendor quotes and incorporate the post-combustion capture technology  -  the Shell Cansolv amine-based process  -  that is being utilized at the Boundary Dam Unit #3 facility.
The same commenter indicates the substantial uncertainty for IGCC projects incorporating CCS. The BSER for the final rule is a highly efficient SCPC using partial CCS, not IGCC.  See preamble section V.H. for EPA's cost analysis of the BSER.
Regarding the issue of vendor guarantees (commenter 9033), see preamble section V.F.
A number of commenters (e.g. 9486, 10043) posed a purported chicken-egg type of issue: how can there be learning by doing when new coal-fired plants aren't being constructed.  EPA addresses this issue in preamble section V.I.4.
Commenter 9666 and others maintain that because CCS is such an uncertain technology, there will be hurdles to financing.  Although the EPA does not accept the commenters' characterization of the technology (see e.g preamble section V.F. (vendor guarantees)), but has based estimates of financing costs on "high-risk financial assumptions".  NETL (2015) at p. 18.
The EPA has carefully studied both AEP's comments, its reports on the Mountaineer effort, and the FEED study it prepared (commenter 8966).  AEP especially singled out its difficulties in siting monitoring wells and otherwise siting a sequestration site.  As explained in preamble section V.I.5, this site-specific experience reflects an individual siting challenge which may not be generally applicable.  For example, none of the Class VI permits issued to date by EPA required the number of monitoring wells as at the Mountaineer site.
Commenter 9427 questions the use of the LCOE metric. This issue is addressed in preamble section V.I.1. The commenter also stated EPA's estimate of the baseline cost of coal fired power generation is incorrect, which also skews its assessment of the proposed standard's relative cost. The EPA used DOE/NETL estimates for the baseline cost of coal fired power generation and believes that they are reasonable estimates of the cost of a new coal-fired power plant.  DOE/NETL stated "[T]he cost estimates for plant designs that only contain fully mature technologies, which have been widely deployed at commercial scale (e.g., PC and NGCC power plants without CO2 capture), reflect n[th]-of-a-kind (NOAK) on the technology commercialization maturity spectrum." Further, the final BSER is a highly efficient supercritical PC unit implementing partial CCS to meet a standard of 1,400 lb CO2/MWh-g. The AEP John W. Turk facility is an example of a highly efficient supercritical PC. In comments of AEP (p. 76), AEP represented the cost of the Turk facility as $2,885/kW. The DOE/NETL estimates for such a facility is $2,842/kW (NETL, 2015  -  for a plant using bituminous coal). This close agreement is another validation of the NETL cost methodology.
Commenter 9033 suggested that in setting economic criteria for technology, EPA consider the "typical commercial power plant" which will not have federal subsidies and will likely not have access to chemical or EOR revenue. According to the commenter, EPA needs to recognize that both chemicals and EOR are niche opportunities and not available to most power plants. The commenter added that even in the most optimistic cases, people forecast EOR has consuming perhaps 100 million tons of CO2 (including current natural CO2) and chemicals are in the low millions of tons when compared with the billions of tons required to be reduced.
Commenter 10095 stated EPA cannot rely on revenues from EOR activities, government subsidies, or regulatory programs to defray the cost of partial CCS and that EPA fails to acknowledge that these activities and policies are not widely available, impermanent, not guaranteed, and subject to significant political uncertainties
The EPA is not relying on EOR revenues in its cost analysis.  This is a conservative approach to assessing costs, given that new coal plants are being sited to take advantage of such opportunities. See preamble section V.H.8.
Commenters 10098 and 10239 stated that EPA has pointed to no evidence that any CCS-enabled power plant has been fully funded by a private entity, undercutting EPA's conclusion that CCS actually "can be accommodated by the industry." According to commenter 10098, every CCS project identified in the proposed rule is receiving significant government grants, loan guarantees, and other subsidies, a point that EPA concedes but states that it does "not consider such government subsidies to mean that the costs of CCS would otherwise be unreasonable. Commenters 10098 and 10239 also noted that CCS cannot be accommodated by the industry as evidenced by many examples of the rejection of CCS as BACT on cost grounds and the failure of CCS projects for various economic reasons.
Commenter 10952 also stated that there is no basis to conclude that industry is "accommodating" the costs or can accommodate the costs as only three projects are planned or under construction. The commenter also noted that since none are operational, it is impossible to conclude that their technical configurations are capable of meeting the duty cycle demands placed on base-load EGUs. The commenter referenced EPA's first proposal in which a ten year timeline and the need for ten up and running demonstration projects, noting that this timeline was lacking from the current proposal. According to the commenter, absent any explanation accompanying the proposal, and there is none, here EPA is making nothing short of a guess, a guess that is in clear conflict with its earlier determinations and conclusion, the hallmark of arbitrary rulemaking.  The commenter also stated that the proposal fails to address how CCS projects would be financially viable without such federal funding, specifically EPA must address what alternative financing means outside federal grant monies are available to support an EGU CCS project where CCS is inordinately costly and an unproven commercial technology.
Commenter 10098 stated that EPA's assertion that the costs of CCS can be accommodated by the industry lacks any factual basis, as EPA relies solely on facilities that have received significant government subsidies for construction and there is no guarantee that such subsidies will be available in the future. The commenter also stated that the proposed rule not only fails to acknowledge EPA's current position against counting such subsidies, as discussed in EPA's NSR Manual, it provides no explanation of why a change in position is warranted. According to the commenter, EPA must provide a reasoned analysis as to why it is now abandoning its current, well-established position that tax credits or other government subsidies for a pollution control should not be included in cost analyses.
Commenter 10029 also stated that the Clean Air Act does not permit the EPA to offset costs by relying on general subsidies available to an industry. The commenter referenced 42 CAA Section 111(a)(1), and stated that under that section , the EPA must tak[e] into account the costs of achieving such reduction (i.e. the standard of performance), not the net costs (after accounting for subsidies) of constructing and operating the stationary source.
Commenter 7977 stated that EPA's conclusion that "a section of the industry is already accommodating the costs" of CCS is based on demonstration projects that receive DOE financial assistance. According to the commenter, that financial assistance was available due to legislation that was passed to stimulate the economy during a recession by increasing spending in a specific time period, and it is unreasonable to conclude that the costs of CCS are not exorbitant under circumstances when such funds are limited and will not be available indefinitely.