Commenter 10095 also stated that CO2 transportation operations could also be affected by the unsteady flow of CO2 generated by EGUs during load changes and planned and forced outages, and it is unknown how these fluctuations and suspensions will impact transportation and injection operations.
Commenter 10036 noted that after CO2 is captured, it must be compressed "from near
atmospheric pressure to a pressure between 1,500 and 2,200 psia (pounds per square inch absolute) in order to be transported via pipeline and then injected into an underground storage site" and noted that compressing CO2 is energy intensive and expensive.

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

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

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

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

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

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

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

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

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

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

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

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

Commenter 0588 stated that EPA, in assessing emission reductions from the proposed rule, failed to take into account the CO2 attributable to the oil that is recovered using gas captured at the coal plant and sold to oil companies to enhance EOR activities. According to the commenter, these emissions -a direct consequence of the NSPS- would significantly undermine the effectiveness of the proposed standard, and could even exceed the mass of the CO2 "saved" by partial CCS.  The commenter therefore stated that such a standard would be arbitrary and capricious, for "control technologies cannot be "best" if they create greater problems than they solve."  The commenter stated that EPA completely fails to take into account the expanded carbon footprint of the oil industry caused by its power plant rule, which is an impermissible omission by the administrator, because the emissions attributable to EOR are inherent to the NSPS as envisioned by the administrator, as opposed to being indirect in nature. According to the commenter, in the final rule, she must reasonably account for all CO2 emissions attributable to the NSPS as envisioned by the EPA.
Commenters 5532 and 1612 object strongly to the use of CCS as a mechanism to extract more fossil fuels from the earth that will, for the most part, be burned for energy and themselves contribute GHG's to the atmosphere. Commenters 5532 and 1612 are also concerned that this policy might indirectly encourage inadequately regulated oil-fracking operations and that it will lengthen, not shorten the time before the United States has done its fair share to protect the climate and that employing EOR is a form of fuel switching from coal to oil that works against EPA's efforts to reduce carbon pollution, fight climate change and protect the environment.