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

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

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

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

Commenter 10786 stated that EOR operators are unlikely to purchase or inject CO2 from CCS, unlikely to assume infinite climate stewardship responsibilities as it is inconsistent with law and business practices. The commenter asserted that operators may demand to be compensated rather than paying for the CO2, and that no operator will agree to a complete restructuring of its business for what the commenter estimates as a 5 percent increase in CO2 supply. Commenter 9426 stated that no effort has been made to investigate whether the price of captured CO2 in an EOR application would overcome the increased costs associated with transporting the CO2 long distances.
Today's rule is not inconsistent with other EPA actions related to waste. Although the determination that the BSER is adequately demonstrated and the regulatory impact analysis for this rule relies on GS in deep saline formations, the EPA also recognizes the potential for securely sequestering CO2 via EOR. The EPA recognizes that types of CO2 storage technologies other than geologic sequestration are under development (e.g. precipitated calcium carbonate) and some are currently in commercial scale operation. The final rule also does not foreclose reuse or other recycling options (other than EOR, itself a form of recycling), but rather provides for a case-by-case adjudication by the EPA of applications seeking to demonstrate storage methodologies of efficacy equal to (or surpassing) geologic sequestration.
The EPA also does not accept the comment that subpart RR reporting will dissuade EOR operators from accepting CO2 from an affected source. The cost of compliance with subpart RR is not significant enough to offset the potential revenue for the EOR operator from the sale of produced oil for CCS projects that are reliant on EOR. First, the costs associated with subpart RR are relatively modest, especially in comparison with revenues from an EOR field. In the economic impact analysis for subpart RR, the EPA estimated that an EOR project with a Class II permit would incur a first year cost of up to $147,030 to develop an MRV plan, and an annual cost of $27,787 to maintain the plan; the EPA estimated annual reporting and recordkeeping costs at $13,262 per year. Monitoring costs are estimated to range from $0.02 per metric ton (base case scenario) to approximately $2 per metric ton of CO2 (high scenario). Using a range of scenarios (that included high end estimates), these subpart RR costs are approximately three to four percent of estimated revenues for an average EOR field, indicating that the costs can readily be absorbed. 75 FR 75073.

Furthermore, there is a demand for new CO2 by EOR operators, even beyond current natural sources of CO2. For example, in an April 2014 study, DOE concluded that future development of EOR will need to rely on captured CO2. Thus, the argument that EOR operators will obtain CO2 from other sources without triggering subpart RR responsibilities, which assumes adequate supplies of CO2 from other sources, lacks foundation.

In addition, the Internal Revenue Code section 45Q provides a tax credit for CO2 sequestration which is far greater than subpart RR costs. Section 45Q(a)(1) allows a credit of $20 per metric ton of qualified CO2 that is captured by the taxpayer at a qualified facility, disposed of by the taxpayer in secure geological storage, and not used by the taxpayer as a tertiary injectant. Section 45Q(a)(2) allows a credit of $10 per metric ton of qualified CO2 that is captured by the taxpayer at a qualified facility, used by the taxpayer as a tertiary injectant in a qualified enhanced oil or natural gas recovery project, and disposed of by the taxpayer in secure geological storage. The section 45Q credit for calendar year 2015 is $21.85 per metric ton of qualified CO2 under § 45Q(a)(1) and $10.92 per metric ton of qualified CO2 under section 45Q(a)(2).

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

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

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

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

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

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

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

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

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

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

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

The EPA recognizes that the review process for siting and construction of CO2 pipelines crossing Federal land differs from processes that would be implemented for CO2 pipelines crossing privately owned or other non-Federal land, and that the Federal land management process may have a longer review schedule than for pipelines crossing privately owned or other non-Federal land. However, the EPA does not agree that the Federal land management process represents a substantial impediment to the timely siting and construction of CO2 pipelines that may be needed, as evidenced by the fact that many of the existing CO2 pipelines cross Federal land. BLM conducted reviews of proposed CO2 pipelines in 2014 and other pipeline projects were proposed for review in 2014. The reviews of proposed CO2 pipeline projects conducted by the BLM demonstrates that the Federal agency review process is a manageable process that would not impede the siting and construction of new CO2 pipelines.
Commenter 9735 stated that EOR is only feasible when coal plants are located relatively close to a mature oil field. The reality is that coal and oil formations are often far apart and CO2 pipelines that would be required do not exist. When EOR is not an option, utility companies will need to transport CO2 to appropriate geologic formations, such as saline aquifers. Commenters 8032, 9197, and 9735 noted that regardless of storage method, a vast pipeline infrastructure for CO2 will need to be built that will have siting, permit, and regulatory challenges that will add additional time and cost to any CCS project.
The EPA recognizes that some new EGUs may not be located in the vicinity of EOR formations and may need to transport captured CO2 to saline aquifer or other non-EOR sequestration sites. Potential sequestration sites are located throughout the United States, and construction of CO2 pipelines is adequately demonstrated. The EPA has addressed comments on storage in the Section 6.3 topic titled Geologic Sequestration. State and federal agencies have several decades of experience with CO2 pipeline permits and the EPA anticipates that existing processes will continue to support future needs for siting and construction of new CO2 pipelines. With respect to the timing of siting and construction of new CO2 pipelines, construction of new EGUs is anticipated to be limited for the foreseeable future, and any new EGUs proposed would need to be planned prior to siting and construction, and the EPA anticipates that the CO2 pipelines needed to transport captured CO2 from new EGUs could be planned, sited, and constructed within a similar timeframe as the timeframe for planning, siting, and constructing the new EGU itself. Therefore the EPA does not anticipate that CO2 pipeline siting and construction will represent a substantial barrier for affected EGUs.
Commenter 9201 cited a study that that the U.S. and Canada will need more than 35,000 miles of additional natural gas transmission pipelines (both mainline and laterals) through 2035 to serve anticipated growth in natural gas demand, and that about three fourths of the incremental growth in demand will arise from the power sector doubling its consumption as a result of EPA policies including CO2 NSPS rules for new and existing power plants. Commenter 9201 noted that the EPA did not consider or evaluate the impacts on land use and other environmental values from natural gas pipeline construction to supply increased demand -- including new natural gas power plants.
Siting and construction of proposed interstate natural gas pipelines is subject to certification by FERC. FERC has established and implements procedures for environmental reviews of proposed natural gas pipelines under Federal NEPA regulations and FERC's implementing regulations. NEPA reviews of proposed natural gas pipelines include consideration of land use and other environmental impacts of construction and operation of the proposed pipeline. Proposed intrastate natural gas pipelines are subject to permitting and environmental reviews under state regulations. Therefore, the land use impacts of any natural gas pipelines proposed to support growth in natural gas demand would be subject to project-specific environmental reviews including consideration of land use impacts. FERC conducts environmental reviews of proposed natural gas pipelines during the course of the natural gas pipeline certification process, which takes an average of fourteen to sixteen months.
Safe Drinking Water Act's Underground Injection Control (UIC) Program and Resource Conservation and Recovery Act
Commenters 9425 and 9666 stated concerns with monitoring of CO2 geologic sequestration wells. The commenters noted the Class VI program requires extensive monitoring and fifty years of post-closure site care as a default which will add significant cost to CCS. Commenter 9666 also stated the concern that State program administrators could lengthen the site care responsibility indefinitely. Commenter 9426 asserted that a default of 50 years of post-closure site care is too long and adds significant additional costs. The commenter further stated that program administrators could further lengthen the site care responsibility indefinitely, posing a significant potential obstacle to CCS deployment.
This rule does not change the requirements for site closure of Class VI wells that were established in the Class VI Rule. Site closure is defined by regulation (40 CFR 146.81) as the time at which the Class VI injection well owner or operator is released from post-injection site care responsibilities. Under the Class VI UIC regulations, following cessation of injection, the operator must conduct comprehensive post-injection site care to show the position of the CO2 plume and the associated area of elevated pressure to demonstrate that neither poses an endangerment to USDWs  -  also having the practical effect of preventing releases of CO2 to the atmosphere. Post-injection site care includes appropriate monitoring and other needed actions (including corrective action). The default duration for the post-injection site care period is 50 years, with flexibility for demonstrating that an alternative period is appropriate if it ensures non-endangerment of USDWs. For example, following the operational period for its project, Archer Daniels Midland plans a post-injection site care period of 10 years. Under the Class VI regulations, the owner or operator of a GS site is released from Class VI related post-injection site care responsibilities upon site closure. See generally preamble section V.N.1.
The EPA's cost estimates account for the requirements of the UIC Class VI program, and GHGRP subpart RR, including operational and post-injection site care monitoring, which are components of the UIC Class VI requirements, and subpart RR. Based on DOE/NETL studies, the EPA estimated that the total CO2 transportation, storage, and monitoring cost associated with EGU CCS would comprise less than 5.5 percent of the total cost of electricity in all capture cases modeled. The studies also show that post-injection site care, which includes monitoring, accounts for between 15 and 22 percent of total storage costs. The monitoring costs do not add significantly to the overall cost of CCS.
Commenters 9423, 9425, 9426, 9666 stated concerns with liability. Commenter 9425 acknowledged that the EPA has established new Class VI regulations under the UIC Program for geologic sequestration wells that address some of the uncertainties in the regulatory framework, including site characterization, design and construction requirements for wells, operating and post-injection monitoring, testing of well integrity and financial responsibility. However, the commenter stated that the proposal does not address liability which remains an impediment to broad deployment of CCS. Commenter 9666 stated that limitation of liability would most likely require congressional action and it is unlikely the EPA could have addressed this issue effectively by rule without additional authority from Congress. The commenter noted this as another indicator that CCS is not an available technology for new EGUs. Commenter 10033 stated that from the perspective of CCS technology itself, although several projects have been successful, these projects have been too small and few in number to provide confidence that carbon sequestration projects will be protective of underground sources of drinking water at the large injection volumes and long time frames that would be found at a commercial power plant.
Commenter 9472 stated that the EPA did not address two types of significant challenges operating CO2 storage facilities in saline formations face. First, the existing regulations for CO2 injection in saline formations, permitted as Class VI injection wells under the EPA's UIC program, pose practical barriers to project development including the 50 year post-injection site care monitoring period. Second, the long-term liability framework for injected CO2 remains uncertain in many areas of the country and limits the opportunity to store CO2 in saline formations in those regions. This period has the potential to exceed the lifetime of organizations involved in the original injection program, adding contractual and legal challenges to the development of a CO2 injection operation. The commenter also noted that while the full breadth of considerations will vary by site and project, they impact the feasibility of integrating CCS at a power plant, and must be sorted out prior to the beginning of CCS operations because subsurface storage must be operational at all times for a CCS project.
The EPA has addressed comments regarding liability in the Section 6.3 topic titled Liability and post-injection site care monitoring elsewhere in this topic titled Safe Drinking Water Act's Underground Injection Control (UIC) Program and Resource Conservation and Recovery Act. Limitation of liability is not a significant impediment to this rule. The EPA has issued Class VI permits for six wells under two projects. Both permit applicants addressed siting and operational aspects of GS (including issues relating to volumes of the CO2 and nature of the CO2 injectate), and included monitoring that helps provide assurance that CO2 will not migrate to shallower formations. The permits were based on findings that regional and local features at the site allow the site to receive injected CO2 in specified amounts without buildup of pressure which would create faults or fractures, and further, that monitoring provides early warning of any changes to groundwater or CO2 leakage. The permitting of these projects illustrates that permit applicants were able to address perceived challenges, including liability. These permits demonstrate the EPA's view that these projects are capable of safely and securely sequestering large volumes of CO2 -- including from steam generating units -- for long-term storage since the EPA would not otherwise have issued the permits. Furthermore, as shown in preamble section V.M, monitoring studies conducted at EOR and saline sites in the U.S. and internationally have demonstrated that large injection volumes can be safely injected.
Commenter 10033 stated that while EPA's Class VI rules on carbon sequestration promulgated under the UIC program address many of the potential causes of drinking water contamination, the commenter continues to be concerned with some of the rule's provisions that were included over the strong objections of the drinking water community. For example, commenter noted that the "injection depth waiver" process allowed by the Class VI rule has many limitations that could result in degradation of USDW (underground sources of drinking water). According to the commenter, repeated requests to clarify and limit injection depth waivers to protect USDW have so far gone unanswered and several expected guidance documents, such as the guidance on injection depth waivers, have not yet been publicly released. The commenter and commenter 10786 stated that to their knowledge, there has never been a single Class VI UIC permit issued anywhere, and only a few applications have been submitted. The commenter concluded that although the foundation for a regulatory system exists, it is not yet a mature process and should not be relied upon at a large scale before it has been fully proven.
Comments regarding the final Class VI rule requirements related to injection depth waivers are outside the scope of this rulemaking. This rule does not change the existing injection depth waiver process, which was established by the Class VI rule. See 75 FR 77254 (December 10, 2010).
In the time since the commenter submitted comments, the EPA has issued six Class VI permits for two projects: an Archer Daniels Midland ethanol facility in Decatur Illinois and the FutureGen Industrial Alliance project. It would not have done so, and under the regulations could not have done so, without demonstrations that CO2 would be securely confined.
Commenter 9596 stated that although the recent promulgation of rules under the Resource Conservation and Recovery Act (RCRA) and the Safe Drinking Water Act (SDWA) for underground CO2 injection wells may remove a certain amount of regulatory uncertainty, it has created new concerns in the oil and gas exploration industry over the regulatory impact of accepting CO2 from EGUs in EOR operations.
With respect to the RCRA conditional exclusion rule, EPA made clear that that rule was not intended to affect the RCRA regulatory status of CO2 streams that are injected into wells other than UIC Class VI wells, including UIC Class II wells used for EOR. See 79 CFR 355 (Jan. 3, 2014).
In response to inquiries and concerns, similar to those of Commenter 9596, directed to EPA's Underground Injection Control Program, on April 23, 2015, the EPA's Director of the Office of Ground Water and Drinking Water issued a memorandum to its regional UIC Program Directors reflecting the principle that injection of anthropogenic CO2 for enhanced recovery through Class II wells does not force transition of these wells to Class VI wells  -  not during the well's active operation and not when EOR operations cease. See section V.N.5.a of the preamble for a summary of the memorandum.
Commenter 10786 stated that the NSPS is not in accord with SDWA's provisions for delegated State Class II programs, including with respect to the increased risk analysis under section 144.19. Unless taking place within the context of an existing Class II permit (presumably issued by a State agency), none of these collateral inquiries regarding existing CO2-EOR operations is envisioned by or authorized under SDWA and its governing regulations. In a State with primacy over its Class II program, all relevant assessments and decisions under 40 C.F.R. Section 144.19 are in the exclusive domain of the relevant State Class II regulator. Indeed, the Transition Guidance later seems to concede as much, noting that relevant considerations will have to be addressed in specific Class II permits. Transition Guidance, p. 6.
The EPA encourages Class II and Class VI UIC Program Directors to work together to address the potential need for transition from Class II to Class VI permits. Additionally, the EPA believes that the best implementation approach is for states to administer both the Class II and the Class VI UIC programs. Nothing in this final rule changes the provisions of SDWA or the authority of the states to administer Class II permits.
Commenter 10786 stated that the Section 144.19 confirms that NSPS is not a "logical outgrowth" of the originally proposed rule. The commenter noted that the EPA's interpretation of 40 C.F.R. Section 144.19 advanced in the Transition Guidance and implicitly adopted by the NSPS provides post-hoc confirmation that this final regulatory provision is not a "logical outgrowth" of EPA's original proposal. It was not until the EPA released the Transition Guidance, as implicitly incorporated thereafter by the NSPS, that industry was made aware that the Agency is now reading section 144.19 as authorizing forced conversions to Class VI (and perhaps at the Class VI Director's discretion). The positions in the NSPS are in direct conflict with both section 144.19 and the Agency's prior statements regarding how EOR was to be treated on these matters.
The commenter is mistaken. EOR wells across the United States are currently permitted as UIC Class II wells. CO2 storage associated with Class II wells is a common occurrence, and where injected through Class II-permitted wells for the purpose of oil or gas-related recovery CO2 storage can occur in a manner protective of underground sources of drinking water. See also previous response.
Commenter 9423 stated the disincentives created by EPA for use of captured CO2 in EOR activities is further exacerbated by EPA's recent Draft UIC Program Guidance on Transitioning Class II Wells to Class VI wells that gives broad discretion to the EPA to determine when an existing Class II EOR well should be regulated and permitted as a Class VI geosequestration well. According to the commenter, the uncertainty of whether a Class II EOR well would be required to meet Class VI geosequestration well requirements as well as the cost, time, and long-term liability to transition a well from Class II to Class VI will be an additional significant disincentive for EOR well operators to accept utility- produced CO2. Commenter 9423 stated that the Class VI UIC regulations as adopted require a determination as to whether or not the primary purpose of the injection of CO2 is enhanced recovery. If the answer is yes, the well remains a Class II well. If the answer is no, then a determination must be made as to whether risks to underground drinking water sources have increased.
Commenters 9731 and 10786 stated that if CO2 is to be a viable commercial product for use in EOR, the EPA must be mindful of the consequences of other significant regulations. For example, the UIC Class VI rule will mandate a conversion from the Class II wells currently used for CO2 injection, which will create additional costs with a number of regulatory and legal uncertainties and challenges.
Commenter 10786 stated that long-term storage with EOR will require an understanding of state legal and regulatory frameworks and how businesses can conduct operations under Class VI that is not present in the NSPS.
Several commenters (9197, 9596, 9780) stated that the need to transition from Class II injection wells to Class VI wells under draft EPA guidance could further discourage EOR operators from accepting CO2 from EGUs for GS.
On April 23, 2015, the EPA issued a memorandum from the Director of the Office of Ground Water and Drinking Water to regional UIC Program Directors in its regional offices, and summarized in section V.N.5.a of the preamble, that makes clear that the commenters' concerns are misplaced. The EPA recognizes the widespread use of EOR and the expectation that injected CO2 can remain underground. The memorandum reflected these principles:
      *       Geologic storage of CO2 can continue to be permitted under the UIC Class II program.
      *       Use of anthropogenic CO2 in EOR operations does not necessitate a Class VI permit.
      *       Class VI site closure requirements are not required for Class II CO2 injection operations.
      *       EOR operations that are focused on oil or gas production will be managed under the Class II program. If oil or gas recovery is no longer a significant aspect of a Class II permitted EOR operation, the key factor in determining the potential need to transition a EOR operation from Class II to Class VI is increased risk to USDWs related to significant storage of CO2 in the reservoir, where the regulatory tools of the Class II program cannot successfully manage the risk.