a. Class VI requirements. In 2010, the EPA established a new class of well, Class VI. Class VI wells are used to inject CO2 into the subsurface for the purpose of long-term sequestration. See 75 FR 77230 (Dec. 10, 2010). This rule accounts for the unique nature of CO2 injection for large-scale GS. Specifically, the EPA addressed the unique characteristics of CO2 injection for GS including the large CO2 injection volumes anticipated at GS projects, relative buoyancy of CO2, its mobility within subsurface geologic formations, and its corrosivity in the presence of water. The UIC Class VI rule was developed to facilitate GS and ensure protection of USDWs from the particular risks that may be posed by large scale CO2 injection for purposes of long-term GS. The Class VI rule establishes technical requirements for the permitting, geologic site characterization, area of review (i.e., the project area) and corrective action, well construction, operation, mechanical integrity testing, monitoring, well plugging, post-injection site care, site closure, and financial responsibility for the purpose of protecting USDWs. Notably:
      *       Site characterization includes assessment of the geologic, hydrogeologic, geochemical, and geomechanical properties of a proposed GS site to ensure that Class VI wells are sited in appropriate locations and CO2 streams are injected into suitable formations with a confining zone or zones free of transmissive faults or fractures to ensure USDW protection.[,] Site characterization is designed to eliminate unacceptable sites that may pose risks to USDWs. Generally, injection of CO2 for GS should occur beneath the lowermost formation containing a USDW. To increase the availability of Class VI sites in geographic areas with very deep USDWs, waivers from the injection depth requirements may be sought where owners or operators can demonstrate USDW protection.
      *       Owners or operators of Class VI wells must delineate the project area of review using computational modeling that accounts for the physical and chemical properties of the injected CO2 and displaced fluids and is based on an iterative process of available site characterization, monitoring, and operational data. Within the area of review, owners or operators must identify and evaluate all artificial penetrations to identify those that need corrective action to prevent the movement of CO2 or other fluids into or between USDWs.[,] Due to the potentially large size of the area of review for Class VI wells, corrective actions may be conducted on a phased basis during the lifetime of the project. Periodic reevaluation of the area of review is required and enables owners or operators to incorporate previously collected monitoring and operational data to verify that the CO2 plume and the associated area of elevated pressure are moving as predicted within the subsurface.
      *       Well construction must use materials that can withstand contact with CO2 over the operational and post-injection life of the project. These requirements address the unique physical characteristics of CO2, including its buoyancy relative to other fluids in the subsurface and its potential corrosivity in the presence of water.
      *       Requirements for operation of Class VI injection wells account for the unique conditions that will occur during large-scale GS including buoyancy, corrosivity, and high sustained pressures over long periods of operation.[,]
      *       Owners or operators of Class VI wells must develop and implement a comprehensive testing and monitoring plan for their projects that includes injectate analysis, mechanical integrity testing, corrosion monitoring, ground water and geochemical monitoring, pressure fall-off testing, CO2 plume and pressure front monitoring and tracking, and, at the discretion of the Class VI director, surface air and/or soil gas monitoring. Owners and operators must periodically review the testing and monitoring plan to incorporate operational and monitoring data and the most recent area of review reevaluation. Robust monitoring of the CO2 stream, injection pressures, integrity of the injection well, ground water quality and geochemistry, and monitoring of the CO2 plume and position of the pressure front throughout injection will ensure protection of USDWs from endangerment, preserve water quality, and allow for timely detection of any leakage of CO2 or displaced formation fluids.
      *       Although subsurface monitoring is the primary and effective means of determining if there are any risks to a USDW, the Class VI rule also authorizes the UIC Program Director to require surface air and/or soil gas monitoring on a site-specific basis. For example, the Class VI Director may require surface air/soil gas monitoring of the flux of CO2 out of the subsurface, with elevation of CO2 levels above background serving as an indicator of potential leakage and USDW endangerment.
      *       Class VI well owners or operators must develop and update a site-specific, comprehensive emergency and remedial response plan that describes actions to be taken (e.g., cease injection) to address potential events that may cause endangerment to a USDW during the construction, operation, and post-injection site care periods of the project.
      *       Financial responsibility demonstrations are required to ensure that funds will be available for all area of review corrective action, injection well plugging, post-injection site care, site closure, and emergency and remedial response.
      *       Following cessation of injection, the operator must conduct comprehensive post-injection site care activities to show the position of the CO2 plume and the associated area of elevated pressure to demonstrate that neither poses an endangerment to USDWs. The injection well also must be plugged, and following a demonstration of non-endangerment of USDWs by the Class VI owner or operator, the site must be closed.[,] 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. Following successful closure, the facility property deed must record that the underlying land is used for GS.
     The EPA has completed technical guidance documents on Class VI well site characterization, area of review and corrective action, well testing and monitoring, project plan development, well construction, and financial responsibility.[,][,][,][,][,] The EPA has also prepared and made available for public comment draft guidance documents on transitioning Class II wells to Class VI wells; well plugging, post-injection site care, and site closure; and recordkeeping, reporting, and data management.[,][,][,]
      To inform the development of the UIC Class VI rule, the EPA solicited stakeholder input and reviewed ongoing domestic and international GS research, demonstration, and deployment projects. The EPA also leveraged injection experience of the UIC Program, such as injection via Class II wells for EOR. A description of the work conducted by the EPA in support of the UIC Class VI rule can be found in the preamble for the final rule (see 75 FR 77230 and 77237-240; December 10, 2010).
      The EPA has issued Class VI permits for six wells under two projects. In September 2014, a UIC Class VI injection well permit (to construct) was issued by the EPA to Archer Daniels Midland for an ethanol facility in Decatur, Illinois. The goal of the project is to demonstrate the ability of the Mount Simon geologic formation, a deep saline formation, to accept and retain industrial scale volumes of CO2 for permanent GS. The permitted well has a projected operational period of five years, during which time 5.5 million metric tons of CO2 will be injected into an area of review with a radius of approximately 2 miles. Following the operational period, Archer Daniels Midland plans a post-injection site care period of ten years. In September 2014, the EPA also issued four Class VI injection well permits (to construct) to the FutureGen Industrial Alliance project in Jacksonville, Illinois, which proposed to capture CO2 emissions from a coal-fired power plant in Meredosia, Illinois and transport the CO2 by pipeline approximately 30 miles to the deep saline GS site. The Alliance proposed to inject a total of 22 million metric tons of CO2 into an area of review with a radius of approximately 24 miles over the 20 year life of the project, with a post-injection site care period of fifty years.
      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 to issuance of Class VI permits. 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 geologic timeframes since the EPA would not otherwise have issued the permits.
b. Class II requirements. As explained in section K.2 above, CO2 has been injected into the subsurface via injection wells for EOR, boosting production efficiency by re-pressurizing oil and gas reservoirs and increasing the mobility of oil. There are decades of industry experience in operating EOR projects. The CO2 injection wells used for EOR are regulated through the UIC Class II program. CO2 storage associated with Class II wells is a common occurrence and CO2 can be safely stored where injected through Class II-permitted wells for the purpose of enhanced oil or gas-related recovery.
      UIC Class II regulations issued under section 1421 of SDWA provide minimum federal requirements for site characterization, area of review, well construction (e.g., casing and cementing), well operation (e.g., injection pressure), injectate sampling, mechanical integrity testing, plugging and abandonment, financial responsibility, and reporting. Class II wells must undergo periodic mechanical integrity testing which will detect well construction and operational conditions that could lead to loss of injectate and migration into USDWs.
      Section 1425 of SDWA allows states to demonstrate that their program is effective in preventing endangerment of USDWs. These programs must include permitting, inspection, monitoring, record-keeping, and reporting components.
2. Relevant requirements of the Greenhouse Gas Reporting Program (GHGRP)
      The GHGRP requires reporting of facility-level GHG data and other relevant information from large sources and suppliers in the United States. The final rules under 40 CFR part 60 specifically require that if an affected EGU captures CO2 to meet the applicable emissions limit, the EGU must report in accordance with 40 CFR part 98, subpart PP (Suppliers of Carbon Dioxide) and the captured CO2 must be injected at a facility or facilities that reports in accordance with 40 CFR part 98, subpart RR (Geologic Sequestration of Carbon Dioxide). See 40 CFR 60.46Da(h)(5) and 40 CFR 60.5555(d). Taken together, these requirements ensure that the amount of captured and sequestered CO2 will be tracked as appropriate at project- and national-levels, and that the status of the CO2 in its sequestration site will be monitored, including air-side monitoring and reporting.
      Specifically, subpart PP provides requirements to account for CO2 supplied to the economy. This subpart requires affected facilities with production process units that capture a CO2 stream for purposes of supplying CO2 for commercial applications or that capture and maintain custody of a CO2 stream in order to sequester or otherwise inject it underground to report the mass of CO2 captured and supplied to the economy. CO2 suppliers are required to report the annual quantity of CO2 transferred offsite and its end use, including GS.
      This rule finalizes amendments to subpart PP reporting requirements, specifically requiring that the following pieces of information be reported: (1) the electronic GHG Reporting Tool identification (e-GGRT ID) of the EGU facility from which CO2 was captured, and (2) the e-GGRT ID(s) for, and mass of CO2 transferred to, each GS site reporting under subpart RR.
      As noted, this final rule also requires that any affected EGU unit that captures CO2 to meet the applicable emissions limit must transfer the captured CO2 to a facility that reports under GHGRP subpart RR. In order to provide clarity on this requirement, the EPA reworded the proposed language under 40 CFR 60.46Da(h)(5) and 40 CFR 60.5555(d) to use the phrase "If your affected unit captures CO2" in place of the phrases "If your affected unit uses geologic sequestration" and "If your affected unit employs geologic sequestration", respectively. This revision is not a change from the EPA's initial intent.
      Reporting under subpart RR is required for all facilities that have received a Class VI UIC permit for injection of CO2. Subpart RR requires facilities meeting the source category definition (40 CFR 98.440) for any well or group of wells to report basic information on the mass of CO2 received for injection; develop and implement an EPA-approved monitoring, reporting, and verification (MRV) plan; report the mass of CO2 sequestered using a mass balance approach; and report annual monitoring activities.[,][,][,] Although deep subsurface monitoring is the primary and effective means of determining if there are any leaks to a USDW, the monitoring employed under a subpart RR MRV Plan can be utilized, if required by the UIC Program Director, to further ensure protection of USDWs. The subpart RR MRV plan includes five major components:
      * A delineation of monitoring areas based on the CO2 plume location. Monitoring may be phased in over time.
      * An identification and evaluation of the potential surface leakage pathways and an assessment of the likelihood, magnitude, and timing, of surface leakage of CO2 through these pathways. The monitoring program will be designed to address the risks identified.
      * A strategy for detecting and quantifying any surface leakage of CO2 in the event leakage occurs. Multiple monitoring methods and accounting techniques can be used to address changes in plume size and risks over time.
      * An approach for establishing the expected baselines for monitoring CO2 surface leakage. Baseline data represent pre-injection site conditions and are used to identify potential anomalies in monitoring data.
      * A summary of considerations made to calculate site-specific variables for the mass balance equation. Site-specific variables may include calculating CO2 emissions from equipment leaks and vented emissions of CO2 from surface equipment, and considerations for calculating CO2 from produced fluids.
      Subpart RR provides a nationally consistent mass balance framework for reporting the mass of CO2 that is sequestered. Certain monitoring and operational data for a GS site is required to be reported to the EPA annually. More information on the MRV plan and annual reporting is available in the subpart RR final rule (75 FR 75065; December 1, 2010) and its associated technical support document.
      Under this final rule, any well receiving CO2 captured from an affected source, be it a Class VI or Class II well, must report under subpart RR. As explained below in Section L.5.a, a Class II well's UIC regulatory status does not change because it receives such CO2. Nor does it change by virtue of reporting under subpart RR.
3. UIC and GHGRP rules provide assurance to prevent, monitor, and address releases of sequestered CO2 to air
      Together the requirements of the UIC and GHGRP programs help ensure that sequestered CO2 will remain secure, and provide the monitoring mechanisms to identify and address potential leakage using SDWA and CAA authorities. The EPA designed the GHGRP subpart RR requirements for GS with consideration of UIC requirements. The monitoring required by GHGRP subpart RR is complementary to and builds on UIC monitoring and testing requirements. 75 FR 77263. Although the regulations for Class VI and Class II injection wells are designed to ensure protection of USDWs from endangerment, as explained below, the practical effect of these complementary technical requirements is that they also prevent releases of CO2 to the atmosphere.
      The UIC and GHGRP programs are built upon an understanding of the mechanisms by which CO2 is retained in geologic formations, which are well understood and proven.
         * Structural and stratigraphic trapping is a physical trapping mechanism that occurs when the CO2 reaches a stratigraphic zone with low permeability (i.e., geologic confining system) that prevents further upward migration.
         * Residual trapping is a physical trapping mechanism that occurs as residual CO2 is immobilized in formation pore spaces as disconnected droplets or bubbles at the trailing edge of the plume due to capillary forces.
         * Adsorption trapping is another physical trapping mechanism that occurs when CO2 molecules attach to the surfaces of coal and certain organic rich shales, displacing other molecules such as methane.
         * Solubility trapping is a geochemical trapping mechanism where a portion of the CO2 from the pure fluid phase dissolves into native ground water and hydrocarbons.
         * Mineral trapping is a geochemical trapping mechanism that occurs when chemical reactions between the dissolved CO2 and minerals in the formation lead to the precipitation of solid carbonate minerals.
a. Class VI Wells. As just discussed in section L.1, the UIC Class VI rule provides a framework to ensure the safety of underground injection of CO2 such that USDWs are not endangered. Through the injection well permit application process, the Class VI permit applicant (i.e., a prospective Class VI well owner or operator) must demonstrate that the injected CO2 will be trapped and retained in the geologic formation, and not migrate out of the injection zone or the approved project area (i.e., the area of review). To assure that CO2 is confined within the injection zone, major components to be considered and included in Class VI permits are site characterization, area of review delineation and corrective action, well construction and operation, testing and monitoring, financial responsibility, post-injection site care, well plugging, emergency and remedial response, and site closure as described in Section L.1.
      Site characterization provides the foundation for successful GS projects. It includes evaluation of the chemical and physical mechanisms that will occur in the subsurface to immobilize and securely store the CO2 within the injection zone for geologic timeframes (see above). Site characterization requires a detailed assessment of the geologic, hydrogeologic, geochemical, and geomechanical properties of the proposed GS site to ensure that wells are sited in suitable locations. Data and information collected during site characterization are used in the development of injection well construction and operating plans; provide inputs for modeling the extent of the injected CO2 plume and related pressure front; and establish baseline information to which geochemical, geophysical, and hydrogeologic site monitoring data collected over the life of the injection project can be compared.
      The Class VI rules contain rigorous subsurface monitoring requirements to assure that the chosen site is functioning as characterized. This subsurface monitoring should detect leakage of CO2 before CO2 would reach the atmosphere.  For example, when USDWs are present, they are generally located above the injection zone. If CO2 were to reach a USDW prior to being released to the atmosphere, the presence of CO2 or geochemical changes that would be caused by CO2 migration into unauthorized zones would be detected by a UIC Class VI monitoring program that is approved and periodically evaluated/adjusted based on permit conditions.
      Likewise, UIC Class VI mechanical integrity testing requirements are designed to confirm that a well maintains internal and external mechanical integrity. Continuous monitoring of the internal mechanical integrity of Class VI wells ensures that injection wells maintain integrity and serves as a way to detect problems with the well system. Mechanical integrity testing provides an early indication of potential issues that could lead to CO2 leakage from the confining zone, providing assurance and verification that CO2 will not reach the atmosphere.
      Further assurance is provided by the regulatory requirement that injection must cease if there is evidence that the injected CO2 and/or associated pressure front may cause endangerment to a USDW. Once the anomalous operating conditions are verified, the cessation of injection, as required by UIC permits, will minimize any risk of release to air.
      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.
      As the EPA has found, "[the] UIC Class VI injection well requirements, which are specifically designed to ensure that the CO2 and any incidental associated substances derived from the source materials and the capture process) will be isolated within the injection zone. The EPA concluded that the elimination of exposure routes through these requirements, which are implemented through a SDWA UIC permit, will ensure protection of human health and the environment..."
      GHGRP subpart RR complements these UIC Class VI requirements. Requirements under the UIC program are focused on demonstrating that USDWs are not endangered as a result of CO2 injection into the subsurface, while requirements under the GHGRP through subpart RR enable accounting for CO2 that is geologically sequestered. A methodology to account for potential leakage is developed as part of the subpart RR MRV plan (see Section L.2). The MRV plan submitted for subpart RR may describe (or provide by reference to the UIC permit) the relevant elements of the UIC permit (e.g. assessment of leakage pathways in the monitoring area) and how those elements satisfy the subpart RR requirements. The MRV plan required under subpart RR may rely upon the knowledge of the subsurface location of CO2 and site characteristics that are developed in the permit application process, and operational monitoring results for UIC Class VI permitted wells.
      In summary, there are well-recognized physical mechanisms for storing CO2 securely. The comprehensive and rigorous site characterization requirements of the Class VI rules assure that sites with these properties are selected. Subsurface monitoring serves to assure that the sequestration site operates as intended, and this monitoring continues through a post-closure period. Although release of CO2 to air is unlikely and should be detected prior to release by subsurface monitoring, the subpart RR air-side monitoring and reporting regime provides backup assurance that sequestered CO2 has not been released to the atmosphere.
b. Class II wells. The Class II rules likewise are designed to protect USDWs during EOR operation, including the injection of CO2 for EOR. For example, UIC Class II minimum federal requirements promulgated under SDWA address site characterization, area of review, well construction (e.g., casing and cementing), well operation (e.g., injection pressure), injectate sampling, mechanical integrity testing, plugging and abandonment, financial responsibility, and reporting. Class II wells must undergo periodic mechanical integrity testing which will detect well construction and operational conditions that could lead to loss of injectate and migration into USDWs. The establishment of maximum injection pressures, designed to ensure that the pressure in the injection zone during injection does not initiate new fractures or propagate existing fractures in the confining zone prevents injection from causing the movement of fluids into an underground source of drinking water. The safeguards that protect USDWs also serve as an early warning mechanism for releases to air.
      CO2 injected via Class II wells becomes sequestered by the trapping mechanisms described above in Section L.3.a. As with Class VI wells, for Class II wells that report under subpart RR, there is monitoring to evaluate whether CO2 used for EOR will remain safely in place both during and after the injection period. Subpart RR provides a CO2 accounting framework that will enable EPA to assess both the project-level and national efficacy of geologic sequestration to determine whether additional requirements are necessary and, if so, inform the design of such regulations.
   c. Response to Comments. Commenters maintained that GS was not demonstrated for CO2 captured from EGUs. In addition, commenters noted that the volumes of captured CO2 would be considerably larger than from existing GS sites, and could quadruple amounts injected into Class II EOR wells. In addition to volumes of CO2 to be injected, commenters opined on the possibility of sporadic CO2 supply due to the nature of EGU operation.
      The EPA does not agree. CO2 capture from EGUs is demonstrated as discussed in Sections V.D and V.E. As discussed below, the volumes of CO2 are comparable to the amounts that have been injected at large scale commercial operations. The EPA also disagrees that the volume of CO2 would quadruple amounts injected into Class II EOR wells because CO2 may be sequestered in deep saline formations, which have widespread geographic availability (see Section J.1). The BSER determination and regulatory impact analysis for this rule relies on GS in deep saline formations. However, the EPA also recognizes the potential for sequestering CO2 via EOR and allows the use of EOR as a compliance option. According to data reported to the GHGRP, approximately 60 million metric tons of CO2 were supplied to EOR in the United States in 2013. Approximately 70 percent of total CO2 supplied in the United States was produced from geologic (natural) CO2 sources and approximately 30 percent was captured from anthropogenic sources. CO2 pipeline systems, such as those serving the Permian Basin, have multiple sources of CO2 that serve to levelize the pipeline supply thus minimizing the effect of supply on the EOR operator.
      GS of anthropogenic CO2 in deep saline formations is demonstrated. First, as explained above, the EPA has issued construction permits under the Class VI program. It would not have done so, and under the regulations cannot have done so, without demonstrations that CO2 would be securely confined. One of these projects was for a steam generating EGU.
      Second, international experience with large scale commercial GS projects has demonstrated through extensive monitoring programs that large volumes of CO2 can be safely injected and securely sequestered for long periods of time at volumes and rates consistent with those expected under this rule. This experience has also demonstrated the value and efficacy of monitoring programs to determine the location of CO2 in the subsurface and detect potential leakage through the presence of CO2 in the shallow subsurface, near surface and air.
      The Sleipner CO2 Storage Project is located at an offshore gas field in the North Sea where CO2 must be removed from the natural gas in order to meet customer requirements and reduce costs. The project began injecting CO2 into the deep subsurface in 1996. The single offshore injection well injects approximately 1 million metric tons per year into a thick, permeable sandstone above the gas producing zone. Approximately 15 million metric tons of CO2 have been injected since inception. Many US and international organizations have conducted monitoring at Sleipner. The location and dimensions of the CO2 plume have been measured numerous times using 3-dimensional seismic monitoring since the 1994 pre-injection survey. The monitoring data have demonstrated that although the plume is behaving differently than initially modeled due to thin layers of impermeable shale that were not initially identified in the reservoir model, the CO2 remains trapped in the injection zone. Numerous other techniques have been successfully used to monitor CO2 storage at Sleipner. The research and monitoring at Sleipner demonstrates the value of a comprehensive approach to site characterization, computational modeling and monitoring, as is required under UIC Class VI rules. The experience at Sleipner demonstrates that large volumes of CO2, of the same order of magnitude expected for an EGU, can be safely injected and stored in saline reservoirs over an extended period.
      Snøhvit is another large offshore CO2 storage project, located at a gas field in the Barents Sea. Like Sleipner the natural gas must be treated to reduce high levels of CO2 to meet processing standards and reduce costs. Gas is transported via pipeline 95 miles to a gas processing and liquefied natural gas plant and the CO2 is piped back offshore for injection. Approximately 0.7 million metric tons per year CO2 are injected into permeable sandstone below the gas reservoir. Between 2008 and 2011, the operator observed pressure increases in the injection formation (Tubaen Formation) greater than expected and conducted time lapse seismic surveys and studies of the injection zone and concluded that the pressure increase was mainly caused by a limited storage capacity in the formation. In 2011, the injection well was modified and injection was initiated in a second interval (Stø Formation) in the field to increase the storage capacity. Approximately 3 million metric tons of CO2 have been injected since 2008. Monitoring demonstrates that no leakage has occurred, again demonstrating that large volumes of CO2, of the same order of magnitude expected for an EGU, can be safely injected and stored in deep saline formations over an extended period.
      As discussed above in Section K, CO2 from the Great Plains Synfuels plant in North Dakota has been injected into the Weyburn oil field in Saskatchewan Canada since 2000. Over that time period the project has injected more than 16 million metric tons of CO2. It is anticipated that approximately 40 million metric tons of CO2 will be permanently sequestered over the lifespan of the project. Extensive monitoring by U.S. and international partners has demonstrated that no leakage has occurred. The sources of CO2 for EOR may vary (e.g., industrial processes, power generation), however this does not impact the effectiveness of EOR operations (see Section K.2).
      CO2 used for EOR may come from anthropogenic or natural sources. The source of the CO2 does not impact the effectiveness of the EOR operation. CO2 capture, treatment and processing steps provide a concentrated stream of CO2 in order to meet the needs of the intended end use. CO2 pipeline specifications of the U.S. Department of Transportation Pipeline Hazardous Materials Safety Administration found at 49 CFR part 195 (Transportation of Hazardous Liquids by Pipeline) apply regardless of the source of the CO2 and take into account CO2 composition, impurities, and phase behavior. Additionally, EOR operators and transport companies have specifications to ensure related to the composition of CO2. These requirements and specifications ensure EOR operators receive a known and consistent CO2 stream.
      At the In Salah CO2 storage project in Algeria, CO2 is removed from natural gas produced at three nearby gas fields in order to meet export quality specification. The CO2 is transported by pipeline approximately 3 miles to the injection site. Three horizontal wells are used to inject the CO2 into the down-dip aquifer leg of the gas reservoir approximately 6,200 feet deep. Between 2004 and 2011 over 3.8 million metric tons of CO2 were stored. Injection rates in 2010 and 2011 were approximately 1 million tons per year. Storage integrity has been monitored by several US and international organizations and the monitoring program has employed a wide range of geophysical and geochemical methods, including time lapse seismic, microseismic, wellhead sampling, tracers, down-hole logging, core analysis, surface gas monitoring, groundwater aquifer monitoring and satellite data. The data have been used to support periodic risk assessments during the operational phase of the project. In 2010 new data from seismic, satellite and geomechanical models were used to inform the risk assessment and led to the decision to reduce CO2 injection pressures due to risk of vertical leakage into the lower caprock, and risk of loss of well integrity. The caprock at the site consisted of main caprock units, providing the primary seal, and lower caprock units, providing additional buffers. There was no leakage from the well or through the caprock, but the risk analysis identified an increased risk of leakage, therefore, the aforementioned precautions were taken. Additional analysis of the reservoir, seismic and geomechanical data led to the decision to suspend CO2 injection in June 2011. No leakage has occurred and the injected CO2 remains safely stored in the subsurface. The decision to proceed with safe shutdown of injection resulted from the analysis of seismic and geomechanical data to identify and respond to storage site risk. The In Salah project demonstrates the value of developing an integrated and comprehensive set of baseline site data prior to the start of injection, and the importance of regular review of monitoring data. Commenters also noted that the data collection and analysis had proven effective at preventing any release of sequestered CO2 to either underground drinking water sources or to the ambient air.
      These projects demonstrate that sequestration of CO2 captured from industrial operations has been successfully conducted on a large scale and over relatively long periods of time. The volumes of captured CO2 are within the same order of magnitude as that expected from EGUs. Even though potentially adverse conditions were identified at some projects (In Salah and Snøhvit), there were no releases to air and the monitoring systems were effective in identifying the issues in a timely manner, and these issues were addressed effectively. In each case, the site-specific characteristics were evaluated on a case-by-case basis to select a site where the geologic conditions are suitable to ensure long-term, safe storage of CO2. Each project was designed to address the site-specific characteristics and operated to successfully inject CO2 for safe storage.
5. Must the standard of performance for CO2 include CAA requirements on the sequestration site?
      One commenter maintained as a matter of law that a standard predicated on use of CCS is not a "system of emission reduction", and therefore is not a "standard of performance" within the meaning of section 111 (a)(1) of the Act. The commenter argued that the standard does not require sequestration of captured CO2 but only capture, so that no emission reductions are associated with the standard. A gloss on this argument is that there are no enforceable requirements for the captured CO2 ("[t]he fate of that [captured] CO2 is something that the proposed standard does not proscribe with enforceable requirements"). The commenter further argues that a "system of emission reduction" under section 111 must be "designed into the new source itself" so that off-site underground sequestration of captured CO2 emissions "could never satisfy the statutory requirements governing a `standard of performance'" (emphasis original).
      The EPA disagrees with both the legal and factual assertions in this comment. As to the legal point, the commenter fails to distinguish capture and sequestration of carbon from every other section 111 standard which is predicated on capture of a pollutant. Indeed, all emission standards not predicated on outright pollutant destruction involve capture of the pollutant and its subsequent disposition in the capturing medium. Thus, metals are captured in devices like baghouses or scrubbers, leaving a solid waste or wastewater to be managed. Gases can be captured with activated carbon, or under pressure, again requiring further management of the captured pollutant(s). The EPA is required to consider these potential implications in promulgating an NSPS. See section 111 (a)(1) (in promulgating a standard of performance under section 111, the EPA must "tak[e] into account ... any nonair quality health and environmental impact"). The EPA thus considers such issues as solid waste and wastewater generation as part of determining if a system of emission reduction is "best" under section 111.
      The further comment that the standard is arbitrary because it fails to impose any requirements on the captured CO2 is misplaced. The commenter mischaracterizes the standard as requiring capture only. The BSER is not just capturing a certain amount of CO2, but sequestering it. Sequestration can occur either on-site or off-site. Sequestration sites receiving and injecting the captured CO2 are required to obtain UIC permits and report under subpart RR of the GHGRP. They must conduct comprehensive monitoring as part of these obligations. Although the NSPS does not impose regulatory requirements on the transportation pipeline or the sequestration site, such requirements already exist under other regulatory programs of the Department of Transportation and the EPA. In particular, 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 EPA has also considered carefully the requirements and operating history of the Class II requirements for EOR wells, which, in combination with the subpart RR requirements, ensure protection of USDWs from endangerment, provide the monitoring mechanisms to identify and address potential leakage using SDWA and CAA authorities, and have the practical effect of preventing releases of CO2 to the atmosphere. This is analogous to the many section 111 standards of performance for metals which result in a captured air pollution control residue to be disposed of pursuant to waste management requirements of the rules implementing the Resource Conservation and Recovery Act, and the many section 111 standards of performance for metals or organics captured in wet air pollution control systems resulting in wastewater discharged to a navigable water where pollutant loadings are controlled under rules implementing the Clean Water Act. Again, these are non-air environmental impacts for which the EPA must account in establishing a section 111(a) standard. The EPA has reasonably done so here based on the regulatory regimes of the Class VI and Class II UIC requirements in combination with the monitoring regime of the subpart RR reporting rules, as well as the CO2 pipeline standards of the Department of Transportation.
      In this regard, the EPA notes that at proposal it acknowledged the possibility "that there can be downstream losses of CO2 after capture, for example during transportation, injection or storage." 79 FR at 1484. Given the rigorous substantive requirements and the monitoring required by the Class VI rules, the complementary monitoring regime of the subpart RR MRV plan and reporting rules, as well as the regulatory requirements for Class II wells, any such losses would be de minimis. Indeed, the same commenter maintained that the monitoring requirements of the Class VI rule are overly stringent and that a 50-year post-injection site care period is unnecessarily long. As it happens, as noted above, the Class VI rules allow for an alternative post-injection site care period based on a site-specific demonstration. See 40 CFR 146.93(b).
      The EPA addresses these comments in more detail in the Response to Comment Document.
6. Other Perceived Obstacles to Geologic Sequestration
a. Class II to Class VI transition. A number of commenters maintained that the Class VI rules could effectively force all Class II wells to transition to Class VI wells if they inject anthropogenic CO2, and further maintained that, as a practical matter, this would render EOR unavailable for such CO2. The EPA disagrees with these comments. 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. The EPA issued a memorandum to its regional offices on April 23, 2015 reflecting 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.
b. GHGRP Subpart RR. A number of commenters maintained that no EOR operator would accept captured carbon from an EGU due to the reporting and other regulatory burdens imposed by the monitoring requirements of GHGRP subpart RR. They noted that preparing a subpart RR MRV plan could cost upwards of $100,000 which would be cost prohibitive given other available sources of CO2.
The EPA disagrees with this comment in several respects. First, the BSER determination and regulatory impact analysis for this rule relies on GS in deep saline formations, not on EOR. However, the EPA also recognizes the potential for sequestering CO2 via EOR, but disagrees that subpart RR is prohibitive to the use of EOR.
      The 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. 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.
      The EPA addresses these comments in more detail in the Response to Comment Document.
c. Conditional exclusion for geologic sequestration of CO2 streams under the Resource Conservation and Recovery Act (RCRA). Certain commenters voiced concerns that regulatory requirements for hazardous wastes might apply to captured CO2 and these requirements might be inconsistent with, or otherwise impede, GS of captured CO2 from EGUs. The EPA has acted to remove any such (highly conjectural) uncertainty. The Resource Conservation and Recovery Act (RCRA) authorizes the EPA to regulate the management of hazardous wastes. In particular, RCRA Subtitle C authorizes a cradle to grave regulatory program for wastes identified as hazardous, whether specifically listed as hazardous or whether the waste fails certain tests of hazardous characteristics. The EPA currently has little information to conclude that CO2 streams (defined in the RCRA exclusion rule as including incidental associated substances derived from the source materials and the capture process, and any substances added to the stream to enable or improve the injection process) might be identified as "hazardous wastes" subject to RCRA Subtitle C regulation. Nevertheless, to reduce potential uncertainty regarding the regulatory status of CO2 streams under RCRA Subtitle C, and in order to facilitate the deployment of geologic sequestration, the EPA recently concluded a rulemaking to exclude certain CO2 streams from the RCRA definition of hazardous waste. In that rulemaking, the EPA determined that if any such CO2 streams would be hazardous wastes, further RCRA regulation is unnecessary to protect human health and the environment provided certain conditions are met. Specifically, the rule conditionally excludes from Subtitle C regulations CO2 streams if they are (1) transported in compliance with U.S. Department of Transportation or state requirements; (2) injected in compliance with UIC Class VI requirements (summarized above); (3) no other hazardous wastes are mixed with or co-injected with the CO2 stream; and (4) generators (e.g., emission sources) and Class VI well owners or operators sign certification statements. See 40 CFR 261.4(h)).
d. Other perceived uncertainties. Other commenters claimed that various legal uncertainties preclude a finding that geologic sequestration of CO2 from EGUs can be considered to be adequately demonstrated. Many of the issues referred to in comments relate to property rights: issues of ownership of pore space, relationship of sequestration to ownership of mineral rights, issues of dealing with multiple landowners, lack of state law frameworks, or competing, inconsistent state laws. Other commenters noted the lack of long-term liability insurance, and noted uncertainties regarding long-term liability generally.
      An IPCC special report on CCS found that with an appropriate site selection, a monitoring program, a regulatory system, and the appropriate use of remediation methods, the risks of GS would be comparable to risks of current activities, such as EOR, acid gas injection and underground natural gas storage. Furthermore, an interagency CCS task force examined GS-related legal issues thoroughly and concluded that early CCS projects can proceed under the existing legal framework with respect to issues such as property rights and liability. As noted earlier, both the Archer Daniels Midland and FutureGen projects addressed siting and operational aspects of GS (including issues relating to volumes of the CO2 and the nature of the CO2 injectate) in their permit applications. The fact that these applicants pursued permits indicates that they regarded any potential property rights issues as resolvable.
	Commenter American Electric Power (AEP) referred to its own experience with the Mountaineer demonstration project. AEP noted that although this project was not full scale, finding a suitable repository, notwithstanding a generally favorable geologic area, proved difficult. The company referred to years spent in site characterization and digging multiple wells. Other commenters noted more generally that site characterization issues can be time-consuming and difficult, and quoted studies suggesting that it could take 5 years to obtain a Class VI permit.
      The EPA agrees that robust site characterization and selection is important to ensuring capacity needs are met and that the sequestered CO2 is safely stored. Efforts to characterize geologic formations suitable for GS have been underway at DOE through the RCSPs since 2003 (see Section K). Additionally, since 2007, the USGS has been assessing U.S. geologic storage resources for CO2. As noted earlier, DOE, in partnership with researchers, universities, and organizations across the country, is demonstrating that GS can be achieved safely, permanently, and economically at large scales, and projects supported by the department have safely and permanently stored 10 million metric tons of CO2.
      In the time since the commenter submitted comments several Class VI permits have been issued by the EPA. These projects demonstrate that a GS site permit applicant could potentially prepare and obtain a UIC permit concurrent with permits required for an EGU. With respect to AEP's experience with the Mountaineer demonstration project, notwithstanding difficulties, the company was able to successfully dig wells, and safely inject captured CO2. Moreover, the company indicated it fully expected to be able to do so at full scale and explained how. The EPA notes further that a monitoring program and its associated infrastructure (e.g., monitoring wells) and costs will be dependent on site-specific characteristics, such as CO2 injection rate and volume, geology, the presence of artificial penetrations, among other factors. It is thus not appropriate to generalize from AEP's experience, and assume that other sites will require the same number of wells for site characterization or injection. In this regard, we note that the ADM and FutureGen construction permits for Class VI wells involved far fewer injection wells than AEP references.
N. Options That Were Considered but Were Ultimately Not Determined to Be the BSER
      In light of the comments received, the EPA re-examined several alternative systems of emission reduction and reaffirms in this rulemaking our proposed determination that those alternatives do not represent the "best" system of emission reduction when compared against the other available emission reduction options. These are described below.
1. Highly efficient generation technology (e.g., supercritical or ultra-supercritical boilers)
      In the January 2014 proposal, we considered whether `Highly Efficient New Generation without CCS Technology' should constitute the BSER for new steam generating units. 79 FR at 1468-69.  The discussion focused on the performance of highly efficient generation technology (that does not include any implementation of CCS), such as a supercritical pulverized coal (SCPC) or a supercritical CFB boiler, or a modern, well-performing IGCC unit.
      All these options are technically feasible  -  there are numerous examples of each operating in the U.S. and worldwide. However, we do not find them to qualify as the best system for reduction of CO2 emissions for the following reasons:
a. Lack of significant CO2 reductions when compared to business as usual. At the outset, we reviewed the emission rates of efficient PC and CFB units. According to the DOE/NETL estimates, a newly constructed subcritical PC unit firing bituminous coal would emit approximately 1,800 lb CO2/MWh-gr, a new SCPC unit using bituminous coal would emit nearly 1,700 lb CO2/MWh-gr, and a new IGCC unit would emit about 1,450 lb CO2/MWh-gr. Emissions from comparable sources utilizing sub-bituminous coal or lignite will have somewhat higher CO2 emissions.
      Some commenters noted that new coal-fired plants utilizing supercritical boiler design or IGCC would provide substantial emission reductions compared to the emissions from the existing subcritical coal plants that are currently in wide use in the power sector. However, the majority of the most recent new power sector projects using solid fossil fuel (coal or petroleum coke) as the primary fuel  -  both those that have been constructed and those that have been proposed  -  are supercritical boilers and IGCC units. Coal-fired power plants that have come on-line the most recently include AEP's John W. Turk, Jr. Power Plant, which is a 600 MW ultra-supercritical PC (USCPC) facility located in the southwest corner of Arkansas, and Duke Power's Edwardsport plant, which is a 618 MW "CCS ready" IGCC unit located in Knox County, Indiana. The majority of new coal-fired power plants that were brought on-line in 2010 or later have utilized supercritical boiler technology. And those units that initiated operation in 2010 or later were conceived of, planned, designed, and permitted well before 2010  -  likely in the early 2000s. Thus, it seems clear that the power sector had already, at that point, transitioned to the selection of supercritical boiler technology as "business as usual" for new coal-fired power plants. Since that time, there have been other coal-fired power plants that have been proposed and almost all of them have been either supercritical boiler designs or IGCC units.
      The EPA is aware of only one new coal-fired power plant that is actively in the construction phase. That plant is Mississippi Power's Kemper County Energy Facility in Kemper County, MS  -  an IGCC unit that will implement partial CCS to capture approximately 65 percent of the available CO2, which will be sold for use in EOR operations.
      Considering the direction that the power sector has been taking and the changes that it is undergoing, identifying a new supercritical unit as the BSER and requiring an emission limitation based on the performance of such units thus would provide few, if any, additional CO2 emission reductions beyond the sector's "business as usual". As noted, for the most part, new sources are already designed to achieve at least that emission limitation. This criterion does not itself eliminate supercritical technology from consideration as BSER. However, existing technologies must be considered in the context of the range of technically feasible technologies and, as we discuss elsewhere in this final preamble partial CCS can achieve emission limitations beyond business as usual and do so at a reasonable cost.
      The EPA also considered IGCC technology and whether it represents the BSER for new power plants utilizing coal or other solid fossil fuels. IGCC units, on a gross-output basis, have inherently lower CO2 emission rates when compared to similarly-sized SCPC units. However, the net emission rates and overall emissions to the atmosphere (i.e., tons of CO2 per year) tend to be more similar (though still somewhat lower) for new IGCC units when compared to new SCPC units with the same electrical output. Therefore an emission limitation based on the expected performance of a new IGCC unit would result in some CO2 emission reductions from the segment of the industry that would otherwise construct new PC units, but not from the segment of the industry that would already construct new IGCC units. A gross-output-based emission limitation consistent with the expected performance of a new IGCC unit would still require some additional control, such as partial CCS, on a new supercritical boiler.
      As is shown in Section [x.x], additional emission reductions beyond those that would result from an emission standard based on a new SCPC boiler or even a new IGCC unit as the BSER can be achieved at a reasonable cost. Because practicable emission controls are available that are of reasonable cost at the source level and that will have little cost and energy impact at the national level, the EPA is according significant weight to the factor of amount of emissions reductions in determining the BSER. As discussed above, the D.C. Circuit has emphasized this factor in describing the purpose of CAA section 111 as to achieve "as much [emission reduction] as practicable."
b. Lack of incentive for technological innovation. As discussed above, the EPA is justifying its identification of the BSER based on its weighing of the factors explicitly identified in CAA section 111(a)(1), including the amount of the emission reduction. Under the D.C. Circuit caselaw, encouraging the development and implementation of advanced control technology must also be considered. Consideration of this factor confirms the EPA's decision not to identify highly efficient generation technology (without CCS) as the BSER. At present, CCS technologies are the most promising options to achieve significant reductions in CO2 emissions from newly constructed fossil-fuel fired steam generating units. CCS technology is also now a viable retrofit option for some modified, reconstructed and existing sources  -  depending upon the configuration, location and age of those sources. As CCS technologies are deployed and used more there is an expectation that, based on previous experience with advanced technologies, the performance will improve and the implementation costs will decline. The improved performance and lower costs will provide additional incentive for further implementation in the future.
      The International Panel on Climate Change (IPCC) recently released its Fifth Assessment report, which recognizes that widespread deployment of CCS is crucial to reach the long term climate goals. The authors of the report used models to predict the likelihood of stabilizing the atmospheric concentration of CO2 at 450 ppm by 2050 with or without carbon capture and storage (CCS). They found that several of the models were not able to reach this goal without CCS, which underlines the importance of deploying and further developing CCS on a large scale.
      American Electric Power (AEP), in an evaluation of lessons learned from the Phase 1 of its Mountaineer CCS project, wrote: "AEP still believes the advancement of CCS is critical for the sustainability of coal-fired generation."
      Some commenters felt that the proposed standard of performance for new steam generating units, based on implementation of partial CCS at an emission rate of 1,100 lb/MWh-gross, would not serve to promote the increased deployment and implementation of CCS. The commenters argued that such a standard could instead have the unintended result of discouraging the further development of advanced coal generating technologies such as ultra-supercritical boilers and improved IGCC designs.
      Commenters further argued that such a standard will stifle further development of CCS technologies. Commenters felt that the standard would effectively deter the construction of new coal-fired generation  -  and, if there is no new coal-fired generation, then there will be no implementation of CCS technology and, therefore, no need for continued research and development of CCS technologies. They argued, in fact, that the best way to promote the development of CCS was to set a standard that did not rely on it.
      The EPA does not agree with these arguments and, in particular, does not see how a standard that does not require an advanced control technology would serve to promote development and deployment of that advanced control technology. On the contrary, the history of regulatory actions has shown that emission standards that require the installation of advanced control equipment lead to increased use of that control equipment, and the absence of a requirement stifles technology development.
      There is a dramatic instance of this paradigm presented in the present record. In 2011, AEP deferred construction of a large-scale CCS retrofit demonstration project on one of its coal-fired power plants because the state's utility regulators would not approve cost recovery for CCS investments without a regulatory requirement to reduce CO2 emissions. AEP's chairman was explicit on this point, stating in a July 17, 2011 press release announcing the deferral:
      We are placing the project on hold until economic and policy conditions create a viable path forward ... We are clearly in a classic `which comes first?' situation. The commercialization of this technology is vital if owners of coal-fueled generation are to comply with potential future climate regulations without prematurely retiring efficient, cost-effective generating capacity. But as a regulated utility, it is impossible to gain regulatory approval to recover our share of the costs for validating and deploying the technology without federal requirements to reduce greenhouse gas emissions already in place. The uncertainty also makes it difficult to attract partners to help fund the industry's share.

      Some commenters also argued that the incremental cost associated with including CCS at the proposed level would prevent new coal-fired units from being built. Instead, they advocated for a standard based on most efficient technology (supercritical) coupled with government subsidies to advance and promote CCS technology. As we will show later, the final standard that we are issuing in this action is less stringent than the proposed level and can be met at a lower cost than the proposed standard. Further, the record and current economic conditions (fuel costs, renewables, demand growth, etc.) show that non-economic factors such as a desire for fuel diversity will likely drive future development of new coal-fired EGUs. In that scenario, a cost-reasonable standard is, in fact, what will drive new technology deployment.
      The EPA expects that it is unlikely that a new IGCC unit would install partial CCS to meet the final standard unless the facility is built to take advantage of EOR opportunities or to operate as a poly-generation facility (i.e., to co-produce power along with chemicals or other products). For most IGCC units, the final standard of performance can be met simply by co-firing  a small amount of natural gas. Some commenters argued that IGCC is an advanced technology that, like CCS, should be promoted. The EPA agrees. IGCC is a low-emitting, versatile technology that can be used for purposes beyond just power production (as mentioned just above). Commenters further argued that a requirement to include partial CCS (at a level to meet the proposed standard of performance) would serve to deter  -  rather than promote  -  more installation of IGCC technology. We disagree with a similar argument that commenters make with respect to partial CCS for post-combustion facilities, but our final standard moots that argument for IGCC facilities because the final emission limitation of 1,400 lb CO2/MWh-gross will not itself deter installation of IGCC technology, by the terms of the commenters' own argument.
2. "Full" carbon capture and storage (i.e., 90 percent capture)
      We also reconsidered whether the emission limitation for new coal-fired EGUs should be based on the performance of full implementation of CCS technology. For a newly constructed utility boiler, this would mean that a post-combustion capture system would be used to treat the entire flue gas stream to achieve an approximately 90 percent reduction in CO2 emissions. For a newly constructed IGCC unit, a pre-combustion capture system would be used to capture CO2 from a fully shifted gasification syngas stream to achieve an approximately 90 percent reduction in CO2 emissions.
      In the proposal for newly constructed sources (January 2014 proposal), we found that "full CCS" would certainly result in significant CO2 reductions from any new source implementing the technology. However, we also found that the costs associated with implementation, on either a new utility boiler system or a new IGCC unit, are predicted to substantially exceed the costs for other dispatchable non-NGCC generating options that are being considered by utilities and project developers (e.g., new nuclear plants and new biomass-fired units).  See 79 FR at 1477.  This remains the case, and indeed, the difference between cost of full capture and new nuclear technology is even greater than at proposal. The EPA thus is not selecting full capture CCS as BSER.
VI. Rationale for Final Standards for Modified Fossil Fuel-fired Electric Utility Steam Generating Units
      The EPA has determined that, as proposed, the BSER for steam generating units that trigger the modification provisions is each affected unit's own best potential performance as determined by that unit's historical performance. The final standards of performance are similar to those proposed in the June 2014 proposal. Differences between the proposed standards and the final standards issued in this action reflect responses to comments received on the proposal. Those changes are described below.
      As noted previously, the EPA is issuing final emission standards only for affected modified steam generating units that conduct modifications resulting in a potential hourly increase in CO2 emissions (mass per hour) of more than 10 percent ("large" modifications). The EPA is continuing to review the appropriate standards for modified sources that conduct modifications resulting in a potential hourly increase in CO2 emissions (mass per hour) of less than or equal to 10 percent ("small" modifications), is not issuing final standards for these sources in this action, and is withdrawing the proposed standards for these sources.
   A. Rationale for Final Applicability Criteria for Modified Steam Generating Units
      Final applicability criteria for modified steam generating EGUs include those discussed earlier in section [x.x] (General Applicability) and section [x.x] (Applicability Specific to Modified Sources).
      CAA section 111(a)(4) defines a "modification" as "any physical change in, or change in the method of operation of, a stationary source which increases the amount of any air pollutant emitted by such source or which results in the emission of any air pollutant not previously emitted." Certain types of physical or operational changes are exempt from consideration as a modification. Those are described in 40 CFR 60.2, 60.14(e). To be clear, our action in this final rule, and the discussion below, does not change anything concerning what constitutes or does not constitute a modification under the CAA or the EPA's regulations.
      A modified steam generating unit is a source that fits the definition and applicability criteria of a fossil fuel-fired steam generating unit and that commences a qualifying modification on or after June 18, 2014 (the publication date of the proposed modification standards). 79 FR 34960.
      For the reasons discussed below, the EPA in this final action is finalizing requirements only for steam generating units that conduct modifications resulting in an increase in potential hourly CO2 emissions (mass per hour) of more than 10 percent as compared to the source's potential to emit during the previous five years. With respect to modifications with smaller increases in CO2 emissions (specifically, steam generating units that conduct modifications resulting in an increase in potential hourly CO2 emissions (mass per hour) of 10 percent or less compared to the source's potential to emit during the previous 5 years, the EPA is not finalizing any standard or other requirements, and in a separate action today is withdrawing the June 2014 proposal with respect to these sources.
      As we discussed in the June 2014 proposal, the EPA has historically been notified of only a limited number of NSPS modifications involving fossil steam generating units and therefore predicted that very few of these units would trigger the modification provisions and be subject to the proposed standards.
      Given the limited information that we have about past modifications, the agency has concluded that it lacks sufficient information to establish standards of performance for all types of modifications at steam generating units at this time.  Instead, the EPA has determined that it is appropriate to establish standards of performance at this time for larger modifications, such as major facility upgrades involving, for example, the reconstruction or replacement of steam turbines and other equipment upgrades that result in substantial increases in a unit's potential hourly CO2 emissions rate. The Agency has determined, based on its review of public comments and other publicly available information, that it has adequate information regarding the types of modifications that could result in large increases in potential hourly CO2 emissions, as well as on the types of measures available to control emissions from sources that undergo such modifications, and on the costs and effectiveness of such control measures, upon which to establish standards of performance for modifications with large emissions increases at this time.
      In establishing standards of performance at this time for modifications with large emissions increases, but not for those with small increases, the EPA is exercising its policy discretion to promulgate regulatory requirements in a sequential fashion for classes of modifications within a source category, accounting for the information available to the agency, while also focusing initially on those modifications with the greatest potential environmental impact.
      To be clear, the EPA is not reaching a final decision that it will regulate modifications with smaller increases, or even that such modifications should be subject to different requirements than we are finalizing in this rule for the modifications with larger increases. We have made no decisions and this matter is not concluded. We plan to continue to gather information, consider the options for modifications with smaller increases, and, in the future, develop a proposal for these modifications or otherwise take appropriate steps.
      In deferring issuance of standards of performance for those sources that conduct modifications resulting in a potential hourly increase in CO2 emissions of less than or equal to 10 percent, the EPA is exercising its discretion to propose and promulgate standards covering sources within a source category in a sequential manner, under appropriate circumstances, such as those present here, consistent with the case law that authorizes agencies to establish a regulatory framework in an incremental fashion, that is, a step at a time.[,]
      As a means of determining the proper threshold between the larger and smaller increases in CO2 emissions, the EPA examined changes in CO2 emissions that may result from large, capital-intensive projects, such as major facility upgrades involving the reconstruction or replacement of steam turbines and other equipment upgrades that would significantly increase a unit's capacity to burn more fossil fuel, thereby resulting in large emissions increases. Major upgrades such as these could increase a steam generating unit's potential hourly CO2 emissions by well over 10 percent.
      Therefore we are setting the threshold between "large" modifications and "small" modifications subcategory at 10 percent, a level commensurate with the magnitude of the emissions increases that could result from these types of projects, and we are issuing a final standard of performance for those sources that conduct modifications resulting in potential hourly CO2 emission increases that exceed that threshold. We are not issuing standards of performance for those sources that conduct modifications resulting in a potential hourly increase of CO2 emissions of less than or equal to 10 percent.
      Therefore, in a separate action (published in a separate notice in the Federal Register today), the EPA is withdrawing the proposed standards for those sources that conduct modifications resulting in a potential hourly increase in CO2 emissions (mass per hour) of less than or equal to ten percent and is not issuing final standards for those sources at this time. Utilities, states and others should be aware that  the differentiation between modifications with larger and smaller increases in CO2 emissions only applies to sources covered under 40 CFR part 60, subpart TTTT, i.e., it is only applicable to CO2 emissions from fossil fuel-fired steam generating units. There is no similar provision for criteria pollutants or for other source categories. Utilities, states and others should also be aware that the distinction between large and small modifications only applies to NSPS modifications. Sources undertaking modifications may still be subject to requirements of New Source Review under CAA part C or other CAA requirements.
      The EPA notes that some commenters expressed concern that a number of existing fossil steam generating units, in order to fulfill requirements of an approved CAA section 111(d) plan, may pursue actions that involve physical or operational changes that result in some increase in their CO2 emissions on an hourly basis, and thus constitute modifications. Some commenters suggested that the EPA should exempt projects undertaken specifically for the purpose of complying with CAA section 111(d).
      The EPA does not have sufficient information at this time to predict the full array of actions that existing steam generating units may undertake in response to applicable requirements under an approved CAA section 111(d) plan, or which, if any, of these actions may result in increases in potential CO2 hourly emissions. Nevertheless, EPA expects that, to the extent actions undertaken by existing steam generating units in response to 111(d) requirements trigger modifications, the magnitude of the increases in potential hourly CO2 emissions associated with such modifications would generally be small and would therefore generally not subject such modifications to the standards of performance that the EPA is finalizing today for modified steam generating units with large increases in potential hourly CO2 emissions.
	We note that modified steam generating units that are not subject to the standard of performance finalized in this rule would be existing sources subject to section 111(d).
B. Identification of the Best System of Emission Reduction
      The EPA has determined that, as was proposed, the BSER for steam generating units that trigger the modification provisions is the affected source's own best potential performance as determined by that source's historical performance.
      The EPA proposed that the BSER for modified steam generating EGUs is each unit's own best potential performance based on a combination of best operating practices and equipment upgrades. Specifically, the EPA co-proposed two alternative standards for modified utility steam generating units. In the first co-proposed alternative, modified steam generating EGUs would be subject to a single emission standard determined by the affected source's best demonstrated historical performance (in the years from 2002 to the time of the modification) with an additional 2 percent emission reduction. The EPA proposed that the standard could be met through a combination of best operating practices and equipment upgrades. To account for facilities that have already implemented best practices and equipment upgrades, the proposal also specified that modified facilities would not have to meet an emission standard more stringent than the corresponding standard for reconstructed EGUs.
      The EPA also co-proposed that the specific standard for modified sources would be dependent on the timing of the modification. We proposed that sources that modify prior to becoming subject to a CAA section 111(d) plan would be required to meet the same standard described in the first co-proposal -- that is, the modified source would be required to meet a unit-specific emission limit determined by the affected source's best demonstrated historical performance (in the years from 2002 to the time of the modification) with an additional 2 percent emission reduction (based on equipment upgrades). We also proposed that sources that modify after becoming subject to a CAA section 111(d) plan would be required to meet a unit-specific emission limit that would be determined by the CAA section 111(d) implementing authority and would be based on the source's expected performance after implementation of identified unit-specific energy efficiency improvement opportunities.
      The final standards in this action do not depend upon when the modification commences (as long as it commences after June 8, 2014). The EPA received comments on the June 2014 proposal that called into question the need to differentiate the standard based on when the modification was undertaken. Further, commenters noted that the proposed requirements for sources modifying after becoming subject to a CAA section 111(d) plan, which were based on energy efficiency improvement opportunities were vague and that standard setting under CAA section 111(b) is a federal duty and would require notice-and-comment rulemaking. The EPA considered those comments and has determined that we agree that there is no need for subcategories based on the timing of the modification.
   C. BSER Criteria
         1. Technical Feasibility
      The EPA based technical feasibility of the unit-specific efficiency improvement on analyses done to support heat rate improvement for the proposed CAA section 111(d) emission guidelines (Clean Power Plan). That work was summarized in Chapter 2 of the TSD, "GHG Abatement Measures". In response to comments on the proposed Clean Power Plan, the approach was adjusted, as described in the final CAA section 111(d) emission guidelines. As with proposed actions, the EPA is basing technical feasibility for final standards for modified source efficiency improvements on the analyses for heat rate improvements for the CAA 111(d) final rule.
         2. Cost
      Any efficiency improvement made by EGUs for the purpose of reducing CO2 emissions will also reduce the amount of fuel that EGUs consume to produce the same electricity output. The cost attributable to CO2 emission reductions, therefore, is the net cost of achieving heat rate improvements after any savings from reduced fuel expenses. As summarized below, we estimate that, on average, the savings in fuel cost associated with a 4 percent heat rate improvement would be sufficient to cover much of the associated costs, and thus that the net costs of heat rate improvements associated with reducing CO2 emissions from affected EGUs are relatively low.
      We recognize that our cost analysis just described will represent the costs for some EGUs better than others because of differences in EGUs' individual circumstances. We further recognize that reduced generation from coal-fired EGUs will tend to reduce the fuel savings associated with heat rate improvements, thereby raising the effective cost of achieving the CO2 emission reductions from the heat rate improvements. Nevertheless, we still expect that the majority of the investment required to capture the technical potential for CO2 emission reductions from heat rate improvements would be offset by fuel savings, and that the net costs of implementing heat rate improvements as an approach to reducing CO2 emissions from modified fossil fuel-fired EGUs are reasonable.
         3. Emission Reductions
      This approach would achieve reasonable reductions in CO2 emissions from the affected modified units as those units will be required to meet an emission standard that is consistent with more efficient operation. In light of the limited opportunities for emission reductions from retrofits, these reductions are adequate.
         4. Technology Promotion
      As noted previously, the case law makes clear that the EPA is to consider the effect of its selection of the BSER on technological innovation or development, but that the EPA also has the authority to weigh this factor, along with the various other factors. With the selection of emissions controls, modified sources face inherent constraints that newly constructed greenfield and even reconstructed sources do not; as a result, modified sources present different, and in some ways more limited, opportunities for technological innovation or development. In this case, the standards promote technological development by promoting further development and market penetration of equipment upgrades and process changes that improve plant efficiency.
VII. Rationale for Final Standards for Reconstructed Fossil Fuel-fired Electric Utility Steam Generating Units
A. Rationale for Final Applicability Criteria for Reconstructed Sources
      The applicability rationale for reconstructed utility steam generating units is the same as for newly constructed utility steam generating units. We are finalizing the same general criteria and not amending the reconstruction provisions included in the general provisions.
B. Identification of the Best System of Emission Reduction
      In the proposal, the EPA evaluated seven different control technology configurations to determine the BSER for reconstructed fossil fuel-fired boiler and IGCC EGUs: (1) The use of partial CCS, (2) conversion to (or co-firing with) natural gas, (3) the use of CHP, (4) hybrid power plants, (5) reductions in generation associated with dispatch changes, renewable generation, and demand side energy efficiency,(6) efficiency improvements achieved through the use of the most efficient generation technology, and (7) efficiency improvements achieved through a combination of best operating practices and equipment upgrades.
      Although the EPA concluded that the first 4 technologies met most of the evaluation criteria, namely they are adequately demonstrated, have reasonable costs and provide GHG emissions reductions, they were inappropriate for BSER due to site specific constraints for existing EGUs on a nationwide basis. We rejected best operating practices and equipment upgrades because we concluded the GHG reductions are not sufficient to qualify as BSER. The majority of commenters agree with EPA's decision that these technologies are not BSER. In contrast, a few commenters did support partial CCS as BSER.
      The fifth option, reductions in generation associated with dispatch changes, renewable generation, and demand side energy efficiency, is comparable to application of measures identified in building blocks two, three and four in the emissions guidelines that we are finalizing under CAA section 111(d). We solicited comment on any additional considerations that the EPA should take into account in the applicability of building blocks two, three and four in the BSER determination. Most commenters stated that building blocks two, three and four should not be considered for reconstructed sources.
      The proposed BSER was based on the performance of the most efficient generation technology available, which we concluded was the use of the best available subcritical steam conditions for small units and the use of supercritical steam conditions for large units. We concluded this technology to be technically feasible, to have sufficient emission reductions, to have reasonable costs, and some opportunity for technological innovation. The proposed emission standard for these sources was 1,900 lb CO2/MWh-net for units with a heat input rating of greater than 2,000 MMBtu/h and 2,100 lb CO2/MWh-net for units with a heat input rating of 2,000 MMBtu/h or less. The difference in the proposed standards for larger and smaller units was based on greater availability of higher pressure/temperature steam turbines (e.g. supercritical steam turbines) for larger units. As explained in Section III of this preamble, we are finalizing the standard on a gross output basis for utility steam generating units. The equivalent gross-output-based standards are 1,800 lb CO2/MWh and 2,000 lb CO2/MWh respectively.
      We solicited comment on multiple aspects of the proposed standards. First, we solicited comment on a range of 1,600 to 2,000 lb CO2/MWh-gross for large units and 1,800 to 2,200 lb CO2/MWh-gross for small units. We also solicited comment on whether the standards for utility boilers and IGCC units should be subcategorized by primary fuel type. In addition, we solicited comment on if there are sufficient alternate compliance technologies (e.g., co-firing natural gas) that the small unit subcategory is unnecessary and should be eliminated. Those small sources would be required to meet the same emission standard as large utility boilers and IGCC units.
      Many commenters supported the upper limits of the suggested ranges, saying the standard will be consistently met. Some commenters raised concerns about the achievability of these limits for the many boiler and fuel types. A few commenters suggested that there should be separate subcategories for coal-fired utility boilers and IGCC units, since IGCC units have demonstrated limits closer to 1,500 lb CO2/MWh-net and the units' designs are so fundamentally different. Some commenters said that CFB (due to lower maximum steam temperatures), IGCC, and traditional boilers each need their own subcategory. Some commenters suggested that due to high moisture content and high relative CO2 emissions of lignite, lignite-fired units should have its own subcategory. Other commenters opposed the proposed standards for reconstructed units because they thought the BSER determination for reconstructed subpart Da units was inconsistent with the BSER determination for newly constructed units. These commenters stated that the EPA did not provide sufficient justification for eliminating partial carbon capture and sequestration (CCS). These commenters also stated that the reason the EPA gave for dismissing CCS in the proposal was a lack of "sufficient information about costs." These commenters hold that the cost rationale does not apply for reconstructed coal-fired power plants. The fact that reconstructed units may face greater costs to comply with a CAA section 111(b) standard than new sources does not relieve them of their compliance obligation.
      Based on a review of the comments, we have concluded that both the proposed BSER and emission standards are appropriate, and we are finalizing the standards as proposed. Nothing in the comments changed our view that the BSER for reconstructed steam generating units should be based on the performance of a well operated and maintained EGU using the most efficient generation technology available, which we have concluded is a supercritical pulverized coal (SCPC) or supercritical circulating fluidized bed (CFB) boiler for large units, and subcritical for small units. As described at proposal, we have concluded that these standards are achievable by all the primary coal types. The final standards for reconstructed utility boilers and IGCC units is 1,800 lb CO2/MWh-gross for sources with a heat input rating of greater than 2,000 MMBtu/h and 2,000 lb CO2/MWh-gross for sources with a heat input rating of 2,000 MMBtu/h or less.
      While the final emission standards are based on the identified BSER, a reconstructed EGU would not necessarily have to rebuild the boiler to use steam temperatures and pressures that are higher than the original design. As commenters noted, a reconstructed unit is not required to meet the standards if doing so is deemed to be "technologically and economically" infeasible. 40 CFR 60.15(b). This provision inherently requires case-by-case reconstruction determinations in the light of considerations of economic and technological feasibility. However, this case-by-case determination would consider the identified BSER (the use of the best available steam conditions), as well as-- at a minimum-- the first four technologies the EPA considered, but rejected, as BSER for a nationwide rule. One or more of these technologies could be technically feasible and reasonable cost, depending on site specific considerations and, if so, would likely result in sufficient GHG reductions to comply with the applicable reconstructed standards. Finally, in some cases, equipment upgrades and best operating practices would result in sufficient reductions to achieve the reconstructed standards.
VIII. Summary of Final Standards for Newly Constructed, Modified, and Reconstructed Stationary Combustion Turbines
      This section summarizes the final applicability requirements, BSER determinations, and emission standards for newly constructed, modified, and reconstructed stationary combustion turbines. We explain our rationale for these final decisions in Section IX of this preamble.
A. Applicability Requirements
	We are finalizing emission standards for newly constructed, modified, and reconstructed stationary combustion turbines that (1) have a base load rating for fossil fuels greater than 250 MMBtu/h and (2) serve a generator capable of selling more than 25 MW of electricity to the grid. We also are finalizing applicability requirements that will exempt stationary combustion turbines that are dedicated peaking units, dedicated non-fossil units, or are physically incapable of burning natural gas (i.e., not connected to a natural gas pipeline), waste combustors and incinerators (units subject to subparts Eb or CCCC of this part), as well as the large majority of industrial combined heat and power units from the final emission standards. Specifically, the final emission standards do not apply to stationary combustion turbines subject to a federally enforceable permit condition limiting annual electric sales to the specific design efficiency of the combustion turbine multiplied by the unit's potential electric output or less or restricting annual fossil fuel use to 10 percent or less of a unit's heat input capacity. Finally, the final emission standards do not apply to combined heat and power units that are subject to a federally enforceable permit condition limiting net-electric sales to the unit's design efficiency multiplied by the unit's potential output or 219,000 MWh, whichever is greater.
B. Best System of Emission Reduction
	We are finalizing the same BSER as proposed. For newly constructed, modified, and reconstructed stationary combustion turbines. The BSER is the use of modern, efficient combined cycle technology.
C. Final Emission Standards
      For all newly constructed, modified, and reconstructed natural gas-fired combustion turbines, we are finalizing an emission standard of 1,000 lb CO2/MWh-gross, calculated on a 12-operating month rolling average basis. We are also finalizing an optional emission standard of 1,080 lb CO2/MWh-net, calculated on a 12-operating month rolling average basis.
IX. Rationale for Final Standards for Newly Constructed, Modified, and Reconstructed Stationary Combustion Turbines
	This section discusses three inter-related topics (1) applicability criteria, (2) BSER, and (3) achievability of the standards for combustion turbines. We summarize what was proposed, relevant comments received with our responses, and the rationale for the final determinations. The rationale includes a discussion on the role of simple cycle turbines in providing backup power in regions with large amounts of intermittent renewable generation. The achievability discussion explains how the applicability criteria taken together with our BSER determination ensure that the standards are achievable by affected units.
      Applicability and subcategorization are closely tied to the required emission standards, and we are carefully considering them together. For example, some owners/operators may see an inherent value in not being subject to subpart TTTT, regardless of the requirements for that particular type of unit under subpart TTTT, and certain exemption criteria could lead to a perverse incentive to install new units or run units in a way that increases CO2 emissions above the baseline emission rate. Furthermore, the EPA recognizes that energy industry trends have evolved, and we are adjusting our proposed approach to reflect these changes.
      For the proposed applicability to combustion turbines, the EPA used the 1/3 electric sales criteria, in part because it already exists in regulatory context (e.g., the coal-fired EGU NSPS) and would allow for consistency between regulations. Our understanding at proposal was that the 1/3 electric sales criterion would essentially exclude all simple cycle turbines and would serve to distinguish between peaking (i.e., low capital cost, flexible, but relatively inefficient simple cycle units) and intermediate and base load combustion turbines (i.e., higher capital cost, less flexible, but relatively efficient combined cycle units). Based on public comments however, our understanding of the potential future roles of combustion turbine EGUs has evolved. The growth of generation from intermittent renewable sources has created a perceived need for additional cycling generation that operates outside of the traditional roles of simple and combined cycle combustion turbines. In response, the market is developing new technologies to fill this need perceived by end users of combustion turbines. Some manufacturers have developed high efficiency simple cycle turbines. While these newer turbines have higher capital costs than older simple cycle turbine designs, they are significantly more efficient and have maintained similar flexibilities (e.g., ability to start and change load rapidly) as previous designs. In contrast, other manufacturers have developed fast start flexible combined cycle units specifically to fill this role. These newer combined cycle designs have lower design efficiencies than base load combined cycle designs, but are able to start up more quickly to respond to rapid changes in electricity demand. Therefore, there is no longer a clear distinction between the role of simple cycle and combined cycle turbines.
A. Applicability
      This section describes the proposed applicability criteria, applicability issues we specifically solicited comment on, the relevant significant comments, and the final applicability criteria. We also provide our rationale for finalizing an applicability determined strictly on design and permit restrictions and independent of actual operating characteristics.
1. Proposed Applicability
      The proposed five applicability criteria for combustion turbines were that a unit must (1) be capable of combusting more than 250 MMBtu/h heat input of fossil fuel; (2) be constructed for the purpose of supplying and actually supply more than one-third of its potential net-electric output capacity to a utility power distribution system for sale (that is, to the grid) on a 3-year rolling average; (3) be constructed for the purpose of supplying and actually supply more than 219,000 MWh net-electric output to the grid on a 3-year rolling average; (4) combust over 10 percent fossil fuel on a 3-year rolling average; and (5) combust over 90 percent natural gas on a 3-year rolling average.
      We did not propose CO2 standards for two types of combustion turbines that are currently subject to criteria pollutant standards under subpart KKKK (the combustion turbine criteria pollutant NSPS). The first type was stationary combustion turbines that were constructed for the purpose of selling or that actually sell one-third or less of their potential output or 219,000 MWh or less to the grid on a 3-year rolling average basis. The second type of unit was non-natural gas-fired stationary combustion turbines (i.e., combustion turbines that actually combust 90 percent or less natural gas on a 3 year rolling average basis). Under the proposed approach, applicability with the GHG NSPS could change on an annual basis depending on actual electric sales and the composition of fuel burned. While the proposed applicability criteria did not explicitly exempt simple cycle combustion turbines, we concluded at proposal that it would as a practical matter exclude the vast majority of simple cycle turbines because, historically, simple cycle turbines have operated as peaking units and, on average, have sold less than five percent of their potential electric output on an annual basis.
      We solicited comment on a range of issues related to the general applicability of the EGU GHG NSPS to combustion turbines. In conjunction with the proposed one-third sales criterion, we solicited comment on finalizing an electric sales criterion between 20 to 40 percent of the potential electric output or basing the electric sales criterion on the design efficiency of the combustion turbine (i.e., the sliding scale approach). Under the sliding scale approach, more efficient combustion turbines would be able to sell a greater portion of their potential electric output, relative to less efficient combustion turbines, prior to triggering the electric sales criterion. We also solicited comment on whether the electric sales criterion for stationary combustion turbines should be defined on a single calendar year basis. In addition, we solicited comment on eliminating the 219,000 MWh electric sales criterion for combustion turbines to eliminate any incentive to install multiple, exempt, small, and less efficient stationary combustion turbines. We also solicited comment on whether to provide an explicit exclusion for all simple cycle combustion turbines regardless of the amount of electricity sold. Finally, we solicited comment on how to implement the proposed actual electric sales and actual fuel use applicability criteria evaluated as 3-year rolling averages during the first three years of operation, and we requested comment on appropriate monitoring, recordkeeping, and requirements. We specifically solicited comment on whether these proposed requirements raise implementation issues because they are based on source operation after construction has occurred.
      In both the January 2014 proposal for newly constructed EGUs and the June 2014 proposal for modified and reconstructed EGUs, the EPA solicited comment on finalizing a broad applicability approach. Specifically, we solicited comment on whether we should completely remove the electric sales (both the actual sales and "constructed for the purpose" criteria) and fuel use criteria components from the general applicability framework (that establishes the sets of sources that are subject to CAA section 111 standards). Instead the actual electric sales and fuel use thresholds would serve as subcategorization criteria for distinguishing classes of EGUs and subcategory-specific emissions standards. Under a broad applicability approach, the "constructed for the purpose of" would be completely eliminated and applicability for combustion turbines would be determined by the base load rating (i.e., greater than 250 MMBtu/h) and the capability to sell power to a utility distribution system (i.e., serving a generator capable of selling more than 25 MW to a utility distribution system). In contrast to the five proposed applicability criteria, under the broad applicability approach, affected units, including simple cycle peaking and oil-fired combustion turbines, would remain subject to the standard of performance regardless of their actual electric sales or fuel use. The broad applicability approach is consistent with historical NSPS applicability approaches based on design criteria with different emission standards for subcategories distinguished by operating characteristics. We solicited comment on all aspects of this "broad applicability approach," including the extent to which it would achieve the policy objectives of assuring that a simple cycle turbine and a combined cycle turbine are subject to the same standard if they sell more than the specified electric sales threshold to the grid.
      We also requested comment on excluding electricity sold during system emergencies as counting toward net electric sales for determining sales in excess of the electric sales threshold. The rationale included that simple cycle combustion turbines intended only for peaking applications might be required to operate above the proposed electric sales threshold if a major power plant or transmission line is unexpectedly unavailable for an extended period of time. The EPA concluded that this flexibility is appropriate if the unit is called upon to run after all other available generating assets are already running at full load. The definition of "system emergency" presented in the proposal was "any abnormal system condition that the Regional Transmission Organizations (RTO), Independent System Operators (ISO) or control area Administrator determines requires immediate automatic or manual action to prevent or limit loss of transmission facilities or generators that could adversely affect the reliability of the power system and therefore call for maximum generation resources to operate in the affected area, or for the specific affected facility to operate to avert loss of load."
2. Comments on Applicability
      We received comments specific to each one of the five proposed applicability criteria. We also received more general comments on the scope of the proposed framework as compared to the scope of the broad applicability approach. The comments and rationale for applicability to dedicated non-fossil units (i.e., units that combust less than 10 percent fossil fuel) and industrial CHP are discussed in Section III of this preamble. For combustion turbines, we received few specific comments on the 10 percent fossil fuel threshold and the 90 percent natural gas threshold. Many commenters supported the general size thresholds (i.e., have a base load heat input rating greater than 250 MMBtu/h and serving a generator with a capacity greater than 25 MW) because these thresholds are consistent with the thresholds used in states participating in the Regional Greenhouse Gas Initiative (RGGI) and under Title IV programs. Other commenters opposed this threshold and stated that all new, modified, and reconstructed units that sell electricity to the grid, including small EGUs, oil-fired combustion turbines, and simple cycle combustion turbines, should be affected sources because unaffected units have a competitive advantage in energy markets because these exempt units would not be required to internalize the costs of compliance. The EPA received many comments on applicability of the proposed standards to simple cycle combustion turbines, the electric sales criteria (both the one-third sales relative to the potential electric output and the 219,000 MWh criteria), and the broad applicability approach.
      Commenters from the power sector generally supported a complete exemption of simple cycle turbines. The rationale for these commenters included that simple cycle turbines are uniquely capable of achieving the ramp rates necessary to respond to emergency conditions and hourly variations in output from intermittent renewables. Commenters noted that simple cycle combustion turbines serve different purpose than combined cycle power blocks and that economics will drive the use of combined cycle technologies over simple cycle units. However, commenters also stated that historic simple cycle operating data may not be representative of future system requirements as coal units retire, generation from intermittent renewable generation increases, and numerous market and regulatory drivers impact plant operations. In the absence of a complete exemption, these commenters supported an electric sales criterion between 40 to 60 percent. Some commenters supported the sliding scale approach and stated that incentives for manufacturers to develop and end users to purchase higher efficiencies combustion turbines could be directionally helpful towards mitigating concerns about a monolithic national constraint on simple cycle capacity factors. In contrast, others commented that fast response combined cycle units intended for peaking and intermediate load applications can achieve ramp rates comparable to simple cycle units. These commenters said that simple cycle turbines should be restricted to their historical role as peaking units and that the one-third electric sales criterion provides sufficient flexibility. Some commenters suggested that the one-third sales criterion could be reduced to 20 percent or lower without adverse impact on grid reliability. Commenters noted that a complete exclusion for simple cycle turbines creates an opportunity to evade the standard and could thereby increase GHG emissions by creating a regulatory incentive to install and operate less efficient unaffected units compared to more efficient affected units. According to these respondents, any applicability distinctions should be based on utilization and function rather than purpose or technology.
      Commenters also noted that the 219,000 MWh electric sales criteria puts larger combustion turbines at a competitive disadvantage by distorting the market and could have the perverse impact of increasing GHG emissions. These commenters noted that the 219,000 MWh electric sales threshold permits combustion turbines smaller than about 80 MW to sell more than the proposed one-third electric sales threshold while larger, more efficient combustion turbines are restricted to selling one-third of their potential electric output to avoid applicability of the proposed CO2 standard. This creates a regulatory incentive to install multiple less efficient combustion turbines instead of fewer more efficient combustion turbines and could have the unintended consequence of increasing GHG emissions.
      Commenters in general supported that net electric sales applicability use a 3-year rolling average instead of a single year average. However, commenters noted that the inconsistency between the 3 calendar year applicability and 12-operating month compliance period results in compliance issues. For example, a facility could burn greater than 90 percent natural gas over a 3 year period, but could burn greater than 10 percent distillate oil during a 12-operatng month compliance period with the same 3 year period. Since the CO2 content of distillate oil is higher than natural gas, even if the facility is operating at maximum efficiency it would exceed the proposed emission standard. The inconsistency creates similar issues for 12-operating month periods with low electric sales, but the 3 year sales exceed the applicability threshold.
      In response to EPA's request for comments on whether the retrospective applicability requirements would create implementation issues, several permitting authorities opposed proposed applicability provisions that could change applicability determinations from year-to-year because this approach would result in compliance issues and in difficulties in determining proper pre-construction and operating permit conditions. These permitting authorities said that in order for a source to avoid applicability of the NSPS, the source must be subject to a federally enforceable permit limit with associated monitoring, recordkeeping, and reporting conditions for assessing applicability on an ongoing basis. Other commenters stated that an applicability test that concludes after construction and operation have commenced is inconsistent with the general purpose of an applicability test: which is intended to provide clear and predictable standards of performance for new sources that would apply when they begin operations. Commenters opposed the proposed retrospective applicability criteria related to actual output supplied during a preceding compliance period because EGUs must know what performance standards will apply to them during the licensing process and such criteria do not allow the permitting authority and the public to know in advance whether or not the GHG standard applies to a proposed new unit. Commenter said EGUs undergoing permitting should be allowed to request limits in operating permit conditions in order to remain below the proposed rule's applicability provisions, as this methodology is consistent with the pre-construction permitting requirements in many federally approved SIPs and the current approach under the Title V permitting program.
      Many stated a preference for the "proposed applicability approach" over the "broad applicability approach." These commenters did not think it was necessary to require combustion turbines with low electric sales or non-natural gas-fired combustion turbines to be subject to GHG standards. They stated that there is no justification for imposing burdensome monitoring, reporting, and recordkeeping requirements that would have no environmental benefit (i.e., would not reduce CO2 emissions) since these units would be subject "no emissions standards." In addition, some commenters stated that use of the "broad applicability" approach under CAA section 111(b) proceedings is not appropriate because the plain language of the CAA prohibits establishment of applicability requirements under CAA section 111 that rely on "no emissions standard" as suggested by the EPA. These commenters stated that "no emission standard" is not a "standard of performance" as defined in CAA section 111(a)(1) because a "standard of performance" is defined as a "requirement of continuous emission reduction." In contrast, many other commenters supported inclusion of new simple cycle units within the scope of the CAA 111(b) applicability criteria so that similar, existing simple cycle units would be subject to the CAA 111(d) standard (to preserve the discretion of state planners under section 111(d)). Numerous other commenters stated that all sources that sell electricity to the grid should be subject to the standard, including simple cycle units, because they view the utility grid as a single integrated system and that doing so may simplify development of future frameworks for cost-effective carbon reductions from existing units, such as frameworks based on system-wide approaches.
      Multiple commenters supported exclusion of electricity generated as a result of a grid emergency from counting towards net sales when determining applicability. One commenter stated that in addition to declared grid emergencies, there are other circumstances that warrant emergency exemption under the rule, including extreme market conditions, limitations on fuel supply, and reliability responses. Another commenter stated that the definition of "system emergency" should be defined as "any abnormal system condition that the Regional Transmission Organization, Independent System Operators, or Control Area Administrator determines requires immediate automatic or manual action to prevent a limit loss of transmission facilities or generators that could adversely affect the reliability of the power system and therefore calls for maximum generation resources to operate in the affected area, or for the specific affected facility to operate to avert loss of load." The commenter said this definition is appropriate because the benefits of operating these units to generate electrical power during emergency conditions outweigh any adverse impacts from short-term increases in CO2 emissions by units lower in the dispatch order.
      Multiple commenters opposed the exclusion of grid emergencies when calculating a source's net electricity sales for rule applicability purposes because CAA section 111 emission standards must apply continuously, even during grid emergencies. The commenters stated that the EPA does not have the necessary authority under the CAA to suspend applicability of the standard during periods of "grid emergency". Some commenters stated that an exclusion is unnecessary, because the EPA possesses an effective mechanism to address the issue: The EPA Assistant Administrator for Enforcement is delegated the authority to advise a source that the government would not sue the source for taking certain actions during an emergency. Commenters said this enforcement discretion approach has provided prompt, flexible relief that is tailored to the needs of the particular emergency and the communities being served, yet is only utilized where the relief will address the particular emergency at hand. Commenters added this enforcement discretion approach is consistent with CAA's mandate that emission limits apply continuously and provide safeguards against abuse. One commenter stated that the emergencies that the EPA mentions happen rarely and typically last for short periods, and the proposed applicability threshold would allow a source to operate at its full rated capacity for up to 2,920 hours per year without triggering NSPS, and the potential occurrence of grid emergencies represents a tiny fraction of this time. Another commenter stated that no emergency  -  short of large scale destruction of power generating capacity by terrorism, war, accident, or natural disaster  -  can justify operating a peaking unit above a 10 percent capacity factor on a 3-year rolling average.
3. Final Applicability
      For the final rule, we are retaining the applicability criteria that the unit must be capable of combusting more than 250 MMBtu/h heat input of fossil fuel, and must serve a generator capable of selling more than 25 MW to the grid. While some commenters suggested we should cover smaller EGUs as well, we did not propose to cover smaller units. Considering this, that smaller sources emit relatively few CO2 emissions compared to larger units, and that at this time we do not have information to identify an appropriate BSER for these units we are not finalizing any CO2 standards for smaller units. However, based on consideration of the comments received related to the other four proposed applicability criteria and practical implementation issues, we are revising how those criteria will be implemented. First, the proposed actual electric sales relative to the potential electric output and the actual percent natural gas usage criteria are being finalized as applicability criteria based on operating restriction included in a federally enforceable permit. Second, for non-CHP combustion turbines we are eliminating the proposed 219,000 MWh electric sales criterion. Next, the proposed 10 percent fossil fuel use applicability criteria is being finalized as an exemption for non-fossil fuel-fired units that are subject to a federally enforceable permit condition limiting the use of fossil fuel. Finally, similar to the proposed actual electric sales criteria, the proposed constructed for the purpose of selling one-third of your potential electric output applicability criteria is being finalized as an exemption for dedicated peaking units that are subject to a federally enforceable permit limiting annual electric sales. Section III described the rationale for why the EPA is not finalizing GHG standards for dedicated non-fossil fuel-fired or industrial CHP combustion turbines. The final applicability is generally consistent with the broad applicability approach we solicited comment on.
      The EPA agrees with commenters that the NSPS applicability framework should be structured so that permitting authorities and the regulated community can determine what standards apply prior to a facility having commenced construction. Therefore, the EPA has concluded that the proposed retrospective applicability criteria for combustion turbines that included actual electric sales and the amount of natural gas combusted are not practical approaches, since applicability determinations verse these criteria could change from year to year (i.e., facilities could be moving in and out of applicability each year). Furthermore, from a practical implementation standpoint, existing permitting rules would generally require pre-construction permitting authorities to include enforceable conditions limiting operations such that unaffected units would not trigger either the proposed electric sales or fuel use thresholds if they were included as general applicability criteria. Such conditions are often called "avoidance" or "synthetic minor" conditions, and these conditions typically include ongoing monitoring, recordkeeping, and reporting requirements to ensure operations remain below a particular regulatory threshold.
      The EPA evaluated several approaches for implementing the proposed retrospective applicability criteria through a pre-construction and operating permit program. For the proposed 90 percent natural gas fuel use criterion, the EPA has concluded that a comparable permit restriction would be to exempt all facilities not subject to an operating permit restriction requiring that natural gas contribute over 90 percent of the heat input. This is not a practical restriction since (1) operating permit restrictions to improve air quality are typically written to limit high emission activities (e.g., limiting the use of distillate oil to 500 hours annually) and not to limit lower emitting activities; (2) new combustion turbines could avoid applicability by simple not having a permit that requires the use of over 90 percent natural gas even if they intend to only burn natural gas; and (3) this approach is inconsistent with the objectives under CAA section 111(d) and would essentially provide a pathway for all combustion turbines to avoid applicability under state 111(d) plans. Similarly, finalizing an applicability requirement that exempts combustion turbines unless they have a permit restriction limiting non-natural gas to 10 percent or less of the heat input (i.e., limit the use of natural gas to less than 90 percent of the total heat input) is also problematic. Owners/operators of new combustion turbines could avoid applicability by simply being permitted to burn non-natural gas fuels for over 876 hours per year even if they actually intended to seldom, if ever, combust the alternate fuels. Many commenters expressed the need to maintain the ability to burn distillate oil, particularly during natural gas curtailments. Consequently, this approach would cause similar applicability issues for both 111(b) and 111(d). The EPA has concluded that the only way to distinguish a non-natural gas-fired combustion turbine and a natural gas-fired combustion turbine is the ability to burn any natural gas. Consistent with the intent of the rule (to establish GHG emission standards for natural gas-fired combustion turbines) we are not finalizing GHG standards for combustion turbines that are not capable of firing any natural gas. Combustion turbines without any connection to a natural gas pipeline would not be subject to any of the requirements of this rulemaking.
      For the proposed one-third electric sales criterion, the EPA has concluded that a comparable permit restriction would be to require a combustion turbine to actually sell more electricity than the specified threshold. Similar to the fuel use requirement, this is impractical because new combustion turbines could avoid applicability by simply not having a permit restriction to actually sell more than one-third of its potential electric output. Even if a facility were subject to this restriction, a permit violation for a unit that does not operate enough to sell one-third of its potential electric output is nonsensical since system demand may not be sufficient to allow all permitted units to operate above the specified threshold. The EPA has concluded that a permit restriction similar to the proposed one-third electric sales criterion would restrict sales to less than one-third of the potential electric output. Combustion turbines not subject to a federally enforceable electric sales restriction would have to comply with the applicable standards. The EPA has concluded this approach is appropriate for identifying dedicated peaking units. To determine an appropriate annual electric sales threshold to subcategorize dedicated peaking units, the EPA reviewed operating data for existing simple cycle units from 2005 to 2014. The EPA has concluded that an appropriate annual electric sales threshold for dedicated peaking units should be high enough to include how the majority of simple cycle turbines have historically operated. We have concluded that based on the revised electric sales applicability criteria and practical implementation issues (i.e., operating permit restrictions are written on an annual basis) permit restrictions for NSPS applicability purpose will be annual limits, as opposed to the proposed 3 year actual net electric sales applicability criteria.
      As stated earlier, we have concluded it is appropriate to avoid perverse impacts resulting from the applicability of this rulemaking. If we set an electric sales applicability permit restriction threshold too low it could have the unintended impact of increasing GHG emissions. Utilities have an obligation to provide sufficient electricity to meet system demand regardless of specific emission standards that have been placed on individual units. By limiting certain units to less than one-third of their potential electric output, utilities and other developers could justify building multiple lower capital cost, but less efficient, simple cycle turbines combustion turbines subject to avoidance limits below the electric sales threshold compared to fewer higher capital cost more efficient simple cycle combustion turbines that could meet the same demand by operating just above the proposed threshold. In either case, system demand would be the same and a sufficient numbers of combustion turbines would be built to assure sufficient generation capacity was available, but the associated GHG emissions and the cost to ratepayers would be higher for the scenario with multiple turbines operating at lower loads than the fewer more efficient units. In contrast, setting an electric sales applicability threshold that is too high could leave new units with a substantial amount of potential CO2 emissions unregulated and would reduce the number of units included in 111(d) state plans. In addition, developers of new EGUs completely exempt from the 111(b) would also have a perceived benefit of not being subject to potential future revisions of 111(d) requirements. In balancing these competing factors, the EPA has concluded that a permit restriction tied to the design efficiency of the unit is appropriate (i.e, the sliding scale approach). Specifically, owners/operators of new units subject to a permit restriction limiting annual net electric sales to the design efficiency of the unit times the potential electric output (e.g., limiting annual hours of operation to the design efficiency times 8,760 hours) would not be subject to the final requirements of this rulemaking. For a more detailed discussion, see the BSER discussion.
      The EPA has concluded concerns raised during the public comment period suggesting that the 219,000 MWh annual sales exemption would encourage the installation of multiple smaller, less efficient simple cycle combustion turbines instead of a single, more efficient and larger turbine are valid. The 219,000 MWh electric sales criterion allows simple cycle combustion turbines (e.g., less than 80 MW) to sell significantly more electricity relative to the potential electric output than larger turbines. Many commenters expressed that there is an inherent value in flexibility to operate simple cycle turbines at high capacity factors even if it is never intended to run at a high capacity factor. One of these factors is the ability to get capacity payments from the transmission authority. If we finalized the 219,000 MWh electric sales criterion for combustion turbines we would be providing a perverse incentive to install smaller, less efficient simple cycle turbines. We are therefore not finalizing the 219,000 MWh annual electric sales exemption for non-CHP combustion turbines.
      We have concluded that the emergency conditions exemption provides flexibility to maintain system reliability and minimizes overall costs to the sector. Therefore, we are finalizing that electricity sold during hours of operation when the unit is called upon to operate due to a system emergency will not be counted as net electric sales. Electric sales from units that are not called upon to operate specifically due to the system emergency (e.g., already operating when the system emergency is declared) would be treated as normal net electric sales.
B. Identification of the Best System of Emission Reduction
      This section summarizes the proposed BSER for combustion turbines, provides a summary of comments received, and the final BSER determination. For combustion turbines, we proposed and are finalizing the use of combined cycle technology as the BSER for affected stationary combustion turbines. Combustion turbines would be required to meet an output based emission standard based on what we have concluded is an achievable standard based on review of emission rate information from existing natural gas-fired combined cycle units and permitted emission standards for recent natural gas-fired combined cycle units.
1. Proposed BSER