At proposal, we considered three alternatives in evaluating the BSER for new natural gas-fired stationary combustion turbines (1) high efficiency simple cycle aeroderivative turbines (2) modern, efficient NGCC units, and (3) CCS. We rejected high-efficiency simple cycle aeroderivative turbines as the BSER because this standalone technology does not provide emission reductions and is more expensive compared to combined cycle technology. We rejected NGCC with CCS as the BSER because we concluded that at proposal we had insufficient information to make a determination regarding the technical feasibility of implementing CCS at combustion turbine units. In contrast, combined cycle units are the most common type of new fossil fuel-fired units being planned and built today for generating intermediate and base load power. The design is technically feasible and combined cycle units are currently the lowest-cost, most efficient option for new fossil fuel-fired power generation. After considering the technology options, the EPA proposed to find modern, efficient NGCC technology to be the BSER for stationary combustion turbines, and we based the proposed standards on the performance of recently constructed natural gas-fired combined cycle units.
2. Comments
      Many commenters opposed the grouping of simple cycle units and combined cycle units in the same category and establishing the BSER for combustion turbines strictly based on the combined cycle mode of operation. Commenters pointed to the word "achievable" in CAA section 111(a)(1) and stated that applying an emission standard based on combined cycle technology to simple cycle units is legally indefensible because simple cycle units cannot achieve emission rates as low as combined cycle units. Commenters also stated that under CAA section 111(b)(2) the EPA may acknowledge these different functions by completing function-specific BSER determinations and by establishing separate standards for these functions. Many commenters stated that combined cycle technology should be the BSER for base-load and intermediate-load functions, while simple cycle should be the BSER for peak-load functions.
      Some commenters stated that the proposed BSER analysis for coal-fired units was inconsistent with the BSER analysis for natural gas-fired combustion turbines. They stated the EPA determined that use of CCS is feasible for coal-fired generation based on current CCS projects under development at coal-fired generating stations, but the agency did not come to the same conclusion for natural gas-fired combustion turbines when there is an NGCC project under development that will apply CCS to a slip stream of NGCC flue gas. Commenters further stated that it is irrelevant that the NGCC CCS project is a partial CCS project whereas the developmental projects for coal fired units are "full-scale." These commenters stated that the EPA cannot utilize projects under development as a basis for justifying CCS as BSER for coal fired units and then abandon this basis for NGCC units. In addition, some commenters disagreed with the EPA's decision to treat NGCC differently than coal-fired units on the basis that NGCC units start up and shut down more frequently than coal-fired units. The commenter said operating characteristics of NGCC units are not an impediment to using partial CCS, and suggested that NGCC operators could bypass the carbon capture system during startup and shutdown modes (which are typically shorter and less intensive efforts compared to startup or shutdown of a coal facility) and then employ the carbon capture system when operating normally. Many commenters stated that CO2 removal is just as technologically feasible and economically reasonable for an NGCC EGU as a coal-fired EGU. These commenters referred to literature suggesting that at 40 percent removal there would be no expected difference in the technical requirements for either type of EGU. Some commenters referred to a DOE/NETL study that suggests the cost of CCS for NGCC is more cost effective than for coal-fired EGUs.
      Many commenters supported the EPA's determination that NGCC with CCS technology is not BSER for newly constructed, modified, or reconstructed combustion turbines. These commenters agreed that there are insufficient data on costs and site-specific constraints to conclude that CCS and EOR technologies are available and feasible at the numerous locations in the U.S. where combined cycle projects are currently planned based on projected natural gas prices. Commenters stated that the limited scope of the one CCS-on-NGCC project cited in the proposal did not reflect the costs of pipeline transport and geologic sequestration implicit in use of this technology as a nation-wide BSER technology because the slip stream of CO2 is used at a local facility that temporarily incorporates the CO2 into food products. Commenters also stated that CCS has not been adequately demonstrated or proven to be commercially viable for NGCC units. Other commenters stated that CO2 capture technologies do not match well with the operating flexibilities of NGCC and simple cycle units, and even if technical barriers could be overcome, application of CCS to gas-fired turbines would also be more costly (compared to applications of CCS to coal-fired units) on a dollars-per-ton-CO2-captured basis because of the higher flue gas volumes (per MW of generating capacity) and the lower CO2 concentrations from methane combustion in turbines compared to coal combustion in boilers.
      Some commenters stated that a CCS-based standard for NGCC units would negatively impact the environment and the nation's energy needs. They also stated that CAA section 111(a) requires the EPA to account not only for the cost of achieving emission reductions, but also for the impact of BSER on energy requirements and the environment. The commenters cited Costle, where the D.C. Circuit observed that, following its analysis of adequately demonstrated emissions technology, the EPA "must exercise its discretion to choose an achievable emission level which represents the best balance of economic, environmental, and energy considerations." The commenters also stated that requiring CCS on natural gas units would adversely affect the nation's energy needs and the environment because imposing partial CCS on natural gas-fired combustion turbines would invariably delay the emission reductions that can be obtained from new NGCC projects that displace load from older less efficient generating technologies. Finally, the commenters stated that since NGCC units are projected to provide a significant share of new power generation, the EPA should recognize that requiring partial CCS on NGCC units would have proportionally higher impact on electricity prices compared to the projected number of new coal-fired generating projects. These commenters concluded that the EPA cannot determine that partial CCS is BSER for NGCC units without producing severe and unacceptable consequences for the availability of affordable electricity in the United States. In a related comment, another commenter said that CCS is technically feasible for gas turbine facilities, but agrees that requiring CCS for all new NGCC plants may hinder the construction of new, more efficient NGCC. Instead, the commenter suggested the EPA defer a decision on whether CCS is BSER for combustion turbine units until the subsequent NSPS revisions. The commenter expressed concerns that the EPA's rationale for rejecting CCS as BSER for NGCC, may be used by developers and permitting authorities as an excuse to reject CCS as Best Available Control Technology (BACT) in future New Source Review (NSR) permits.
      Some commenters stated that the proposed BSER analysis should have reflected the emission rates achieved by the latest designs deployed at advanced, state-of-the-art, NGCC installations. These commenters stated that advanced NGCC technologies are the best system for reducing CO2 emissions with no negative environmental impacts and no negative economic impacts on rate payers. These commenters stated that advanced NGCC technologies are capable of achieving emission rates that are 8 percent lower than conventional NGCC facilities. Commenters said that the majority of existing sources that do not deploy these advanced technologies are currently able to meet the standard, and commenters said that the proposal failed to explain why these lower-emitting advanced technologies that are more than adequately demonstrated were not selected as the BSER.
3. Identification of BSER
      As stated in the proposal, combined cycle units have both lower GHG emissions and a lower cost of electricity than simple cycle turbine facilities when operated as intermediate and base load EGUs. Therefore, the use of a combined cycle technology would be BSER for higher capacity factor stationary combustion turbines. The EPA refined the LCOE costing approach used at proposal to compare the cost effectiveness of simple cycle combustion turbines compared to combined cycle combustion turbines by adding costs and efficiency impacts due to frequent cycling. Even accounting for these costs, combined cycle technology results in a lower cost of electricity, compared to a simple cycle unit, when electric sales exceed one-third of the potential electric output. Furthermore, we have concluded that high efficiency simple cycle turbine technology is a sub-component of the selected BSER. Recent combined cycle installations have included dampers that allow the associated combustion turbine to operate in either combined cycle mode or simple cycle mode. The selected BSER and emission standard is compatible with the construction of new, modified, and reconstructed bi-modal units with dampers that allow the new source to operate in either combined cycle mode or in simple cycle mode; therefore the use of combined cycle technology is BSER for periods of intermediate and base load operation. However, for dedicated peaking applications highly efficient simple cycle technology alone is considered the BSER.
	The EPA has reviewed the comments on the use of CCS for combined cycle facilities and has concluded that even if CCS is demonstrated as a technical and reasonable cost option for combined cycle units on an individual basis, it would not qualify as BSER based on the nationwide economic impacts. Therefore, the EPA is not making a determination as to the technical availability or individual cost reasonableness of CCS for new combined cycle units. Nearly all new fossil fuel-fired EGUs being constructed today are using combined cycle technology for generating intermediate and base load power and requiring partial CCS on these units would result in unreasonable nationwide impacts.
	The EPA has concluded that advanced combined cycle technology is simply incremental improvements to traditional combined cycle designs and not a unique technology and therefore cannot be the BSER. The emission rates achieved by these technologies were included within the data set of newer combined cycle designs used for establishing the standard. In addition, review of the operating data for combined cycle power blocks installed since 2000 indicates that the mode of operation in response to system demand (e.g., base load or intermediate load and capacity factor in general) impacts achieved efficiencies to a large enough extent that we cannot evaluate the impact of particular subcomponents used within the power block. So a conventional combined cycle power block located in a region of the country where system demand requires the power block to run continuously at base load can achieve higher efficiencies than an advanced combined cycle power block located in a region where system demand requires the power block to cycle on and off to match system demand. For this reason, our data set included a large population of technologies and load conditions to ensure that new combined cycle power blocks can achieve the section 111 standard in all regions of the country.
4. Identification of Applicability Based on Permitted Electric Sales
      At proposal, we assumed all combustion turbines operating above the proposed 1/3 electric sales criterion would be able to comply with a standard consistent with the performance of recently constructed combined cycle facilities. However, as described in the applicability section, our understanding of the future role of combustion turbine EGUs has evolved. At this time however, we do not have sufficient information to establish an appropriate output-based emission rate for combustion turbines operating with operations that span this entire category. Therefore, our applicability approach is to use a sliding scale trigger. With the sliding scale approach, the trigger for applicability for the combined cycle standard depends on the design efficiency of the unit. Affected units subject to federally enforceable permit restrictions limiting operating below the electric sales threshold would not be required to comply with the requirements included in subpart TTTT. This both encourages the installation of the most efficient technologies intended for limited operation by giving the most efficient units the flexibility to sell more electricity and minimizes emissions for higher capacity factor units by requiring them to comply with the requirements of subpart TTTT.
      As discussed previously, the proposed percent actual electric sales relative to the potential electric output criterion is being finalized as a permit restriction applicability criteria. Based on the concerns raised in the comments about the impact of intermittent renewable generation (e.g., wind and solar) on the operation of simple cycle turbines, the EPA has done additional analysis. First, we evaluated the percent sales applicability criterion in greater detail to get a more accurate picture of how many simple cycles would have met the electric sales applicability criterion based on historical operation. We also examined the operation of simple turbines in regions with relatively large amounts of wind and solar generation.
      In the proposal, the EPA estimated the number of simple cycle turbines that would have met the proposed applicability based on the number of simple cycle turbines that operated over 2,920 hours in any year. However, this was a simplification of the one-third actual electric sales criteria and overestimated the number of potentially impacted simple cycle turbines in two ways. First, the 2,920 hours simplification assumes operation at full load. However, the typical duty cycle (average capacity factor while operating) of simple cycle turbines is approximately 70 percent. Therefore, simple cycle turbines can operate in excess of 2,920 hours and still not be selling one-third of their potential electric output. Historically, only 10 of the 1,939 existing simple cycle turbines have individual years where sales exceeded one-third of their potential electric output. Second, the proposed one-third electric sales applicability criterion was on a 3-year rolling average basis. Using 3-year rolling average basis, the number of existing simple cycle turbines that historically sold enough electricity to meet the proposed one-third electric sales applicability is only two.
	We used information reported to the Energy Information Administration (EIA) to determine the impact of renewable generation on the operation of simple cycle turbines. The EIA provides data on the total in-state electricity generation, including wind and solar, from 2008 through 2014. Interstate flow of electricity is available from 2008 through 2012. California, Texas, and the Southwest Power Pool (data approximated by EGUs in Nebraska, Kansas, and Oklahoma) all had increases for the percent of wind and solar electricity generated in-state and percent of total electric generation from wind and solar from 2008 through 2014. To determine the observed impact of the increased generation from intermittent renewable sources, the EPA reviewed data submitted for simple cycle turbines to the EPA's Clean Air Markets Division (CAMD) over the same time period.
	The percent of in-state generation from wind and solar in the Southwest Power Pool increased from 3 to 16 percent between 2008 and 2014. The average growth rate of wind and solar was 28 percent, while overall electricity demand grew 1 percent annually on average. Based on statements in some of the comments, we would expect to see a large change in the operation of simple cycle turbines in this region. However, the average percent electric sales compared to the potential electric output from simple cycle turbines only increased at an annual rate of 1.7 percent, and remained essentially unchanged at 3 percent of potential electric sales between 2008 and 2014. Overall, generation from simple cycle turbines increased slightly more at an annual rate of 2.5 percent, resulting from additional simple cycle capacity being in line with what was expected due to overall increased electricity demand. The lack of significant change in the operation of simple cycle turbines in this region could be explained by the relatively large amount of exported power. If most of the intermittent power was being exported, the intermittent nature of the power would primarily impact other transmission regions. An alternate explanation is that other generating assets are flexible enough to respond to the intermittent nature of wind generation and that simple cycle turbines are not necessary to backup wind and solar generating assets to the degree some commenters suggested. If this were the case, then new simple cycle turbine will primarily continue to fill their historical role as peaking units and flexible combined cycle units will provide the primary backup capacity for new wind and solar generating assets.
	The percent of in-state generation from wind and solar in Texas increased from 4 to 9 percent between 2008 and 2014. The average growth rate of wind and solar was 13 percent, while the overall demand grew an average of 2 percent annually. However, similar to the Southwest Power Pool, the overall percent of electric sales relative to the potential electric output from simple cycle turbines has remained relatively unchanged. Average electric sales relative to potential electric output from simple cycle turbines increased at an annual rate of 0.9 percent. However, the overall generation from simple cycle combustion turbines increased at an annual rate of 6.6 percent, resulting from simple cycle capacity additions occurring at approximately four times what would be expected from growth in overall demand. The EPA has concluded that the most likely simple cycle turbines to support intermittent renewable generation are the most efficient simple cycle combustion turbines installed in the particular transmission region. There are two highly efficient intercooled simple cycle turbines installed in Texas. These two combustion turbines sell an average of 10 percent of their potential electric output annually, compared to an average of 3 percent for the remaining simple cycle turbines. No simple cycle turbine in Texas sold more than 25 percent of its potential electric sales annually.  This growth in simple cycle turbine capacity could indicate that additional generation assets are necessary to provide firm capacity for intermittent generation sources such as wind and solar, but based on the data those simple cycle turbines are expected to continue operating as they have historically, and sell less than one-third of their potential electric output.
	The percent of in-state generation from wind and solar in California increased from 3 to 11 percent between 2008 and 2014. The average growth rate of wind and solar was 25 percent, while overall demand has remained stable. The operation of simple cycle turbines in California has changed more significantly than the other evaluated regions. As in Texas, considerable additional simple cycle capacity has been added in recent years. The average capacity of simple cycle turbines is increasing at 15 percent annually even though overall demand has remained relatively steady. In addition, the newest simple cycle turbines are operating at higher capacity factors than the existing fleet of simple cycle turbines. Many of the new additions are intercooled simple cycle turbines that can be installed to back up wind and solar generation. The annual electric sales relative to the potential electric output for the intercooled turbines range from 3 to 25 percent, with a 7 percent average. No simple cycle turbines in California have sold more than one-third of their potential electric output on an annual basis.
      Based on historical amounts of intermittent generation, the proposed one-third actual electric sales threshold would appear to offer sufficient operational flexibility for new simple cycle turbines. Existing combined cycle, other generation assets, and demand response programs are currently proving adequate backup to renewable generation. In the future, however, existing combined cycle facilities will likely provide base load power and operate at higher capacity factors. They will therefore be less available to provide backup power for intermittent generation. In addition, the percent of power generated from intermittent sources is expected to increase in the future. Both of these factors could require additional flexibility from the remaining generation sources to maintain grid reliability. Even though fast start combined cycle technologies, reciprocating internal combustion engines, energy storage technologies, and demand response programs are promising technologies for providing backup power for renewable generation, none of them historically have been deployed in sufficient capacity to provide the potential necessary capacity to facilitate the continued growth of renewable generation. While we anticipate that state and federally issued permits for new electric generating sources will consider the GHG benefits of these technologies compared to simple cycle turbines, the EPA has concluded at this time it is appropriate to finalize an NSPS that provides additional flexibility for new combustion turbines intended to run at lower capacity factors. Specifically, new combustion turbines can avoid the requirements of subpart TTTT by requesting a federally enforceable permit restriction to sell the design efficiency times the potential electric output electricity on an annual basis.
      The EPA considered multiple options for extending flexibility for simple cycle turbines. Ultimately, we concluded that a trigger based on the design net efficiency at standard conditions is appropriate. The electric sales trigger for applicability of the combined cycle based standard would be based on the design net efficiency of the facility. The EPA has concluded this approach provides sufficient operational flexibility for new simple cycle combustion turbines, even with increased future use. In addition, even though the historical electric sales of simple cycle turbines is less than 5 percent, this net efficiency trigger approach has the impact of promoting the installation of the most efficient generating technologies since applicability and operational flexibility would be linked directly to the efficiency of the devices. The design net efficiencies for currently available potentially impacted aeroderivative simple cycle combustion turbines range from approximately 32 percent for smaller designs to 39 percent for the largest intercooled designs. The efficiencies of industrial frame units range from 30 percent for smaller designs to 36 percent for the largest units. These efficiency values follow the methodology the EPA has historically used and are based on the higher heating value (HHV) of the fuel. In contrast, combustion turbine vendors in the United States often quote efficiencies based on the lower heating value (LHV) of the fuel. The LHV of a fuel is determined by subtracting the heat of vaporization of water vapor generated during combustion of fuel from the higher heating value. For natural gas, the LHV is approximately 10 percent lower that the HHV. Therefore, the corresponding LHV efficiency ranges would be 35 to 44 percent for aeroderative designs and 33 to 40 percent for frame designs. Based on comments, we anticipate the aeroderative turbines will make up the majority of new combustion turbines intended for limited use (i.e., peaking) applications. Based on the sliding scale applicability approach, owners/operators of new simple cycle combustion turbines could elect to request a federally enforceable permit limiting annual sales to between 32 to 39 percent of the potential electric output to avoid complying with the standards in this rulemkaing. Based on historical operation of simple cycle turbines, 99.5 percent do not sell more than one-third of their potential electric output on an annual basis. Therefore, the majority of new simple cycle applications could take a permit restriction without impacting how they would operate or what combustion turbine they would select. In addition, 99.9 percent of simple cycle turbines operate less than 36 percent on an annual basis. Owners/operators of new simple cycle combustion turbines would still have multiple technology options available to them to accommodate this amount of operation. The two simple cycle turbines that exceeded the 36 percent threshold had annual sales of 39 and 45 percent and are located in Montana and New York respectively. As noted earlier, the most efficient simple cycle turbine is 39 percent efficient and would accommodate operation of the Montana facility. The only simple cycle turbine that exceeded the maximum electric threshold permit restriction, based on current simple cycle designs, sold an abnormally high amount of electricity in 2014. It is possible that this unit was operating under emergency conditions and the incremental generation due to the emergency would not have been counted as net electric sales for applicability purposes. Regardless, as described earlier, for combustion turbines operating above this threshold it is cost effective and the BSER is the additional of heat recovery to the turbine exhaust. Since the definition of stationary combustion turbine includes both simple and combined cycle units, we are capping the maximum permit restriction to 40 percent of the potential electric output. Combined cycle unit design efficiencies often exceed 50 percent. Without this restriction many existing combined cycle units could request permit limitations to avoid applicability with the 111(d) requirements.
C. Achievability of the Final Standards
      We concluded at proposal that, for a combustion turbine designed to sell greater than one-third of its potential electric output, adding heat recovery and converting to a combined cycle is both cost effective (i.e., results in a lower cost of electricity) and results in a lower emission rate. The proposed standards of performance for natural gas-fired stationary combustion turbines were in the form of a gross-output-based emission limit expressed in units of mass of CO2 per unit of gross energy output, specifically, in lb CO2/MWh-gross. The subcategories for which the EPA proposed separate standards of performance were (1) large natural gas-fired stationary combustion turbines with a base load rating greater than 850 MMBtu/h and (2) small natural gas-fired stationary combustion turbines with a base load rating less than or equal to 850 MMBtu/h. The EPA solicited comment on a broad range of issues related to the final standard. For new, modified, and reconstructed units we proposed a limit of 1,000 lb CO2/MWh-gross for large units (base load heat input rating greater than 850 MMBtu/h) and 1,100 lb CO2/MWh-gross for small units (base load heat input rating of 850 MMBtu/h or less). We solicited comment on a range of 950  -  1,100 lb CO2/MWh for large stationary combustion turbines and an emission standard range of 1,000  -  1,200 lb CO2/MWh for small stationary combustion turbines. We also solicited comment on eliminating the size subcategory, increasing the size distinction between large and small stationary combustion turbines to 900 MMBtu/h to account for larger aeroderivative designs, to 1,000 MMBtu/h to account for future incremental increases in base load ratings, or on increasing the size distinction to between 1,300 to 1,800 MMBtu/h. In addition, we solicited comment on establishing a variable capacity factor threshold that would allow more efficient, lower emitting turbines to run and be permitted for longer periods of operation (e.g., a higher capacity factor for the most efficient turbines being progressively lowered for lower efficiency turbines).
      With respect to the size subcategory, some commenters and others agreed with the 850 MMBtu/h break point between large and small units, some suggested increasing it to 1,500 MMBtu/h, and others suggested eliminating the size based subcategorization. Some commenters stated that the current 850 MMBtu/h size distinction is inappropriate for CO2 because it was originally determined based on NOX performance and not significant for CO2 emission rates. These commenters stated that the 850 MMBtu/h cut-point, when compared to the existing fleet, does not result in a logical cut-point with a clear demarcation of higher emitting versus lower emitting technology on either side of this value, but rather divides the units at an arbitrary size classification. These commenters suggested 1,500 MMBtu/h since there is a clear cut-point in the existing fleet of gas turbines between the heat input range of 1,300 MMBtu/h and 1,800 MMBtu/h, with more efficient and lower CO2 emitting technology above and below 1,500 MMBtu/h.
      In contrast, other commenters said that differentiation of small and large gas turbines cannot be justified because many of the same technologies that reduce the emission rates of larger units could be incorporated into smaller units. Commenters also said that separate standards for small and large turbines undermine the incentive for technology innovation, a key purpose of the NSPS program, and that relaxing standards for smaller units will discourage investment in more efficient technologies. These commenters recommended that the limit for both large and small units be no higher than 1,000 lb CO2/MWh. Finally, some commenters suggested that the EPA should regulate multiple small units built together as a single large unit if the combined heat input capacity of all gas turbines at the facility exceeds 850 MMBtu/h.
      Numerous commenters from the power sector, air permitting authorities, and environmental groups acknowledged that accelerating renewable portfolio standards in certain states coupled with NERC reliability requirements can affect the performance of combined cycle natural gas EGUs as they are increasingly cycled and operated at lower capacity factors to complement hourly variations in intermittent renewable generation (e.g., solar and wind). However, commenters had a wide range of opinions on the extent to which intermittent renewables should be used to justify increasing the national emissions standard above the emission rate that can be achieved by well-operated and maintained intermediate and base-loaded combined cycle plants.
      Commenters from the power sector generally supported increasing the standard for each subcategory to 1,100 lb CO2/MWh-gross for large units and 1,200 lb CO2/MWh-gross for small units and finalizing standards for modified and reconstructed standards that are 10 percent higher than the final standards for newly constructed combustion turbines because combustion turbines constructed prior to 2000 were not included in the EPA's BSER analysis for new sources. Conversely, some commenters stated that the proposed standards for combustion turbines do not reflect the emission rates that are achievable by modern, efficient NGCC power blocks, and these commenters do not believe the proposed numerical standards meet the CAA section 111 requirements for BSER. Some commenters stated that the appropriate limitation, consistent with Congressional objectives under CAA section 111, is 800 lb CO2/MWh-gross based on the performance of the lowest emitters in the CAMD database. Some commenters stated that a limitation of 850 lb CO2/MWh-gross reflected BSER for high-capacity factor units because half of the combined cycle plants in the CAMD database are achieving this level of emissions. One commenter from the power sector who operates combined cycle power plants stated that the final standard for new large combustion turbines should be 925 lb CO2/MWh-gross. Several other commenters stated that a reasonable standard for new combustion turbines would be 950 lb CO2/MWh-gross, and several commenters stated that the final standard for new small combustion turbines should be 1000 lb CO2/MWh-gross. Numerous commenters stated that the final standard for new sources should not exceed 1,000 lb CO2/MWh-gross for either large or small combustion turbines. Other commenters stated that since the standards were developed based on emission rates that are being achieved by the majority of existing units, the final standards should be the same for new, modified, and reconstructed units. These commenters stated that since the standards were developed based on emission rates that are being achieved by the majority of existing units, the final standards should be the same for new, modified, and reconstructed units.
      Numerous commenters supported tiered subcategories for peaking, load-following/intermediate, and base load units. Commenters noted that the EPA's proposals excluded units that operate in peaking mode and argued there is no basis in law or policy to exempt units from regulation simply because they operate less frequently, and hence less efficiently. Commenters said the EPA should cover all sources that supply (or are designed to supply) any amount of electricity to the grid, and should distinguish subcategories based on actual operation. Several commenters supported tiered standards based on capacity factor. They proposed 825 lb CO2/MWh-gross for base load units (those operating over 4,000 hours annually), 875 lb CO2/MWh-gross for intermediate and load-following units (those operating between 1,200 and 4,000 hours annually), and 1,100 lb CO2/MWh-gross for peaking units (those operating less than 1,200 hours per year). One of the most common comments received was that peaking units should be either included in a subcategory or completely exempted due to the highly variable capacity factors and duty cycles imposed by system operators on these versatile generators. Numerous commenters pointed to recent BACT limits for CO2 that indicate tiered limits are appropriate for the different roles served by combustion turbines citing BACT limits from 1,328 to 1,450 lb CO2/MWh-gross for peaking units. One commenter supported tiered limits consistent with recent BACT determinations in the State of New York: a combined cycle limit of 925 lb CO2/MWh-gross and a simple cycle limit of 1,450 lb CO2/MWh-gross. An air quality regulator from a state with rapidly increasing renewable generation supported a limit of 825 lb CO2/MWh-gross for base load NGCC units; 1,000 lb CO2/MWh-gross for intermediately loaded, large NGCC units; 1,100 lb CO2/MWh-gross for intermediately loaded, small NGCC units; and this commenter recommended that the EPA set a numerical limit specifically for peaking units after completion of a peaker-specific BSER analysis.
      Other commenters opposed the tiered approach. Commenters suggested that separate standards for different operating conditions would be complicated to implement and enforce, provide few benefits, and could have the unintended consequence of encouraging less efficient technologies and less efficient operation. Commenters added that annual capacity factors would likely vary significantly from year to year, and possibly from month to month as the 12 operating month average is recalculated every operating month. The commenters stated that this real-world variability and uncertainty significantly diminishes the value of creating tiered standards for peaking and load-following units because individuals responsible for long-range decisions related to reliability may react to a system of tiered standards by purchasing additional generating assets to ensure system demand can be satisfied while operating individual units below tier-specific thresholds.
      After further evaluation, the EPA has concluded against subcategorizing the combustion turbine standard based on size for several reasons. While some commenters suggested that the division between large and small should be increased to 1,500 MMBtu/h, other commenters said subcategorizing based on size would distort the market and provide a regulatory incentive to install less efficient, smaller combined cycle facilities, resulting in increased GHG emissions. The EPA reviewed data on the size of available combined cycle facilities (without duct burners) listed in Gas Turbine World. Combined cycle turbines are not currently offered in the following output sizes: between 600 to 800 MMBtu/h, 1,000 to 1,200 MMBtu/h, and 1,300 to 1,800 MMBtu/h based on the heat input to the combustion turbine engine. However, a review of heat input data by the EPA for combined cycle facilities submitted to the EPA Clean Air Markets Division show that multiple combined cycle facilities have been built in the past with heat input capacities with the capacities listed above. Therefore, the EPA has concluded that the regulated community uses various sizes of combined cycle facilities and that no clear cut point distinguishes small and large combined cycle facilities. Subcategorizing by size could unduly influence the selection of technology and development of future turbine offerings. Further, the average emissions rate of combined cycle facilities of less than 850 MMBtu/h (the proposed cut point) is lower than the average emissions rate of combined cycle facilities with heat input ratings of 850 MMBtu/h up to 1,500 MMBtu/h. Finally, the EPA has concluded that, while certain smaller combined cycle designs are less efficient than larger combined cycle designs, this is primarily related to design choices of the heat recovery steam generator, and is not an inherent limitation in the technical ability of small combined cycle technologies to have comparable efficiencies to large combined cycle facilities.
	Since the standards were proposed, the EPA has expanded the NGCC emissions rate analysis that supported the proposed emission standards to include emissions information for combined cycle facilities that commenced operation in 2011, 2012, and 2013 and updated the emissions data to include emissions through 2014. Based on analysis of these data and the comments submitted on the proposed standard, the EPA has concluded that an emission standard of 1,000 lb CO2/MWh-gross is achievable for all affected combustion turbines. Therefore, the EPA is finalizing an emission standard of 1,000 lb/MWh-gross for all combustion turbines without any size based subcategories. Emissions data from combined cycle facilities with heat input ratings of less than 850 MMBtu/h have demonstrated that this level is achievable for smaller combined facilities. The sixteen NGCC facilities evaluated using the Clean Air Markets data have heat input rates of less than or equal to 850 MMBtu/h and an average 12-month maximum CO2 emission rate of 952 lb/MWh-gross. Three of the facilities evaluated using the Clean Air Markets data had a maximum 12-operating month rolling average emissions rate equal to or greater than 1,000 lb CO2/MWh-gross. One of those facilities had a maximum 12-operating-month rolling average emissions rate equal to or greater than 1,100 lb CO2/MWh-gross. In addition, the five facilities that commenced construction between 2007 and 2012 all have maximum 12-month emission rates of less than 950 lb CO2/MWh-gross. For larger units, twenty-five of the 314 combined cycle facilities with heat input ratings greater than 850 MMBtu/h had maximum 12-month average emission rates greater than 1,000 lb CO2/MWh. The analysis inherently includes multiple years of data and did not filter out periods of startup, shutdown, operation at intermediate load, or cycling when determining the maximum 12-operating month emission rate. The final standard includes a sufficient compliance margin to account for any performance degredation in the operation of these facilities.
      In addition, multiple technologies that can increase the performance of new combined cycle facilities are currently available. First, vendors continue to improve the single cycle efficiency of combustion turbines. The use of more efficient combustion turbine engines improves the overall efficiency of combined cycle facilities. In addition, existing smaller combined cycle facilities were likely designed using single or dual pressure heat recovery steam generators without a reheat cycle. New designs could incorporate three pressure steam generators with a reheat cycle to improve the overall efficiency of the combined cycle facility. Additional technologies to reduce emission rates for new combustion turbines include CHP and integrated non-emitting technologies.
      The EPA reviewed the GHG limitations in recently issued construction permits for NGCC facilities. In total 31 major permits were identified with 39 discrete limits on GHG emissions. Eight of the limits were expressed as lbs/h or tons per year and were not included in the analysis. In addition, One CHP unit that generates electricity and supplies steam to a chemical plant was in the set with a limit of 1,362 lb CO2/MWh based only on the gross electrical portion of output and does not account for the useful thermal output. Therefore, it was also not included in this analysis. Two of the permits did not clearly specify if the output based standard was on a gross or net basis and were therefore also excluded. The remaining 28 permit standards were expressed on a lb CO2/MWh or a heat rate basis that could be converted to a lb CO2/MWh basis. Eight permit limits were based on net output ranging from 774-936 lb CO2/MWh-net. The lowest emission limit was for a hybrid power plant with a solar component of heat input that could contribute up to 50 MW. Twenty permit limits were based on gross output ranging from 833-1,100 lb CO2/MWh-gross. Of these 28 permit limits, only one unit had a heat input capacity less than 1,500 MMBtu/h (366 MMBtu/h); this unit also had the highest emission limit of 1,100 lb CO2/MWh. All permit limits were evaluated over an annual period. Most of these permits included an allowance for a design margin to reflect the possibility that the constructed facility will not be able to achieve the design heat rate; an allowance for efficiency losses due to combustion turbine degradation prior to maintenance overhauls; an allowance for the steam turbine system; and an allowance for the variability in operation of auxiliary plant equipment due to use over time. Typically, the sum of these allowances was in the range of 10 to 13 percent. Limits typically considered whether the unit would be base load or load-following. Some permits limited the amount of No. 2 fuel oil that could be used as backup fuel and adjusted emission limits to account for this use. Startup and shutdown emissions were typically included in the annual average compliance calculation.
X. Summary of Other Final Requirements for Newly Constructed, Modified, and Reconstructed Fossil Fuel-fired Electric Utility Steam Generating Units and Stationary Combustion Turbines
      This section describes the final action's requirements regarding startup, shutdown, and malfunction; continuous monitoring; emissions performance testing; continuous compliance; and notification, recordkeeping, and reporting for newly constructed, modified, and reconstructed affected steam generating units and combustion turbines. We also explain final decisions regarding several of these requirements.
A. Startup, Shutdown, and Malfunction Requirements
      In its 2008 decision in Sierra Club v. EPA, 551 F.3d 1019 (D.C. Cir. 2008), the U.S. Court of Appeals for the District of Columbia Circuit vacated portions of two provisions in the EPA's CAA section 112 regulations governing the emissions of hazardous air pollutants (HAP) during periods of startup, shutdown, and malfunction (SSM). Specifically, the Court vacated the SSM exemption contained in 40 CFR 63.6(f)(1) and 40 CFR 63.6(h)(1), holding that under section 302(k) of the CAA, emissions standards or limitations must be continuous in nature and that the SSM exemption violates the CAA's requirement that some CAA section 112 standards apply continuously.
      Consistent with Sierra Club v. EPA, the EPA has established standards in this rule that apply at all times. In establishing the standards in this rule, the EPA has taken into account startup and shutdown periods and, for the reasons explained below, has not established alternate standards for those periods.  Specifically, startup and shutdown periods are included in the compliance calculation as periods of partial load. The final method to calculate compliance is to sum the emissions for all operating hours and to divide that value by the sum of the electric energy output (and useful thermal energy output, where applicable for affected CHP EGUs), over a rolling 12-operating-month period. In their compliance determinations, sources must incorporate emissions from all periods, including startup or shutdown, during which fuel is combusted and emissions are being monitored, in addition to all power produced over the periods of emissions measurements. Given that the duration of startup or shutdown periods is expected to be small relative to the duration of periods of normal operation and that the fraction of power generated during periods of startup or shutdown is expected to be very small, the impact of these periods on the total average over a 12-operating-month period is expected to be minimal.
      Periods of startup, normal operations, and shutdown are all predictable and routine aspects of a source's operations. Malfunctions, in contrast, are neither predictable nor routine. Instead they are, by definition sudden, infrequent and not reasonably preventable failures of emissions control, process or monitoring equipment. (40 CFR 60.2). The EPA interprets CAA section 111 as not requiring emissions that occur during periods of malfunction to be factored into development of section 111 standards. Nothing in CAA section 111 or in case law requires that the EPA consider malfunctions when determining what standards of performance reflect the degree of emission limitation achievable through "the application of the best system of emission reduction" that the EPA determines is adequately demonstrated. While the EPA accounts for variability in setting emissions standards, nothing in CAA section 111 requires the agency to consider malfunctions as part of that analysis. A malfunction should not be treated in the same manner as the type of variation in performance that occurs during routine operations of a source. A malfunction is a failure of the source to perform in a "normal or usual manner" and no statutory language compels the EPA to consider such events in setting CAA section 111 standards of performance.
      Further, accounting for malfunctions in setting emission standards would be difficult, if not impossible, given the myriad different types of malfunctions that can occur across all sources in the category and given the difficulties associated with predicting or accounting for the frequency, degree, and duration of various malfunctions that might occur. As such, the performance of units that are malfunctioning is not "reasonably" foreseeable. See, e.g., Sierra Club v. EPA, 167 F.3d 658, 662 (D.C. Cir. 1999) ("The EPA typically has wide latitude in determining the extent of data-gathering necessary to solve a problem. We generally defer to an agency's decision to proceed on the basis of imperfect scientific information, rather than to 'invest the resources to conduct the perfect study.'") See also, Weyerhaeuser v Costle, 590 F.2d 1011, 1058 (D.C. Cir. 1978) ("In the nature of things, no general limit, individual permit, or even any upset provision can anticipate all upset situations. After a certain point, the transgression of regulatory limits caused by `uncontrollable acts of third parties,' such as strikes, sabotage, operator intoxication or insanity, and a variety of other eventualities, must be a matter for the administrative exercise of case-by-case enforcement discretion, not for specification in advance by regulation."). In addition, emissions during a malfunction event can be significantly higher than emissions at any other time of source operation. For example, if an air pollution control device with 99 percent removal goes off-line as a result of a malfunction (as might happen if, for example, the bags in a baghouse catch fire) and the emission unit is a steady state type unit that would take days to shut down, the source would go from 99 percent control to zero control until the control device was repaired. The source's emissions during the malfunction would be 100 times higher than during normal operations. As such, the emissions over a 4-day malfunction period would exceed the annual emissions of the source during normal operations. As this example illustrates, accounting for malfunctions could lead to standards that are not reflective of (and significantly less stringent than) levels that are achieved by a well-performing, non-malfunctioning source. It is reasonable to interpret CAA section 111 to avoid such a result. The EPA's approach to malfunctions is consistent with CAA section 111 and is a reasonable interpretation of the statute.
      In the event that a source fails to comply with the applicable CAA section 111 standards as a result of a malfunction event, the EPA would determine an appropriate response based on, among other things, the good faith efforts of the source to minimize emissions during malfunction periods, including preventative and corrective actions, as well as root cause analyses to ascertain and rectify excess emissions. The EPA would also consider whether the source's failure to comply with the CAA section 111 standard was, in fact, sudden, infrequent, not reasonably preventable and was not instead caused in part by poor maintenance or careless operation. 40 CFR 60.2 (definition of malfunction).
      If the EPA determines in a particular case that an enforcement action against a source for violation of an emission standard is warranted, the source can raise any and all defenses in that enforcement action and the federal district court will determine what, if any, relief is appropriate. The same is true for citizen enforcement actions. Similarly, the presiding officer in an administrative proceeding can consider any defense raised and determine whether administrative penalties are appropriate.
      In summary, the EPA interpretation of the CAA and, in particular, CAA section 111 is reasonable and encourages practices that will avoid malfunctions. Administrative and judicial procedures for addressing exceedances of the standards fully recognize that violations may occur despite good faith efforts to comply and can accommodate those situations.
      In the January 2014 proposal for newly constructed EGUs, the EPA had proposed to include an affirmative defense to civil penalties for violations caused by malfunctions in an effort to create a system that incorporates some flexibility, recognizing that there is a tension, inherent in many types of air regulation, to ensure adequate compliance while simultaneously recognizing that despite the most diligent of efforts, emission standards may be violated under circumstances entirely beyond the control of the source. Although the EPA recognized that its case-by-case enforcement discretion provides sufficient flexibility in these circumstances, it included the affirmative defense to provide a more formalized approach and more regulatory clarity. See Weyerhaeuser Co. v. Costle, 590 F.2d 1011, 1057-58 (D.C. Cir. 1978) (holding that an informal case-by-case enforcement discretion approach is adequate); but see Marathon Oil Co. v. EPA, 564 F.2d 1253, 1272-73 (9th Cir. 1977) (requiring a more formalized approach to consideration of "upsets beyond the control of the permit holder"). Under the EPA's regulatory affirmative defense provisions, if a source could demonstrate in a judicial or administrative proceeding that it had met the requirements of the affirmative defense in the regulation, civil penalties would not be assessed. Recently, the U.S. Court of Appeals for the District of Columbia Circuit vacated an affirmative defense in one of the EPA's CAA section 112 regulations. NRDC v. EPA, 749 F.3d 1055 (D.C. Cir., 2014) (vacating affirmative defense provisions in CAA section 112 rule establishing emission standards for Portland cement kilns). The court found that the EPA lacked authority to establish an affirmative defense for private civil suits and held that under the CAA, the authority to determine civil penalty amounts in such cases lies exclusively with the courts, not the EPA. Specifically, the Court found: "As the language of the statute makes clear, the courts determine, on a case-by-case basis, whether civil penalties are `appropriate.'" See NRDC at 1063 ("[U]nder this statute, deciding whether penalties are `appropriate' in a given private civil suit is a job for the courts, not EPA."). In light of NRDC, the EPA is not including a regulatory affirmative defense provision in this final rule. As explained above, if a source is unable to comply with emissions standards as a result of a malfunction, the EPA may use its case-by-case enforcement discretion to provide flexibility, as appropriate. Further, as the D.C. Circuit recognized, in an EPA or citizen enforcement action, the court has the discretion to consider any defense raised and determine whether penalties are appropriate. Cf. NRDC, at 1064 (arguments that violations were caused by unavoidable technology failure can be made to the courts in future civil cases when the issue arises). The same is true for the presiding officer in EPA administrative enforcement actions.
B. Continuous Monitoring Requirements
      The majority of comments received on the proposal supported the EPA's use of existing monitoring requirements under the Acid Rain Program, which are contained in 40 CFR part 75 requirements. In response to this, the EPA is finalizing monitoring requirements that incorporate and reference the part 75 monitoring requirements as frequent as practicable while ensuring monitoring accuracy and stringency required under the program.
      This final rule requires owners or operators of EGUs that combust solid fossil fuel to install, certify, maintain, and operate continuous emission monitoring systems (CEMS) to measure CO2 concentration, stack gas flow rate, and (if needed) stack gas moisture content in accordance with 40 CFR part 75, in order to determine hourly CO2 mass emissions rates (tons/hr).
	The rule allows owners or operators of affected EGUs that burn exclusively gaseous or liquid fuels to install fuel flow meters as an alternative to CEMS and to calculate the hourly CO2 mass emissions rates using Equation G-4 in Appendix G of Part 75. To implement this option, hourly measurements of fuel flow rate and periodic determinations of the gross calorific value (GCV) of the fuel are also required, in accordance with Appendix D of Part 75.
	In addition to requiring monitoring of the CO2 mass emission rate, the rule requires EGU owners or operators to monitor the hourly unit operating time and "gross output", expressed in megawatt hours (MWh). The gross output includes electrical output plus any mechanical output, plus 75 percent of any useful thermal output.
	The rule requires EGU owners or operators to prepare and submit a monitoring plan that includes both electronic and hard copy components, in accordance with sections 75.53(g) and (h). The electronic portion of the monitoring plan should be submitted to the EPA's Clean Air Markets Division (CAMD) using the Emissions Collection and Monitoring Plan System (ECMPS) Client Tool. The hard copy portion of the plan should be sent to the applicable State and EPA Regional office. Further, all monitoring systems used to determine the CO2 mass emission rates have to be certified according to section 75.20 and section 6 of Part 75, Appendix A within the 180-day window of time allotted under section 75.4(b), and are required to meet the applicable on-going quality assurance procedures in Appendices B and D of Part 75.
      The rule requires all valid data collected and recorded by the monitoring systems (including data recorded during startup, shutdown, and malfunction) to be used in assessing compliance. Failure to collect and record required data is a violation of the monitoring requirements, except for periods of monitoring system malfunctions, repairs associated with monitoring system malfunctions, and required monitoring system quality assurance or quality control activities that temporarily interrupt the measurement of stack emissions (e.g., calibration error tests, linearity checks, and required zero and span adjustments).
      The rule requires only those operating hours in which valid data are collected and recorded for all of the parameters in the CO2 mass emission rate equation to be used for calculating compliance with applicable emission limits. Additionally for EGUs using CO2 CEMS, only unadjusted stack gas flow rate values should be used in the emissions calculations. In this rule, Part 75 bias adjustment factors (BAFs) should not be applied to the flow rate data. These restrictions on the use of Part 75 data for Part 60 compliance are consistent with previous NSPS regulations and revisions. Additionally if an affected EGU combusts natural gas and/or fuel oil and the CO2 mass emissions rate are measured using Equation G-4 in Appendix G of Part 75, then determination of site-specific carbon-based F-factors using Equation F-7b in section 3.3.6 of Appendix F of Part 75 is allowed, and use of these Fc values in the emissions calculations instead of using the default Fc values in the Equation G-4 nomenclature is also allowed.
      This final rule includes the following special compliance provisions for units with common stack or multiple stack configurations; these provisions are consistent with section 60.13(g):
     * If two or more EGUs share a common exhaust stack, are subject to the same emission limit, and the operator is required to (or elects to) determine compliance using CEMS, then monitoring the hourly CO2 mass emission rate at the common stack instead of monitoring each EGU separately is allowed. If this option is chosen, the hourly gross electrical load (or steam load) is the sum of the hourly loads for the individual EGUs and the operating time is expressed as "stack operating hours" (as defined in 40 CFR 72.2). Then, if compliance with the applicable emission limit is attained at the common stack, each EGU sharing the stack will be in compliance with the CO2 emissions limit.
     * If the operator is required to (or elects to) determine compliance using CEMS and the effluent from the EGU discharges to the atmosphere through multiple stacks (or, if the effluent is fed to a stack through multiple ducts and is monitored in the ducts), then monitoring the hourly CO2 mass emission rate and the "stack operating time" at each stack or duct separately is required. In this case, compliance with the applicable emission limit is determined by summing the CO2 mass emissions measured at the individual stacks or ducts and dividing by the total gross output for the unit.
      The rule requires 95 percent of the operating hours in each compliance period (including the compliance periods for the intermediate emission limits) to be valid hours, i.e., operating hours in which quality-assured data are collected and recorded for all of the parameters used to calculate CO2 mass emissions. EGU owners or operators have the option to use backup monitoring systems, as provided in sections 75.10(e) and 75.20(d), to help meet this data capture requirement. This requirement is separate from the requirement for a source to demonstrate compliance with an applicable emission standard. When demonstrating compliance with an emission standard the calculation must use all valid data to calculate a compliance average even if the percent of valid hours recorded in the period is less than the 95 percent requirement.
C. Emissions Performance Testing Requirements
      Similarly to the comments received on monitoring for the proposal, commenters in general supported the use of current testing requirements required under the Acid Rain Program 40 CFR part 75 requirements.  Thus the EPA is finalizing requirements for performance testing as consistent with part 75 requirements where appropriate to ensure the quality and accuracy of data and measurements as required by the final rule.
      In accordance with section 75.64(a), the final rule requires an EGU owner or operator to begin reporting emissions data when monitoring system certification is completed or when the 180-day window in section 75.4(b) allotted for initial certification of the monitoring systems expires (whichever date is earlier). For EGUs subject to the 1,400 lb CO2/MWh-gross) emission standard, the initial performance test consists of the first 12 operating months of data, starting with the month in which emissions are first required to be reported. The initial 12-operating-month compliance period begins with the first month of the first calendar year of EGU operation in which the facility exceeds the capacity factor applicability threshold.
      The traditional 3-run performance tests (i.e., stack tests) described in section 60.8 are not required for this rule. Following the initial compliance determination, the emission standard is met on a 12-operating-month rolling average basis.
D. Continuous Compliance Requirements
      This final rule specifies that compliance with the 1,400 lb CO2/MWh-gr emission limit is determined on a 12-operating-month rolling average basis, updated after each new operating month. For each 12-operating-month compliance period, quality-assured data from the certified Part 75 monitoring systems is used together with the gross output over that period of time to calculate the average CO2 mass emissions rate.
      The rule specifies that the first operating month included in the initial 12-operating-month compliance period is the month in which reporting of emissions data is required to begin under section 75.64(a), i.e., either the month in which monitoring system certification is completed or the month in which the 180-day window allotted to finish certification testing expires (whichever month is earlier).
      Initial compliance with the applicable emissions limit in kg/MWh is calculated by dividing the sum of the hourly CO2 mass emissions values by the total gross output for the 12-operating-month period. Affected EGUs continue to be subject to the standards and maintenance requirements in the CAA section 111 regulatory general provisions contained in 40 CFR part 60, subpart A.
E. Notification, Recordkeeping, and Reporting Requirements
      This final rule requires an EGU owner or operator to comply with the applicable notification requirements in section 75.61, sections 60.7(a)(1) and (a)(3), and section 60.19. The rule also requires the applicable recordkeeping requirements in subpart F of part 75 to be met. For EGUs using CEMS, the data elements that are recorded include, among others, hourly CO2 concentration, stack gas flow rate, stack gas moisture content (if needed), unit operating time, and gross electric generation. For EGUs that exclusively combust liquid and/or gaseous fuel(s) and elect to determine CO2 emissions using Equation G-4 in Appendix G of Part 75, the key data elements in subpart F that are recorded include hourly fuel flow rates, fuel usage times, fuel GCV, gross electric generation.
      The rule requires EGU owners or operators to keep records of the calculations they perform to determine the total CO2 mass emissions and gross output for each operating month. Records of the calculations performed to determine the average CO2 mass emission rate (kg/MWh) and the percentage of valid CO2 mass emission rates in each compliance period are required to be kept. The rule also requires sources to keep records of calculations performed to determine site-specific carbon-based F-factors for use in Equation G-4 of Part 75, Appendix G (if applicable).
      Sources are required to keep all records for a period of 3 years. All required records must be kept on-site for a minimum of 2 years, after which the records can be maintained off-site.
      The rule requires all affected EGU owners/operators to submit quarterly electronic emissions reports in accordance with subpart G of Part 75. The reports in Appendix G that do not include data required to calculate compliance with the applicable CO2 emission standard are not required to be reported under this rule. The rule requires the reports in section 60.5555 to be submitted using the ECMPS Client Tool. Except for a few EGUs that may be exempt from the Acid Rain Program (e.g., oil-fired units), this is not a new reporting requirement. Sources subject to the Acid Rain Program are already required to report the hourly CO2 mass emission rates that are needed to assess compliance with this rule.
      Additionally, in the final rule and as part of an agency-wide effort to streamline and facilitate the reporting of environmental data, the rule requires selected data elements that pertain to compliance under this rule, and that serve the purpose of identifying violations of an emission standard, to be reported periodically using ECMPS.
      Specifically, EGU owners/operators must submit quarterly electronic reports within 30 days after the end of each quarter consistent with current Part 75 reporting requirements. The first report is for the quarter that includes the final (12[th]) operating month of the initial 12-operating-month compliance period. For that initial report and any subsequent report in which the 12[th] operating month of a compliance period (or periods) occurs during the calendar quarter, the average CO2 mass emissions rate (kg/MWh) is reported for each compliance period, along with the dates (year and month) of the first and twelfth operating months in the compliance period and the percentage of valid CO2 mass emission rates obtained in the compliance period. The dates of the first and last operating months in the compliance period clearly bracket the period used in the determination, which facilitates auditing of the data. Reporting the percentage of valid CO2 mass emission rates is necessary to demonstrate compliance with the requirement to obtain valid data for 95 percent of the operating hours in each compliance period. Any violations that occur during the quarter are identified. If there are no compliance periods that end in the quarter, a definitive statement to that effect must be included in the report. If one or more compliance periods end in the quarter but there are no violations, a statement to that effect must be included in the report.
      Currently, ECMPS is not programmed to receive the additional information included in the report required under section 60.5555(a)(2) for affected EGUs. However, we will make the necessary modifications to the system in order to fully implement the reporting requirements of this rule upon promulgation.
XI. Interactions with Other EPA Programs and Rules
A. Overview
      This final rule will, for the first time, regulate GHGs under CAA section 111. In Section IX of the preamble to the proposed rule, the EPA addressed how regulation of GHGs under CAA section 111 could have implications for other EPA rules and for permits written under the CAA Prevention of Significant Deterioration (PSD) preconstruction permit program and the CAA Title V operating permit program. The EPA proposed to adopt provisions in the regulations that explicitly addressed some of these implications.
       For purpose of the PSD program, the EPA is finalizing provisions in part 60 of its regulations that make clear that the threshold for determining whether a PSD source must satisfy the Best Available Control Technology (BACT) requirement for greenhouse gases continues to apply after promulgation of this rule. This rule does not require any additional revisions to State Implementation Plans. As discussed further below, this final rule may have bearing on the determination of BACT for new and existing and modified and reconstructed EGUs that require PSD permits. With respect to the Title V operating permits program, this rule does not affect whether sources are subject to the requirement to obtain a title V operating permit based solely on emitting or having the potential to emit GHGs above major source thresholds. However, this rule does have some implications for title V fees, which the EPA is addressing in this final rule.
      Finally, the fossil fuel-fired EGUs covered in this rule are or will be potentially impacted by several other recently finalized or proposed EPA rules, and such potential interactions with other EPA rules are discussed below.
B. Applicability of Tailoring Rule Thresholds under the PSD Program
      In our January 8, 2014 proposal, the EPA proposed to adopt regulatory language in 40 CFR part 60 that would ensure the promulgation of this NSPS would not undercut the application of rules that limit the application of the PSD permitting program requirements to only the largest sources of GHGs. An intervening decision of the United States Supreme Court has, to a large extent, resolved the legal issue that led the EPA to propose these Part 60 provisions. The Supreme Court has since clarified that the PSD program does not apply to smaller sources based on the amount of GHGs they emit. However, because the largest sources emitting GHGs remain subject to the PSD permitting requirements, the EPA has concluded that it remains appropriate to adopt the proposed regulatory provisions in 40 CFR part 60 in this rule. We discuss our reasons for this action in detail below.
       Under the PSD program in part C of title I of the CAA, in areas that are classified as attainment or unclassifiable for NAAQS pollutants, a new or modified source that emits any air pollutant subject to regulation at or above specified thresholds is required to obtain a preconstruction permit. This permit assures that the source meets specific requirements, including application of BACT to each pollutant subject to regulation under the CAA. Many states (and local districts) are authorized by the EPA to administer the PSD program and to issue PSD permits. If a state is not authorized, then the EPA issues the PSD permits for facilities in that state.
      To identify the pollutants subject to the PSD permitting program, EPA regulations contain a definition of the term "regulated NSR pollutant." 40 CFR 52.21(b)(50); 40 CFR 51.166(b)(49). This definition contains four subparts, which cover pollutants regulated under various parts of the CAA. The second subpart covers pollutants regulated under section 111 of the CAA. The fourth subpart is a catch-all provision that applies to "[a]ny pollutant that is otherwise subjection to regulation under the Act."
      This definition and the associated PSD permitting requirements applied to GHGs for the first time on January 2, 2011, by virtue of EPA's regulation of GHG emissions from motor vehicles, which first took effect on that same date. 75 FR 17004 (Apr. 2, 2010). As such, GHGs became subject to regulation under the CAA and the fourth subpart of the "regulated NSR pollutant" definition became applicable to GHGs.
      On June 3, 2010, the EPA issued a final rule, known as the Tailoring Rule, which phased in permitting requirements for GHG emissions from stationary sources under the CAA PSD and title V permitting programs (75 FR 31514). Under its understanding of the CAA at the time, the EPA believed the Tailoring Rule was necessary to avoid a sudden and unmanageable increase in the number of sources that would be required to obtain PSD and title V permits under the CAA because the sources emitted GHGs emissions over applicable major source and major modification thresholds. In Step 1 of the Tailoring Rule, which began on January 2, 2011, the EPA limited application of PSD or title V requirements to sources of GHG emissions only if the sources were subject to PSD or title V "anyway" due to their emissions of non-GHG pollutants. These sources are referred to as "anyway sources." In Step 2 of the Tailoring Rule, which began on July 1, 2011, the EPA applied the PSD and title V permitting requirements under the CAA to sources that were classified as major, and, thus, required to obtain a permit, based solely on their potential GHG emissions and to modifications of otherwise major sources that required a PSD permit because they increased only GHG emissions above applicable levels in the EPA regulations.
      In the PSD program, the EPA implemented the steps of the Tailoring Rule by adopting a definition of the term "subject to regulation." The limitations in Step 1 of the Tailoring Rule are reflected in 40 CFR 52.21(b)(49)(iv) and 40 CFR 51.166(b)(48)(iv). With respect to "anyway sources" covered by PSD during Step 1, this provision established that greenhouse gases would not be subject to PSD requirements unless the source emitted GHGs in the amount of 75,000 tons per year (tpy) of carbon dioxide equivalent (CO2e) or more. The primary practical effect of this paragraph is that the PSD BACT requirement does not apply to GHG emissions from an "anyway source" unless the source emits GHGs at or above this threshold. The Tailoring Rule Step 2 limitations are reflected in 40 CFR 52.21(b)(49)(v) and 51.166(b)(48)(v). These provisions contain thresholds that, when applied through the definition of "regulated NSR pollutant," function to limit the scope of the terms "major stationary source" and "major modification" that determine whether a source is required to obtain a PSD permit. See e.g. 40 CFR 51.166(a)(7)(i) and (iii); 40 CFR 51.166(b)(1); 40 CFR 51.166(b)(2).
      This structure of the EPA's PSD regulations created questions regarding the extent to which the limitations in the Tailoring Rule would continue to apply to GHGs once they became regulated, through this final rule, under section 111 of the CAA. 79 FR at 1487-1488. As discussed above, the definition of "regulated NSR pollutant" in the PSD regulations contains a separate PSD trigger for air pollutants regulated under the NSPS, 40 CFR 51.166(b)(49)(ii) (the "NSPS trigger provision"). Thus, when GHGs become subject to a standard promulgated under CAA section 111 for the first time under this rule, PSD requirements would presumably apply for GHGs on an additional basis besides through the regulation of GHGs from motor vehicles. However, the Tailoring Rule, on the face of its regulatory provisions, incorporated the revised thresholds it promulgated into only the fourth subpart of the PSD definition of regulated NSR pollutant ("[a]ny pollutant that otherwise is subject to regulation under the Act"). The regulatory text does not clearly incorporate the thresholds into the NSPS trigger provision in the second subpart ("[a]ny pollutant that is subject to any standard promulgated under section 111 of the Act"). For this reason, a question arose as to whether the Tailoring Rule limitations would continue to apply to the PSD requirements after they are independently triggered for GHGs by the NSPS that the EPA is now promulgating. Stakeholders questioned whether the EPA must revise its PSD regulations  - - and, by the same token, whether states must revise their SIPs  - - to assure that the Tailoring Rule thresholds will continue to apply to sources potentially subject to PSD under the CAA based on GHG emissions.
     In the January 8, 2014 proposed rule, the EPA explained that the agency had included an interpretation in the Tailoring Rule preamble, which means that the Tailoring Rule thresholds continue to apply if and when the EPA promulgates requirements under CAA section 111. 79 FR at 1488 (citing 75 FR 31582). Nevertheless, to ensure there would be no uncertainty as to this issue, the EPA proposed to adopt explicit language in sections 60.46Da(j), 60.4315(b), and 60.5515 of the agency's regulations. The language makes clear that the thresholds for GHGs in the EPA's PSD definition of "subject to regulation" apply through the second subpart of the definition of "regulated NSR pollutant" to GHGs regulated under subparts Da, KKKK, and TTTT of part 60.
     The EPA received comments supporting the adoption of this proposed language, but several commenters also expressed concern that adding this language to part 60 alone would not be sufficient. Several commenters urged EPA to instead revise the PSD regulations in parts 51 and 52. In addition, commenters expressed concern that further steps were needed to amend the SIPs before there would be certainty that the Tailoring Rule limitations continued to apply after the adoption of GHG standards under CAA section 111 in this final rule.
     On June 23, 2014, the United States Supreme Court, in Utility Air Regulatory Group v. Environmental Protection Agency, issued a decision addressing the application of PSD permitting requirements to GHG emissions. The Supreme Court held that the EPA may not treat GHGs as an air pollutant for purposes of determining whether a source is a major source (or modification thereof) for the purpose of PSD applicability. The Court also said that the EPA could continue to require that PSD permits, otherwise required based on emissions of pollutants other than GHGs, contain limitations on GHG emissions based on the application of BACT. The Supreme Court decision effectively upheld PSD permitting requirements for GHG emissions under Step 1 of the Tailoring Rule for "anyway sources" and invalidated application of PSD permitting requirements to Step 2 sources based on GHG emissions. The Court also recognized that, although EPA had not yet done so, it could "establish an appropriate de minimis threshold below which BACT is not required for a source's greenhouse gas emissions." 134 S. Ct. at 2449.
     In accordance with the Supreme Court decision, on April 10, 2015, the U.S. Court of Appeals for the District of Columbia Circuit (the D.C. Circuit) issued an amended judgment vacating the regulations that implemented Step 2 of the Tailoring Rule, but not the regulations that implement Step 1 of the Tailoring Rule. The court specifically vacated sections 51.166(b)(48)(v) and 52.21(b)(49)(v) of the EPA's regulations, but did not vacate sections 51.166(b)(48)(iv) or 52.21(b)(48)(iv). The court also directed the EPA to consider whether any further revisions to its regulations are appropriate in light of UARG v. EPA, and, if so, to undertake such revisions.
     The practical effect of the Supreme Court's clarification of the reach of the CAA is that it eliminates the need for Step 2 of the Tailoring Rule and subsequent steps of the GHG permitting phase in that EPA had planned to consider under the Tailoring Rule. This also eliminates the possibility that the promulgation of GHG standards under section 111 could result in additional sources becoming subject to PSD based solely on GHGs, notwithstanding the limitations the EPA adopted in the Tailoring Rule. However, for an interim period, the EPA and the states will need to continue applying parts of the PSD definition of "subject to regulation" to ensure that sources obtain PSD permits meeting the requirements of the CAA.
     The CAA continues to require that PSD permits issued to "anyway sources" satisfy the BACT requirement for GHGs. Based on the language that remains applicable under sections 51.166(b)(48)(iv) and 52.21(b)(49)(iv), the EPA and states may continue to limit the application of BACT to GHG emissions in those circumstances where a source emits GHGs in the amount of at least 75,000 tpy on a CO2e basis. The EPA's intention is for this to serve as an interim approach while the EPA moves forward to propose a GHG Significant Emission Rate (SER) that would establish a de minimis threshold level for permitting GHG emissions under PSD. Under this forthcoming SER rule, the EPA intends to propose restructuring the GHG provisions in its PSD regulations so that the de minimis threshold for GHGs will not reside within the definition of "subject to regulation." This restructuring will be designed to make the PSD regulatory provisions on GHGs universally applicable, without regard to the particular subparts of the definition of "regulated NSR pollutant" that may cover GHGs. Upon promulgation of the SER rule, it will then provide a framework that states may use when updating their SIPs consistent with the Supreme Court decision.
	While the GHG SER rulemaking is pending, the EPA and approved state, local, and tribal permitting authorities will still need to implement the BACT requirement for GHGs. In order to enable permitting authorities to continue applying the 75,000 tpy CO2e threshold to determine whether BACT applies to GHG emissions from an "anyway source" after GHGs are subject to regulation under CAA section 111, the EPA has concluded that it continues to be appropriate to adopt the proposed language in sections 60.46Da(j), 60.4315(b), and 60.5515.
      The EPA has evaluated these provisions in light of the Supreme Court decision and the comments received on the question of whether this CAA section 111 standard will undermine the application of the Tailoring Rule limitations. While most of the Tailoring Rule limitations are no longer needed to avoid triggering the requirement to obtain a PSD permit based on GHGs alone, the limitation in sections 51.166(b)(48)(iv) and 52.21(b)(49)(iv) will remain important to provide an interim applicability level for the GHG BACT requirement in "anyway source" PSD permits. Thus, there continues to be a need to ensure that the regulation of GHGs under CAA section 111 does not make this BACT applicability level for anyway sources effectively inoperable. The language the EPA proposed for sections 60.46Da(j), 60.4315(b), and 60.5515 will continue to be effective at avoiding this result after the judicial actions described above and the adoption of this final rule. The provisions in part 60 reference sections 51.166(b)(48) and 52.21(b)(49) of the EPA's regulations. However, the courts have now vacated sections 51.166(b)(48)(v) and 52.21(b)(49)(v), and the EPA will take steps soon to eliminate these subparts from the CFR. As a result of these steps, the language in 60.46Da(j), 60.4315(b), and 60.5515 will not incorporate the vacated parts of sections 51.166(b)(48) and 52.21(b)(49), but these provisions in part 60 will continue to apply to those subparts of the PSD rules that are needed on an interim basis to limit application of BACT to GHGs only when emitted by an anyway source in amounts of 75,000 tpy CO2e or more. Thus, in this final rule, the EPA is adopting the proposed text of sections 60.46Da(j), 60.4315(b), and 60.5515 without change.
      As to the concern expressed by some commenters that revisions to part 60 alone are not sufficient, the GHG SER rulemaking described above will include proposed revisions to the PSD regulations in parts 51 and 52 that should ultimately address this concern. The EPA acknowledges that the commenters concern will not be fully addressed for an interim period of time, but (for the reasons discussed above) the part 60 provisions adopted in this rule are sufficient to make explicit that the 75,000 tpy CO2e BACT applicability level for GHGs will apply to GHGs that are subject to regulation under the CAA section 111 standards adopted in this rule.
      Rather than adopting a temporary patch in its PSD regulations in this rule to address the implications for PSD of regulating GHGs under CAA section 111, the EPA believes it will be most efficient for the EPA and the states if the EPA completes a comprehensive PSD rule that will address all the implications of the Supreme Court decision. The revisions the EPA will consider based on the Supreme Court decision will inherently address the commenters concerns about the definition of the "subject to regulation" and the proposed part 60 provisions. To the extent this PSD rule is not complete before the EPA proposes additional CAA section 111 standards for GHGs, the EPA will need to consider adding provisions like sections 60.46Da(j), 60.4315(b), and 60.5515 to other subparts of part 60. As of this time, the EPA has not proposed GHG standards for other source categories under CAA section 111. To the extent needed, this approach of adding provisions to a few subparts in part 60 would be less burdensome to states and more efficient than revising section 51.166 at this time solely to address the implications of regulating GHGs under CAA section 111.
      The EPA understands that many commenters expressed concerned that PSD SIPs would also have to be amended to address the implications of regulating GHGs under CAA section 111. However, the language in 60.46Da(j), 60.4315(b), and 60.5515 is designed to avoid the need for states to make revisions to the PSD regulations in their SIPs at this time. The EPA has previously observed that the form of each pollutant regulated under the PSD program is derived from the form of the pollutant described in regulations, such as an NSPS, that make the pollutant regulated under the CAA. 56 FR 24468, 24470 (May 30, 1991); 61 FR 9905, 9912-18 (Mar. 12, 1996); 75 FR at 31522.
      Moreover, it is more likely that states would need to consider a SIP revision if the EPA were to revise section 51.166 in this rule. Revisions to 51.166 can trigger requirements for states to revise their PSD program provisions under section 51.166(a)(6).
      Given the process required in states to review their SIPs and submit them to the EPA for approval, it is most efficient for all concerned when the EPA is able consolidate its revisions to 51.166. The EPA, thus, believes it will be less work for states if we issue a comprehensive set of rules addressing regulation of GHGs under the PSD program after the Supreme Court decision.
      In comments on the proposed rules, states generally did not express concern that the proposed revisions to part 60 were insufficient to avoid the need for SIP revisions. In our proposal, we addressed any state with an approved PSD SIP program that applies to GHGs which believed that this final rule would require the state to revise its SIP so that the Tailoring Rule thresholds continue to apply. First, the EPA encouraged any state that considered such revisions necessary to make them as soon as possible. Second, if the state could do so promptly, the EPA said it would assess whether to proceed with a separate rulemaking action to narrow its approval of that state's SIP so as to assure that, for federal purposes, the Tailoring Rule thresholds will continue to apply as of the effective date of the final NSPS rule. 79 FR 1487. The EPA did not receive any comments or other feedback from states requesting that the EPA narrow their program to ensure the Tailoring Rule thresholds continue to apply after promulgating this rule. We do not believe such action will be necessary in any state after the Supreme Court decision and our action in this rule to adopt the proposed part 60 provisions in this final rule for purposes of ensuring the Step 1 BACT applicability level for GHGs continues to apply on an interim basis.
C.  Implications for BACT Determinations under PSD
      New major stationary sources and major modifications at existing major stationary sources are required by the CAA to, among other things, obtain a permit under the PSD program before commencing construction. The emission thresholds that define PSD applicability can be found in 40 CFR 51 and 52 as discussed briefly in the preceding section.
      Sources that are subject to PSD must obtain a preconstruction permit that contains emission limitations based on application of BACT for each regulated NSR pollutant. The BACT requirement is set forth in section 165(a)(4) of the CAA, and in EPA regulations under 40 CFR parts 51 and 52. These provisions require that BACT determinations be made on a case-by-case basis. CAA section 169(3) defines BACT as:
      an emissions limitation (including a visible emission standard) based on the maximum degree of reduction for each pollutant subject to regulation under the Clean Air Act which would be emitted from any proposed major stationary source or major modification which the Administrator, on a case-by-case basis, taking into account energy, environmental, and economic impacts and other costs, determines is achievable for such facility through application of production processes and available methods, systems, and techniques, including fuel cleaning, clean fuels, or treatment or innovative fuel combustion techniques for control of each such pollutant....

Furthermore, this definition in the CAA specifies that

      "[i]n no event shall application of [BACT] result in emissions of any pollutants which will exceed the emissions allowed by any applicable standard established pursuant to section 111 or 112 of the Act."

This condition of CAA section 169(3) has historically been interpreted to mean that BACT cannot be less stringent than any applicable standard of performance under the NSPS. See, e.g., U.S. EPA, PSD and Title V Permitting Guidance for Greenhouse Gases, p. 20-21 (March 2011) ("GHG Permitting Guidance"). Thus, upon completion of an NSPS, the NSPS establishes a "BACT Floor" for PSD permits that are issued to affected facilities covered by the NSPS.
      BACT is a case-by-case review that considers a number of factors. These factors include the availability, technical feasibility, control effectiveness, and the economic, environmental and energy impacts of the control option. See GHG Permitting Guidance at 17-46. The fact that a minimum control requirement is established by the EPA through an applicable NSPS (i.e. the BACT floor) does not bar a permitting agency from justifying a more stringent standard as BACT.
      In the proposed rule, the EPA discussed how this rule may relate to determination of BACT for new and existing EGUs that require PSD permits. Under this NSPS, an affected facility is a new EGU or a modified or reconstructed EGU. The new source NSPS requirements apply, in general, to any stationary source that adds a new EGU that is an affected facility under this NSPS. This could, for example, include both a new, greenfield EGU facility or an existing facility that wants to add a new EGU in order to add or replace capacity. While this latter scenario is considered a "new affected facility" under the NSPS, it may also be considered a "modification" of an existing stationary source under PSD. Thus, the new source NSPS requirements could apply to a modification, as that term is defined under PSD.
      In addition, this NSPS will apply to modified or reconstructed sources as those terms are defined under part 60. It is important to recognize that a physical change that triggers the NSPS modification or reconstruction requirements does not necessarily subject the source to PSD requirements, and vice versa. In general, in order to trigger the NSPS modification or reconstruction requirements, a physical change must increase the maximum potential hourly emission rate of the pollutant (to be an NSPS modification) or the fixed capital cost of the change must exceed 50 percent of the fixed capital cost of a comparable entirely new facility (to be an NSPS reconstruction). See 40 CFR 60.2, 60.14, 60.15. Under the PSD program, however, a physical change (or change in the method of operation) must result in an increase in annual emissions of the pollutant by the specified emission threshold in order to be subject to PSD requirements. This emission calculation considers the unit's past annual emission and its projected annual emissions. See, e.g., 40 CFR 52.21(a)(2)(iv)(C). In addition, the PSD emissions test for a modification allows the existing source to consider qualifying emission reductions and increases at the source within a contemporaneous period to "net out" of, or avoid, triggering PSD review. Thus, this NSPS could establish a BACT floor for sources that are modifying an existing EGU and their emissions make them subject to PSD.
      In the preamble to the proposed rule, the EPA discussed whether a standard of performance for the new source NSPS, specifically the BSER for solid fuel-fired EGUs that is based on partial CCS, could become the BACT floor when permitting a modified or reconstructed EGUs or non-EGU sources. As noted above, BACT is a case-specific review by a permitting agency. In evaluating BACT, the permitting authority should consider all available control technologies that have the potential for practical application to the facility or emission unit under evaluation. This review must include any technologies that are part of an applicable NSPS for the specific type of source and would therefore establish the minimum level of stringency for the BACT.
      Some commenters expressed concern that, if the EPA finalizes a BSER for utility boilers and IGCC units that is based on partial CCS, it would establish a BACT Floor for new EGUs that would be inconsistent with prior BACT determinations for EGUs in both permits issued by EPA Regions and permits issued by state agencies on which EPA has commented. Many of these comments were more directed at the development and deployment of CCS (i.e., the commenter did not believe CCS should be the basis for BSER) rather than examining whether an NSPS should establish the BACT floor for applicable sources, which is a natural consequence of setting an NSPS under the terms of the CAA. We respond to these comments in other sections of this preamble that support the selection of partial CCS as the basis for the BSER for fossil fuel-fired electric utility steam generating units.
      With regard to the commenters who stated that a BSER for EGUs that is based on partial CCS would be inconsistent with BACT determinations in previous GHG PSD permits, it is important to recognize that a BACT determination is a case-by-case analysis and that technological capabilities and costs evolve over time. In addition, to date the EPA has not issued a PSD permit with GHG BACT for a source that would be an affected facility requiring partial CCS under this NSPS (i.e., a fossil fuel-fired steam generating unit), so one cannot determine whether the EPA  -  as a PSD permitting authority  -  has been either consistent or inconsistent with setting a BSER of partial CCS in this NSPS. Although some permitting authorities may have determined that CCS is not technologically feasible or economically achievable for a gas-fired EGU, because of the case-by-case nature of the analysis, it does not automatically follow that the same conclusion is appropriate for a solid fuel-fired EGU. Furthermore, PSD permitting requirements first applied to greenhouse gases in January 2011 and more information about GHG control technology has been gained in this four-and-a-half year period.
      Additionally, if a state was processing a permit application for a solid fuel-fired EGU and CCS was not proposed as BACT (or not even considered as a possible control for BACT), the EPA is not necessarily required to comment negatively on the draft permit, or to otherwise request or require that the state agency amend the BACT to include CCS. For state agencies that have their own approved state implementation plan, the state has primacy over their permitting actions and discretion to interpret their approved rules and apply the applicable federal and state regulatory requirements that are in place at the time for the facility in question. The EPA's role is to provide oversight to ensure that the state operates their PSD program in accordance with the CAA and applicable rules. Furthermore, if the EPA does not adversely comment on a certain permit or BACT determination, it does not necessarily imply EPA endorsement of the proposed permit or determination.
      Some commenters also felt that the determination of partial CCS as BSER is inconsistent with the agency's position on CCS in the EPA's GHG Permitting Guidance, which they say supports the notion that additional work is required before CCS can be integrated at full-scale electric utility applications. It is important to recognize that the EPA's permitting guidance is guidance -- it does not contain any final determination of BACT for any source. Furthermore, we disagree with the commenters' characterization of the content of the GHG Permitting Guidance. The guidance specifically states "[f]or the purposes of a BACT analysis for GHGs, EPA classifies CCS as an add-on pollution control technology that is "available" for facilities emitting CO2 in large amounts, including fossil fuel-fired power plants, and for industrial facilities with high-purity CO2 streams (e.g., hydrogen production, ammonia production, natural gas processing, ethanol production, ethylene oxide production, cement production, and iron and steel manufacturing). For these types of facilities, CCS should be listed in Step 1 of a top-down BACT analysis for GHGs." GHG Permitting Guidance at 32. As discussed elsewhere in the Guidance, technologies that should be listed in Step 1 are those that "have the potential for practical application to the emissions unit and regulated pollutant under evaluation." GHG Permitting Guidance at 24. The EPA continues to stand by its position on the availability of CCS in this context, as expressed in the GHG Permitting Guidance.
      The Guidance continues on to discuss case-specific factors and potential limitations with applying CCS, and it acknowledges that CCS may not be ultimately selected as BACT in "certain cases" based on technology feasibility and cost. GHG Permitting Guidance at 36, 43. While acknowledging these challenges when it was issued in March 2011, the Guidance clearly does not rule out the selection of CCS as BACT for any source category and it is forward looking. Nothing in the guidance is inconsistent with agency's present position that CCS is adequately demonstrated for the types of sources covered by this rule, as articulated elsewhere in this preamble.
      A commenter asserted that the GHG Permitting Guidance should be amended because it calls for consideration of CCS in BACT determinations even though the proposed NSPS required "partial CCS" as BSER for new boiler and IGCC EGUs. The guidance explains that "the purpose of Step 1 of the process is to cast a wide net and identify all control options with potential application to the emissions unit under review." GHG Permitting Guidance at 26.  The EPA agrees that the GHG Permitting Guidance only uses the term "CCS" and does not distinguish "partial CCS" from "full CCS." But considering the purpose of Step 1 of the process, we believe that the term "CCS", as it was used in the GHG Permitting Guidance, adequately describes the varying levels of CO2 capture. A BACT review should analyze all available technologies in order to adequately support the BACT determination, and may require evaluation of partial CCS, full CCS, and/or no CO2 capture. The specific facility type and CO2 capture conditions will dictate the level(s) of CO2 capture that are most appropriate to consider as "available" in a BACT review.
D. Implications for Title V Program
      Under the title V program, certain stationary sources, including "major sources" are required to obtain an operating permit. This permit includes all of the CAA requirements applicable to the source, including adequate monitoring, recordkeeping, and reporting requirements to assure sources' compliance. These permits are generally issued through EPA-approved State title V programs.
      In the January 8, 2014 proposal, the EPA discussed whether this rulemaking would impact the applicability of title V requirements to major sources of GHGs. 79 FR at 1489-90. The relevant issue for title V purposes was, in essence, whether promulgation of CAA section 111 requirements for GHGs would undermine the Tailoring Rule, which, as explained above, phased in permitting requirements for GHG emissions for stationary sources under the CAA PSD and title V permitting programs. Based on the EPA's understanding of the CAA at that time, the proposal discussed this issue in the context of the regulatory and statutory definitions of "major source," focusing on revisions that had been made in the Tailoring Rule to the definitions in the title V regulations of "major source" and "subject to regulation." 79 FR at 1489-90 (quoting 75 FR 31,583). Under the title V regulations, as revised by the Tailoring Rule, "major source" is defined to include, in relevant part, "a major stationary source ... that directly emits, or has the potential to emit, 100 tpy or more of any air pollutant subject to regulation." The proposal further explained that the GHG threshold that had been established in the Tailoring Rule had been incorporated into the definition of "subject to regulation" under 40 CFR 70.2 and 71.2, such that those definitions specify "`that GHGs are not subject to regulation for purposes of defining a major source, unless as of July 1, 2011, the emissions of GHGs are from a source emitting or having the potential to emit 100,000 tpy of GHGs on a CO2e basis.'"  Id. (quoting 75 FR 31,583). The proposal thus concluded that the title V definition of "major source," as revised by the Tailoring Rule, did not on its face distinguish among types of regulatory triggers for title V. It further noted that the title V program had already been triggered for GHGs, and thus concluded that the promulgation of CAA section 111 requirements would not further impact title V applicability requirements for major sources of GHGs. 79 FR at 1489-90.
      As noted elsewhere in this section, after the proposal for this rulemaking was published, the United States Supreme Court issued its opinion in UARG v EPA, 134 S.Ct. 2427 (June 23, 2014), and in accordance with that decision, the D.C. Circuit subsequently issued an amended judgment in Coalition for Responsible Regulation, Inc. v. Environmental Protection Agency, Nos. 09-1322, 10-073, 10-1092 and 10-1167 (D.C. Cir., April 10, 2015). Those decisions support the same overall conclusion as the EPA discussed in the proposal, though for different reasons.
      With respect to title V, the Supreme Court said in UARG v EPA that EPA may not treat GHGs as an air pollutant for purposes of determining whether a source is a major source required to obtain a title V operating permit. In accordance with that decision, the D.C. Circuit's amended judgment in Coalition for Responsible Regulation, Inc. v. Environmental Protection Agency, vacated the title V regulations under review in that case to the extent that they require a stationary source to obtain a title V permit solely because the source emits or has the potential to emit GHGs above the applicable major source thresholds. The D.C. Circuit also directed the EPA to consider whether any further revisions to its regulations are appropriate in light of UARG v. EPA, and, if so, to undertake to make such revisions. These court decisions make clear that promulgation of CAA section 111 requirements for GHGs will not result in EPA imposing a requirement that stationary sources obtain a title V permit solely because such sources emit or have the potential to emit GHGs above the applicable major source thresholds.
      To be clear, however, unless exempted by the Administrator through regulation under CAA section 502(a), any source, including an area source (a "non-major source"), subject to an NSPS is required to apply for, and operate pursuant to, a title V permit that assures compliance with all applicable CAA requirements for the source, including any GHG-related applicable requirements. This aspect of the title V program is not affected by UARG v. EPA, as the EPA does not read that decision to affect either the grounds other than those described above on which a title V permit may be required or the applicable requirements that must be addressed in title V permits. Consistent with the proposal, the EPA has concluded that this rule will not affect non-major sources and there is no need to consider whether to exempt non-major sources. Thus, sources that are subject to the CAA section 111 standards promulgated today are required to apply for, and operate pursuant to, a title V permit that assures compliance with all applicable CAA requirements, including any GHG-related applicable requirements.
E. Implications for Title V Fee Requirements for GHGs
   1. Why is the EPA revising Title V fee rules as part of this action?
	The January 8, 2014 notice of proposed rulemaking (79 FR 1430)(the "EGU GHG NSPS proposal" or "NSPS proposal") proposed the first section 111 standards to regulate GHGs at EGUs. That notice also included proposed revisions to the fee requirements of the 40 CFR part 70 and part 71 operating permit rules under Title V of the CAA to avoid inadvertent consequences for fees that would be triggered by the promulgation of the first CAA section 111 standard to regulate GHGs. If we do not revise the fee rules by the time of the promulgation of the NSPS standards for GHGs, then approved part 70 programs implemented by state, local and tribal permitting authorities that rely on the "presumptive minimum" approach and the part 71 program implemented by the EPA would be required to account for GHGs in emissions-based fee calculations at the same dollar per ton ($/ton) rate as other air pollutants. The EPA believes this would result in the collection of fees in excess of what is required to cover the reasonable costs of an operating permit program. See NSPS proposal at 1490.
	In response to these concerns, the EPA proposed regulatory changes to limit the fees collected based on GHG emissions and proposed two fee adjustment options to increase the fees collected based on the costs for permitting authorities to conduct certain review activities related to GHG emissions, while still providing sufficient funding for an operating permit program. Also, we proposed an option that would have provided for no fee adjustments to recover the costs of conducting review activities related to GHG emissions. Id. at 1490. The EPA did not propose any action related to state and local permitting authorities that do not use the presumptive minimum approach.
	Most commenters on the proposal, including state and local permitting authorities, were supportive of exempting GHGs from the emissions-based fee calculations of the permit rules, but support for the fee adjustment options was mixed, with state and local permitting authorities generally supporting either of the two fee adjustments, and other commenters generally supporting the option that provides for no fee adjustment.
   2. Background on the Fee Requirements of Title V
	In the NSPS proposal, the EPA explained the statutory and regulatory background related to the requirement that permitting authorities collect fees from the owner or operator of title V sources that are sufficient to cover the costs of the operating permit program. CAA section 502(b)(3)(A) requires an operating permit program to include a requirement that sources "pay an annual fee, or the equivalent over some other period, sufficient to cover all reasonable (direct and indirect) costs required to develop and administer the permit program." See also 40 CFR 70.9(a). CAA section 502(b)(3)(B)(i) requires that, in order to have an approvable operating permit program, the permitting authority must show "the program will result in the collection, in the aggregate, from all sources [required to get an operating permit], of an amount not less than $25 per ton of each regulated pollutant [adjusted annually for changes in the consumer price index], or such other amount as the Administrator may determine adequately reflects the reasonable costs of the permit program." See also 40 CFR 70.9(b)(2). This has been generally referred to as the "presumptive minimum" approach. If a permitting authority does not wish to use the presumptive minimum approach, it may demonstrate "that collecting an amount less than the [presumptive minimum amount] will" result in the collection of funds sufficient to cover the costs of the program. CAA section 503(b)(3)(B)(iv); see also 40 CFR 70.9(b)(5). This has been generally referred to as the "detailed accounting" approach. CAA section 502(b)(3)(B)(ii) sets forth a definition of "regulated pollutant" for purposes of calculating the presumptive minimum that includes each pollutant regulated under section 111 of the CAA. See also 40 CFR 70.2.
   3.     What fee rules did we propose to revise?
      In the NSPS proposal, to exempt GHGs from emissions-based fee calculations, we proposed to exempt GHGs from the definition of "regulated pollutant" for purposes of operating permit fee calculations ("the GHG exemption"). The EPA then proposed two alternative ways to account for the costs of addressing GHGs in operating permits through a cost adjustment. First, we proposed a modest additional cost for each GHG-related activity of certain types that a permitting authority would process ("the GHG adjustment option 1"). Alternatively, we proposed a modest additional increase in the per ton rate used in the presumptive minimum calculation for all non-GHG fee pollutants ("the GHG adjustment option 2"). The EPA also solicited comment on an option that would provide no additional cost adjustment to account for GHGs ("the GHG adjustment option 3"). All of the GHG adjustment options are based on the assumption that the GHG exemption is finalized. See NSPS Proposal at 1493-1495.
      The EPA additionally proposed two clarifications. The first was regulatory text in 40 CFR part 60, subparts Da, KKKK and TTTT, to clarify that GHGs, as opposed to CO2, is the regulated pollutant for fee purposes ("the fee pollutant clarification"). Id. at 1505, 1506 and 1511. The second was a proposal to move the existing definition of "Greenhouse gases (GHGs)" within 40 CFR 70.2 and 71.2 to promote clarity in the regulations ("the GHG clarification"). Id. at 1490, 1517, 1518.
      For background purposes, below is a brief summary of each of the proposals.
a. The GHG exemption. To address the fee issues discussed in the NSPS proposal, the EPA proposed to exempt GHG emissions from the definition of "regulated pollutant (for presumptive fee calculation)" in 40 CFR 70.2 and the definition of "regulated pollutant (for fee calculation)" in 40 CFR 71.2. See NSPS preamble at 1493, 1495.
b. The GHG adjustment option 1. The first proposed "GHG adjustment" option (option 1) was to include an additional cost for each GHG-related activity of certain types that a permitting authority would process (an activity-based adjustment). The three activities identified for this option were "GHG completeness determination (for initial permit or for updated application)" at 43 hours of burden, "GHG evaluation for a modification or related permit action" at 7 hours of burden, and "GHG evaluation at permit renewal" at 10 hours of burden. See also 79 FR 1494, fn. 280 (providing a description of each of these activities).
      For part 70, the burden hours per activity would be multiplied by the cost of staff time (in $/hour) specific to the state, including wages, benefits, and overhead, to determine the cost of each activity. All the activities for a given period would be totaled to determine the total GHG adjustment for the state. See 79 FR at 1494.
      For part 71, we proposed a labor rate assumption of $52 per hour in 2011 dollars. Using that labor rate, we proposed to determine the GHG fee adjustment for each GHG permitting program activity to be a specific dollar amount for each activity ("set fees") that the source would pay for each activity performed. See 79 FR at 1495. The EPA proposed to revise 40 CFR 70.9(b)(2)(v) and 40 CFR 71.9(c)(8) to implement this option.
c. The GHG adjustment option 2. The second proposed GHG adjustment option (option 2) was to increase the dollar per ton ($/ton) rates used in the fee calculations for each non-GHG fee pollutant. The revised $/ton rates would be multiplied by the total tons of non-GHG fee pollutants actually emitted by any source to determine the applicable total fees. The EPA proposed to increase the $/ton rates by 7 percent. See NSPS proposal at 1494, 1495.
d. The GHG adjustment option 3. The EPA also solicited comment on not charging any fees related to GHGs (option 3). The basis for this proposed option was the observation that most sources that need to address GHGs in a permit would also emit non-GHG fee pollutants, and thus, the cost of permitting for any particular source may be accounted for adequately without charging any additional fees related to GHGs. Id. at 1494-1495.
e. The fee pollutant clarification. Another fee-related proposal was to add regulatory text to 40 CFR part 60, subparts Da, KKKK and TTTT, to clarify that the fee pollutant for operating permit purposes would be considered to be "GHGs," (as defined in 40 CFR 70.2 and 71.2), rather than solely CO2, which would be regulated under the section 111 standards and implemented through the EGU GHG NSPS. Id. at 1505, 1506, and 1511.
f. The GHG clarification. The EPA proposed to move the existing definition of "Greenhouse gases (GHGs)" within the definition of "Subject to regulation" in 40 CFR 70.2 and 71.2 to a separate definition within those sections to promote clarity in the regulations. Id. at 1490, 1517, 1518.
4. What action is the EPA finalizing?
	In this action, the EPA is finalizing the following elements as proposed: (1) the GHG exemption, (2) the GHG adjustment option 1, and (3) the fee pollutant clarification.
	Public commenters on the proposal stated both support and opposition to using the NSPS rulemaking action to revise the title V fee rules. Two commenters stated that proposing the title V fee revisions within the NSPS rulemaking would result in fewer commenters, particularly state and local permitting authorities, having knowledge of the changes to the fee rules and sufficient opportunity to comment on the changes because the NSPS proposal is limited to a single source category, and one stated that a separate proposal for the fee rules would provide a sufficient opportunity for public comment. The EPA believes it is appropriate to move forward with final action amending the title V fee regulations as part of this NSPS. As we explained in the preamble for the proposal and elsewhere in this final rule, the fee rules and the section 111 standards are interrelated because, if we do not revise the fee rules, promulgation of the final NSPS will trigger certain requirements related to title V fees for GHG emissions that the EPA believes will result in the collection of excessive fees in states that implement the presumptive minimum approach and in the part 71 program. Thus, it is important to finalize the revisions to the fee rules at the same time or prior to this NSPS, and it is within the EPA's discretion to address the NSPS and the fee rules at the same time as part of the same rulemaking action. In response to the commenters who were concerned that including the fee rule proposal as part of the NSPS proposal would result in the public not having sufficient public comment opportunities, the EPA believes sufficient public comment opportunities were provided on the fee rule changes because the proposal met all public participation requirements and we provided additional public outreach, including to state and local permitting authorities, which discussed the fee rule proposal. In addition to the publication of the proposed rulemaking in the Federal Register, the EPA held numerous hearings, reached out to state partners and the public, and developed numerous fact sheets and other information to support public comment on this rule. The EPA has complied with the applicable public participation requirements and executive orders. The proposal met all the requirements for public notice  -  it contained a clear and detailed explanation of how the part 70 and 71 rules would be affected by the promulgation of the CAA section 111 standard for EGUs and how the EPA proposed to revise the related regulatory provisions. We received many comments on the proposal to revise the fee rule for operating permits programs, and we are taking those comments into consideration in the finalization of the rulemaking action.
a. The GHG exemption.exemption. The EPA is taking final action to revise the definition of regulated pollutant (for presumptive fee calculation) in 40 CFR 70.2 and regulated pollutant (for fee calculation) in 40 CFR 71.2 to exempt GHG emissions. This regulatory amendment will have the effect of excluding GHG emissions from being subject to the statutory ($/ton) fee rate set for the presumptive minimum calculation requirement of part 70 and the fee calculation requirements of part 71. We received supportive comments from the majority of public commenters, including state and local permitting authorities and others, on revising the operating permit rules to exempt GHGs from the emission-based calculations that use the statutory fee rates. We are finalizing this portion of the proposal for the same reasons we explained in the proposal notice, including that leaving these regulations unchanged would have resulted in the collection of fee revenue far beyond the reasonable costs of an operating permit program. The EPA believes that these revisions (in conjunction with the GHG adjustment, see below) are consistent with the CAA requirements for fees pursuant to the authority of section 502(b)(3)(B)(i).
	Some members of the public opposed the proposed GHG exemption for reasons including that it may limit permitting authorities' ability to charge sufficient fees to cover the cost of GHG permitting if the state is barred from exceeding minimum requirements set by the EPA. Despite this adverse comment, the EPA believes it is appropriate to finalize the GHG exemption because we are not finalizing any requirements that would require states to charge any particular fees to any particular sources. The changes we are finalizing to part 70 concern the presumptive minimum approach, which sets a minimum fee target for states that have decided to follow the presumptive minimum approach. Neither the statute nor the final rule require any state following the presumptive minimum approach (or any other approach) to charge fees to sources using any particular method. Thus, the GHG exemption will not limit states' ability to structure their individual fee programs however they see fit in order to meet the requirement that they collect revenue sufficient to cover all reasonable costs of their permitting program. See CAA section 502(b)(3); 40 CFR 70.9(b)(3).
b. The GHG adjustment option 1. The EPA is finalizing GHG adjustment option 1 because we believe it will result in a system for the calculation of costs for part 70 and fees for part 71 that is most directly related to the costs of GHG permitting. The EPA has determined that some adjustment to cost and fee accounting is important because the recent addition of GHG emissions to the operating permitting program does add new burdens for permitting authorities. Although GHG adjustment option 3 (no GHG permitting fee adjustments) was supported by many industrial commenters, the EPA rejected it because it is in tension with the statutory requirement that permitting authorities collect sufficient fees to cover all the reasonable costs of permitting. See CAA section 502(b)(3)(A). Some state and local permitting authorities provided comments supporting option 1, while others supported option 2, and some supported either option, stating no preference. Also, a few state and local permitting authorities supported finalizing no adjustment and a few others asked for flexibility to set fee adjustments not proposed by EPA, but that they believed would be appropriate for their program.
      The EPA is finalizing option 1 instead of option 2 because the option 1 adjustments are based on the actual costs for permitting authorities to process specific actions that require GHG reviews. The option 2 approach, which would have added a 7 percent surcharge to the $/ton rate used in the fee-related calculations, may have been administratively easier to implement, but is tied to the emissions of non-GHG air pollutants, which are not directly related to the costs of GHG permitting.permitting.
	Consistent with CAA section 502(b)(3)(B)(i), the Administrator has determined that the final rule's approach of exempting GHG emissions from fee-related calculations and accounting for the GHG permitting costs through option 1 will result in fees that will cover the reasonable costs of the permitting programs.
	The EPA is revising the part 70 regulations through this final action, specifically 40 CFR 70.9(b)(2), to modify the presumptive minimum approach to add the activity-based cost of GHG permitting activities, outlined in the revised 40 CFR 70.9(b)(2)(v), to the emissions-based calculation of 40 CFR 70.9(b)(2)(i), which is being revised to now exclude GHG emissions. To determine the activity-based GHG adjustment under 40 CFR 70.9(b)(2)(v), the permitting authority will multiply the burden hours for each activity (set forth in the regulation) by the cost of staff time (in $ per hour), including wages, benefits, and overhead, as determined by the state, for the particular activities undertaken during the particular time period.
	States that implement the presumptive minimum approach will need to follow the final rule's option 1 approach. States that use the detailed accounting approach are not directly affected by this rulemaking, but they must ensure that their fee collection programs are sufficient to fully fund all reasonable costs of the operating permit program, including costs attributable to GHG-related permitting. The EPA suggests states that use the detailed accounting approach consider the 7 percent assumption for the costs of GHG permitting in any such analysis, consistent with the EPA analysis of options 1 and 2 in the proposal.
	Consistent with 40 CFR 70.4(i), a state that wishes to change its operating permit program as a result of this final rule must apprise the EPA. The EPA will review the materials submitted concerning the change and decide if a formal program revision process is needed and will inform the state of next steps. The communication apprising the EPA of any such changes should include at least a narrative description of the change and any other information that will assist the EPA in its assessment of the significance of the changes. Certain changes, such as switching from the presumptive minimum method to a detailed accounting fee demonstration method, will be considered substantial program revisions and be subject to the requirements of 40 CFR 70.4(i)(2).
	With respect to the part 71 program, in this final action the EPA is revising 40 CFR 71.9(c) to require each part 71 source to pay an annual fee which is the sum of the activity-based fee of 40 CFR 71.9(c)(8) and the emissions-based fee of 40 CFR 71.9(c)(1)-(4), which excludes GHG emissions. To determine the activity-based fee, the revised 40 CFR 71.9(c)(8) requires the source to pay a "set fee" for each listed activity that has been initiated since the fee was last paid. Under part 71, fees are typically paid at the time of initial application submittal, and thereafter, annually on the anniversary of the initial fee payment, or on any other dates that may be established in the permit. These set fees would not change until such time as we may revise our part 71 rule to change the set fees.
	The final rule implements the option 1 approach by listing three activities performed by permitting authorities that involve GHG reviews. The following describes the activities as described in our proposal and certain clarifications we are making in the final rule to ensure consistent implementation.
	The EPA is finalizing that the first listed activity under option 1 is "GHG completeness determination (for initial permit or updated application)." This activity must be counted for each new initial permit application, even for applications that do not include GHGs emissions or applicable requirements, since an important part of any completeness determination will be to determine that GHG emissions and applicable requirements have been properly addressed, as needed, in the application. The fee for this activity is a one-time charge that covers the initial application and any supplements or updates. The EPA believes that a single charge for a GHG completeness determination will be adequate to cover the reasonable costs for a permitting authority to review an initial application and any subsequent application updates related to initial permit issuance; thus, any updates to an initial application are included in a single "GHG completeness determination," rather than as a separate activity for which the source would be charged in addition to the completeness determination for the initial application. This is an important distinction because many sources submit multiple permit application updates, either voluntarily or as required by the permitting authority, during application review, many of which do not require a separate or comprehensive completeness determination.
	The EPA is finalizing regulatory text that would describe the second listed activity as "GHG evaluation for a permit modification or related permit action." The EPA had proposed that the second listed activity under option 1 would be "GHG evaluation for a modification or related permit action." For the final rule, we are clarifying that we are adding a cost for a "permit modification" rather than for a "modification." The term "modification" may be interpreted to refer to any change at a source, even a change that would not be required to be processed as a "permit modification," while "permit modification" refers to any revision to an operating permit that cannot be processed as an administrative permit amendment and thus requires a review by a permitting authority as either a significant or minor permit modification.