Chapter 9
Other Rules and Programs

Contents
9.1	General	2
9.2	EPA Creation of New Source Category TTTT for Rule	3
9.3	Including Modified or Reconstructed Units	10
Conditions That Constitute Modifications	16
9.4	Potential Impacts on Modified and Existing Sources from EPA's Proposal	17
9.5	BACT Determinations	22
9.6	Implications for GHG Applicability Thresholds Related to Permitting	33
9.7	Title V Permitting Fees	42


General
One commenter (10098) stated that EPA should not expand GHG NSPS to other non-EGU source categories. The commenter provided in depth discussion for each of the following reasons:
      -There is no legal obligation to do so (cited the refinery settlement agreement). 
      -Emissions from manufacturing sources are at least an order of magnitude lower than EGUs, which would alter the cost benefit and endangerment equations. 
      -Other source categories are impacted by a broader range of factors, such as industry economics, geography, federal and state incentives and transportation networks. 
      -Each manufacturing sector is comprised of unique business models with differing sizes, ownership structures, foreign competitors, profit margins, and customer bases. 
      -Many industries have already taken voluntary action to reduce GHG emissions. 
      -NSPS are an inefficient way to impose GHG emission reductions due to their one-size-fits-all structure and application. 
      -The development and deployment of CCS is inappropriate in other industrial sectors. 
      -Compliance costs that fail to account for trade exposure will shift production overseas and result job losses without reducing global GHG emissions.
      -The recent NSPS for petroleum refining will add significant compliance costs to oil and gas production, while reducing GHG as an ancillary benefit.
      -If EPA considers GHG NSPS for other sectors, it should first proceed with an ANPR to solicit views and comments from all impacted stakeholders.
This comment is beyond the scope of this rulemaking.
One commenter (9034) stated that the utility industry GHG NSPS sets an important precedent for a host of other source categories already regulated under the CAA's new source program including petroleum refineries; chemical manufacturing; petroleum and natural gas production, transmission, compression, and distribution; food processing; waste management; and production of metals such as aluminum, iron, and steel. The adverse economic impacts resulting from imposition of the Proposed Rule on the utility industry will be magnified if similarly-based GHG limits are applied across other industries.
 
This comment is also beyond the scope of this rulemaking.  Should EPA consider GHG standards for other stationary source sectors, it would only do so after robust notice and comment procedures.
One commenter (9196) stated that despite EPA's recognition that the CAA requires the agency to consider energy requirements in connection with proposed standards of performance, the consideration in this proposal is wholly inadequate and highly misleading and neglects to consider the impact of this proposed rule in the broader context of the numerous other EPA regulations already or soon to be placed on the energy sector.
EPA has carefully considered issues of impacts on energy in this rulemaking, as required by CAA section 111 (a)(1).  These considerations significantly influenced EPA's choice of a standard of performance for new NGCC sources.  See preamble V.O.3.  With respect to coal- burning steam electric generating sources, EPA views impacts on energy requirements to be minimal.  Few, if any, such sources are projected to be constructed, and  available data indicate that, even in the absence of this rule, existing and anticipated economic conditions will lead electricity generators to choose new generation technologies that would meet the proposed standard without installation of additional controls. See RIA chapter 4.
One commenter (10660) requested that EPA address a number of uncertainties raised by EPA's proposed rulemaking that currently are left unaddressed, unresolved, or inadequately supported. These include issues such as the applicability of the Tailoring Rule and fee calculations under Title V; applicability of the rule to simple cycle units; and the determination that carbon capture and storage (CCS) is the best system of emissions reduction (BSER) for coal-fired electric generating units (EGUs).
The applicability of the Tailoring Rule is addressed in section XII.B. of the preamble and section 9.6 of this response to comments document.   Title V fee calculations are addressed in section XII.D. of the preamble and section 9.7 of this response to comments document.  For natural gas-fired nominal peaking stationary combustion turbines, the EPA is finalizing the BSER as combustion of "clean fuels" and a corresponding heat input-based standard. This standard of performance will apply to the vast majority of simple cycle combustion turbines.  EPA's proposal was unambiguous that partial CCS was BSER for new coal-fired EGUs.  See, e.g. 79 FR at 1469 ("[w]e propose that implementation of partial capture CCS technology is the BSER for new fossil fuel-fired boilers and IGCC units because it fulfills the criteria established under CAA section 111").  Based on the same methodology used at proposal, EPA's final determination is that partial CCS and IGCC are BSER for new fossil-fuel fired EGUs.  
EPA Creation of New Source Category TTTT for Rule
Several commenters (7990, 8944, 8952, 9500, 9678, 9665, 9514, 10619, 4867; 9514; 9035; 9515, 4621: 9003) support promulgating requirements for GHG from new EGUs under a new subpart TTTT.
One commenter (9678) stated that EPA must establish separate standards for coal-fired and gas-fired sources subject to this rulemaking. However, the commenter supports structuring the rulemaking under a single subpart TTTT, so as not to constrain EPA's ability to provide flexibility to existing units under the upcoming rulemaking(s). As EPA notes in the preamble, there may be benefits to regulating new EGUs units under a single source category because it would facilitate future regulation of existing units under "a system-wide approach, such as emission rate averaging, that covers fossil-fuel fired steam generating units and combustion turbines." 
Two commenters (8952, 150; 8944) supported a new subpart TTTT because the applicability of subparts Da and KKKK are significantly different from the applicability of the proposed EGU CO2 NSPS. Examples of the differences cited by the commenter include 1) coverage under Subpart KKKK of mechanical drive turbines while the CO2 emission limits only apply to EGUs; and 2) Subpart KKKK has specific limits for modified and reconstructed units while the CO2 emissions apply only to new units. These differences in applicability could cause confusion in rule interpretation. Due to these and other substantive differences in the rule provisions, a separate NSPS standard is appropriate and recommended.
One commenter (9665) stated that the primary reason to establish a new subpart TTTT is the difference in applicability of GHG and "conventional" air pollutant emission standards. For example, subpart KKKK is applicable to gas turbines ranging in size from 10 MMBtu/h heat input (and larger) while the proposed GHG standards apply to gas turbines ranging from 250 MMBtu/h (and larger). Furthermore, subpart KKKK is applicable to all installed gas turbines regardless of whether they are installed in simple cycle or combined cycle units. Subpart KKKK also has separate categories for new, modified, and reconstructed gas turbines. In contrast, the proposed GHG standards apply only to combined cycle and simple cycle gas turbines above a certain capacity thresholds. The standards also apply to new units only. Based on the substantial differences in applicability and classification of affected sources, a separate subpart TTTT add clarity to the new GHG regulatory requirements, as well as more readily allow for different size classifications.
Two commenters (9514, 9500) support the creation of a new subpart TTTT. One commenter (9514) stated that they support the agency's decision to make separate BSER determinations for subcategories, including a subcategory for electric utility steam-generating units (which encompass IGCC facilities), and another subcategory for stationary combustion turbines.  The commenters (9514, 9500) stated that the CAA grants EPA discretion to create or not create subcategories that may include different classes, types, and sizes of sources. Categorizing sources by function is consistent with the legislative history of the CAA. The commenter (9514) also identifies existing NSPS and NESHAP rules where EPA has established a single category that encompasses different technologies. The commenter stated EPA should include all fossil fuel-fired power in the same category because they serve the same function, and doing so may simplify frameworks to secure cost-effective carbon reductions from existing units. The commenter stated that natural gas-fired plants now provide substantial quantities of baseload and intermediate load power and serve the same load-serving function as steam EGUs, and would thus logically fall within a single category. The commenter stated that subpart TTTT should not be limited to baseload and intermediate load plants, but should encompass all fossil fuel-fired power plants that form part of our electricity generating system. According to the commenter, utilities system operators make dispatch decisions for an entire fleet of power plants without regard to type of fuel. This allows utilities to dispatch the least expensive available generating resources. States and utilities may choose to consider compliance options for EPA's forthcoming 111(d) standards that follow similar principles. While EPA has not yet proposed emission guidelines under section 111(d), to the extent that those guidelines incorporate a system-based approach to carbon pollution reductions, a single category for fossil fuel-fired EGUs can simplify the implementation of compliance options that look to the whole fleet of existing power plants. EPA should consider this in determining whether to finalize a new category TTTT encompassing all fossil-fired power plants.
One commenter (9500) stated that not combining categories into a single TTTT could have negative consequences for achieving carbon pollution reductions under section 111(d) of the CAA. Commenters (4867; 9500) stated that EPA's decision to create a new subpart TTTT, or not, should have no effect on the substance of the proposed section 111(b) rule. Combining categories imposes no limitations on the agency's ability to choose the rule's stringency, define BSER that forms the basis of that stringency, or set different stringencies, based on different identified systems, for various subcategories of sources. If EPA combines categories Da and KKKK into new category TTTT, it should be able to readily identify the coal-fired plants previously in category Da and the gas-fired plants previously in category KKKK as separate subcategories, and still issue different standards for them just as it has proposed to do for small and large turbines. Combining existing source categories into new category TTTT is consistent with the explicit grant of authority to the agency in section 111(b)(1)(A) to revise the list of source categories. Combining source categories into new source category TTTT also does not appear to add any significant administrative burden or complexity. Creation of new category TTTT, therefore, does not require EPA to redefine Da and KKKK as subcategories of TTTT for all pollutants and performance standards, past and future. 
Two commenters (9500; 9514) stated that EPA's decision on whether to combine coal and gas-fired EGUs into a single new source category TTTT in this new source rulemaking thus could have implications for the design of existing source performance standards. Combining source categories has a large impact on the options available to EPA and states in future existing-source standards, facilitating averaging and trading across sources currently in different source categories. Analysis indicates that trading between sources is a very important determinant of the environmental and economic impact of the existing-source standards. Because the existing-source standards are likely to be much more environmentally and economically significant than the new-source standards, EPA should combine source categories to the extent it determines that would help reduce carbon pollution. Commenter 9514 stated that establishing an inclusive category in this rulemaking under section 111(b) could simplify the forthcoming 111(d) standards for existing power plants. Combining categories would simplify implementation of a system-based approach to achieving the emission reductions required under section 111(d), should EPA (in its forthcoming emission guidelines) or states (in their SIPs) choose to adopt such an approach. Establishing a single category for all fossil fuel-fired EGUs in the context of section 111(b) rule may simplify EPA's and states' efforts to achieve significant emission reductions from power plants pursuant to section 111(d).
One commenter (10619) stated that promulgating both source categories in a new Subpart TTTT provides advantages in administering NSPS for the following reasons:  
      -Enables a system-wide approach for emission guidelines; 
      -Facilitates revision, remand, and/or vacatur that may result from ongoing court cases; 
      -CO2 requirements for steam-generating boilers and combustion turbines are similar; and 
      -Inefficiencies are created by codifying requirements for GHG emissions from EGUs in separate subpart Da and subpart KKKK creates inefficiency if they are codified in these respective Subparts.
One commenter (9426) sees implementation advantages to a single subpart TTTT. The commenter recommends a new Subpart TTTT for new utility boilers and IGCC units and a new Subpart UUUU for new natural gas-fired stationary combustion turbines. EPA also must consider how imposing more stringent QA/QC criteria in Subpart TTTT would impact reporting under other NSPS and other programs, including the Acid Rain Program.
In this rule, the EPA is combining the steam generator and combustion turbine categories into a single category of fossil fuel-fired electricity generating units for purposes of promulgating standards of performance for GHG emissions. Combining the two categories is reasonable because they both provide the same product: electricity services. Moreover, combining them in this rule is consistent with our decision to combine them in the CAA section 111(d) rule for existing sources that accompanies this rule. In addition, many of the monitoring, reporting, and verification requirements are the same for both source categories, and, as discussed next, we are codifying all requirements in a single new subpart TTTT of the regulations; as a result, combining the two categories into a single category will reduce confusion. It should be noted that in this rule, we are not combining the two categories for purposes of standards of performance for other air pollutants.
Two commenters (9381; 9591) stated that although they prefer that EPA retain the use of subparts Da and KKKK, if EPA determines that the use of separate subparts would limit trading and other flexibility options available to states for subsequent regulation of existing units under 111(d), the commenter would support development of a new subpart (TTTT) that includes the proposed performance standards for new boilers and combustion turbines.
One commenter (9514) stated that the new category should reflect the current applicability definitions, that is, should include all fossil fuel-fired power plants with a capacity to generate more than 25 MW of net electrical output (or more than 219,000 MWh annually) and that either have been designed to supply to or actually supply any amount of electricity to the grid.
One commenter (9591) stated that applicability of the new subpart should include all fossil fuel-fired sources that supply electricity to the grid regardless of unit size. The commenter does not support the Subpart KKKK applicability exemption based on sales below 33% of potential output and believes that all stationary combustion turbines that sell power to the grid should be subject the GHG regulation. Yet, the commenter supports EPA's argument that units that sell more than 40% of its potential electric output to the grid should be subject to an emission rate standard (i.e., the larger, non- peaking turbines would have to demonstrate compliance with an emission rate standard). In contrast, smaller, peaking units can be subject to work practice standards and/or recordkeeping requirements.
One commenter (9515) stated that creating a new subpart for all greenhouse gas performance standards may strengthen the legal case for future emissions trading among different types of existing sources.
 In this rule, the EPA is combining the steam generator and combustion turbine categories into a single category of fossil fuel-fired electricity generating units for purposes of promulgating standards of performance for GHG emissions. Combining the two categories is reasonable because they both provide the same product: electricity services. Moreover, combining them in this rule is consistent with our decision to combine them in the CAA section 111(d) rule for existing sources that accompanies this rule. In addition, many of the monitoring, reporting, and verification requirements are the same for both source categories, and, as discussed next, we are codifying all requirements in a single new subpart TTTT of the regulations; as a result, combining the two categories into a single category will reduce confusion. It should be noted that in this rule, we are not combining the two categories for purposes of standards of performance for other air pollutants.
One commenter (9514) stated that if EPA finalizes a new category TTTT, EPA should in a future rulemaking reorganize its existing regulations to cover emissions of criteria pollutants under category TTTT as well. Section 111 requires EPA to review its performance standards for each source category at least every eight years and the current co-proposal would establish CO2 emissions in subpart TTTT, while leaving subparts Da and KKKK to cover other criteria pollutant. Not only would this introduce unnecessary confusion into the regulations, it would create a situation in which EPA would conduct its periodic review for these sources on different tracks depending upon the particular kind of pollutant at issue. To ensure that EPA undertakes its reviews for fossil fuel-fired EGUs in a manner that is both timely and coordinated, EPA should incorporate performance standards for criteria pollutants in subpart TTTT as well.
 In this rule, the EPA is combining the steam generator and combustion turbine categories into a single category of fossil fuel-fired electricity generating units for purposes of promulgating standards of performance for GHG emissions. Combining the two categories is reasonable because they both provide the same product: electricity services. Moreover, combining them in this rule is consistent with our decision to combine them in the CAA section 111(d) rule for existing sources that accompanies this rule. In addition, many of the monitoring, reporting, and verification requirements are the same for both source categories, and, as discussed next, we are codifying all requirements in a single new subpart TTTT of the regulations; as a result, combining the two categories into a single category will reduce confusion. It should be noted that in this rule, we are not combining the two categories for purposes of standards of performance for other air pollutants.
Several commenters (1200, 6870 8909, 8937-5262, 9042, 9194, 9381, 9407, 9426, 9592, 9396, 9593, 9649, 9666, 10095, 10097, 10100, 10240, 1039510952; 10466) stated that they oppose a new combined subpart TTTT and support retaining the current NSPS separate subparts (Da and KKKK).
One commenter (10100, 1200) stated that this approach will ensure consistency with EPA's longstanding approach of compiling all NSPS for a single source category into a separate subpart rather than creating a new subpart that combines source categories and only addresses certain standards, which would be confusing and inefficiently organized.
Several commenters (6870; 9194; 9396; 9592; 10240) stated that it is appropriate to distinguish between fossil fuel-fired steam electric generators and combustion turbine EGUs in the case of regulating GHGs. The commenters also do not believe it is appropriate to create a new subpart TTTT for GHG NSPS even if EPA established separate subcategories for fossil fuel-fired steam electric generators and gas-fired combustion turbine.
One commenter (9381) supports EPA's proposal to retain the current NSPS source categories provided that EPA determines that this structure would not prevent states from proposing compliance programs that allow averaging and trading between sources in Subparts Da and KKKK under future Section 111(d) regulation of existing sources.  This approach will ensure consistency with EPA's longstanding approach of compiling all NSPS for a single source category into a separate subpart rather than creating a new subpart that combines source categories and only addresses certain standards, which would be confusing and inefficiently organized.
Several commenters (9407, 10097,10952) stated that EPA has provided no specific information as to why a new subpart would be superior to the existing subpart configuration other than that combining the two existing subparts into one may offer additional flexibilities for future emission guidelines for existing sources such as emission averaging. But without specific explanation as to why one subpart would be superior to the existing two and whether there might be disadvantageous associated with one subpart, EPA should not combine the existing two subparts that include two fundamentally different means of electric generation into one subpart at this time.
One commenter (9666) stated that standards of performance must be "achievable" by each type of source in a source category and if the purpose of EPA's "co-proposal" to establish a Subpart TTTT is to set a single standard for existing EGUs under future section 111(d) emission guidelines, then such a proposal is contrary to law. The commenter stated that EPA must distinguish among different classes, types, and sizes of facilities in setting new source standards of performance, and for that reason, if EPA chooses to proceed with this rulemaking, it should promulgate standards for distinct types of sources under distinct subparts. In the past, EPA has always established separate source categories for EGUs that utilize different fuel types. EPA has not sufficiently established why regulating CO2 emissions from new EGUs would warrant a departure from this long-established practice.
One commenter (10095) stated that in their December 2011 Response to Comments on Proposed NSPS Amendments to Subpart D and Da, EPA further recognized the fundamental difference between coal steam boilers and natural gas steam boilers: "Neither natural gas nor distillate oil is typically used in new baseload steam generating units (e.g., boilers with steam turbines). Basing the standards on either of these fuels would result in standards that are neither technically or economically achievable for a coal-fired EGUs." In the final rule, EPA chose to keep these units in the same category only because it concurrently decided to set a standard achievable for all affected sources. 
One commenter (8909) stated that the separate performance standards allow more regulatory flexibility to recognize differences between coal-fired and natural gas-fired EGUs. Both fuel types play a significant role in the U.S. energy mix but have different emissions profiles and are generally utilized in different types of EGUs. They also respond differently to emissions control technologies. This approach better allows EPA to craft standards of performance tailored to the unique characteristics of each fuel and generator type.
One commenter (9194) stated that, under a single subpart TTTT, the finding that the CO2 emission rate of a natural gas combined cycle unit represents BSER for coal-fired EGUs is not consistent with the historical practice of regulating fossil fuel-fired steam electric generators and combustion turbine EGUs under separate subparts. 
One commenter (9593) stated that the current source categories will ensure consistency with EPA's longstanding approach of compiling all NSPS for a single source category into its own separate subpart rather than creating a new subpart that combines source categories and only addresses certain standards, which would be confusing and inefficient.
One commenter (9381) stated that a single-category approach could stifle investment in new or modified coal-fired electricity generation utilizing CCS and would provide no incentive for the power industry to invest in new CCS technology that many view as critical to the reduction of global atmospheric concentrations of CO2 necessary to curb the effects of climate change.  Further, a single-category approach would effectively ban new coal-fired generation in the absence of commercialized CCS, creating an incentive to continue the operation of older, less efficient coal-fired EGUs rather than construction of new, more efficient units.
Commenter (9426; 9649) stated that they do not believe that a new subpart TTTT can be used to establish system-wide emission guidelines under section 111(d) for all fossil units. We do not understand how having Subpart TTTT would provide any flexibility for implementation of Section 111(d) emissions guidelines, since existing sources have been excluded from Subpart TTTT and since EPA has acknowledged that there are two distinct subcategories that would be regulated under Subpart TTTT. Because the EPA's intentions are not clear, the EPA must provide additional analysis on how it believes Subpart TTTT might provide such flexibility. 

One commenter (9042) stated that 40 CFR Part 60 contains 96 subparts. While not all of these source categories have GHG emissions, the number of subparts required if EPA decides to create new subparts for all new GHG regulation could be extensive. The commenter is concerned that the creation of new subparts to regulate GHG emissions from subcategories of existing categories could make Part 60 confusing and unwieldy.

One commenter (9649) stated that while choosing how to structure the regulations is not a listing decision, creating a new subpart TTTT that houses all the different GHG standards for various source categories would blur the distinctions between categories made in the listing decisions. The listing decision distinguished source categories based on the method by which electricity is generated, that is, between steam-generated boilers and combustion turbines, but a separate GHG subpart mirrors the original single emission standard as well as the latest applicability conditions, both of which distinguish EGUs by the type of load they serve.
In this rule, the EPA is combining the steam generator and combustion turbine categories into a single category of fossil fuel-fired electricity generating units for purposes of promulgating standards of performance for GHG emissions. Combining the two categories is reasonable because they both provide the same product: electricity services. Moreover, combining them in this rule is consistent with our decision to combine them in the CAA section 111(d) rule for existing sources that accompanies this rule. In addition, many of the monitoring, reporting, and verification requirements are the same for both source categories, and, as discussed next, we are codifying all requirements in a single new subpart TTTT of the regulations; as a result, combining the two categories into a single category will reduce confusion. It should be noted that in this rule, we are not combining the two categories for purposes of standards of performance for other air pollutants.
One commenter (9514) stated that under its current co-proposal for subpart TTTT, EPA seeks to exempt peaking plants from the category and from regulation. As a functional matter, it defines peakers as those that have been designed to supply, and that actually supply, more than one-third of their potential electric capacity for sale to the grid on a three-year rolling average basis. As discussed elsewhere, the commenter urges EPA to include peaking plants in the combined TTTT category and to set standards for such plants as a subcategory.
See preamble for definitions of base load turbines and non-base load turbines (including peakers). The broad applicability in this final rule includes peaking units.
One commenter (9514) recommended that EPA define peaking units as units that operate fewer than 1,200 hours per year. EPA must also ensure that distinctions among combustion turbine power plants are based on function (as determined by annual hours of operation), not on purpose or technology.
  See preamble for definitions of base load turbines and non-base load turbines (including peakers).  The final rule includes a non-base load subcategory.
One commenter (10098; 10239) stated that in the event EPA proceeds with regulating GHG emissions under Subpart TTTT, EPA should adopt the definitions for coal and petroleum coke that it currently applies to steam generating units under Subpart Da. Based on past precedents, it would be arbitrary and capricious for EPA to continue to categorize petroleum coke as coal.
 The final standards apply to all new fossil fuel-fired EGUs ... including petroleum coke units. All fossil fuels are treated equally for steam generating units and IGCC units. Therefore, there are no regulatory implications to considering petroleum coke coal or oil. 
One commenter (10098) stated that there appear to be several discrepancies in the proposed rule that could produce different regulatory obligations under the alternative. For example, EPA proposes regulations at a facility level under Subpart Da, but at a unit-level under Subpart TTTT. Also, despite EPA's language in the preamble to provide an affirmative defense for malfunction, it appears that the affirmative defense was only included in Subpart TTTT but EPA does not propose to add or revise any regulatory text to provide an affirmative defense for GHG emissions under Subpart Da. The commenter stated that co-proposing the GHG NSPS for fossil-fuel fired EGUs in the existing Da and KKKK categories and creating a new category, TTTT create uncertainty and confusion regarding the EPA's intentions for the final standard.
In this rule, the EPA is combining the steam generator and combustion turbine categories into a single category of fossil fuel-fired electricity generating units for purposes of promulgating standards of performance for GHG emissions. Combining the two categories is reasonable because they both provide the same product: electricity services. Moreover, combining them in this rule is consistent with our decision to combine them in the CAA section 111(d) rule for existing sources that accompanies this rule. In addition, many of the monitoring, reporting, and verification requirements are the same for both source categories, and, as discussed next, we are codifying all requirements in a single new subpart TTTT of the regulations; as a result, combining the two categories into a single category will reduce confusion. It should be noted that in this rule, we are not combining the two categories for purposes of standards of performance for other air pollutants.
One commenter (10052) stated that proposed Subpart TTTT does not provide guidance on the methodology to partition and calculate the emission rates when there are multiple sources of emissions and a common turbine/generator, such as a dual combustion turbine combined cycle system with a single steam turbine.
In this rule, the EPA is combining the steam generator and combustion turbine categories into a single category of fossil fuel-fired electricity generating units for purposes of promulgating standards of performance for GHG emissions. Combining the two categories is reasonable because they both provide the same product: electricity services. Moreover, combining them in this rule is consistent with our decision to combine them in the CAA section 111(d) rule for existing sources that accompanies this rule. In addition, many of the monitoring, reporting, and verification requirements are the same for both source categories, and, as discussed next, we are codifying all requirements in a single new subpart TTTT of the regulations; as a result, combining the two categories into a single category will reduce confusion. It should be noted that in this rule, we are not combining the two categories for purposes of standards of performance for other air pollutants.
Including Modified or Reconstructed Units
One commenter (10098; 10239) stated that EPA should not expand the proposed rule now or in the future to encompass existing sources. EPA does not have the authority to regulate GHG emissions from existing EGUs under Section 111(d). That subsection only provides EPA authority to regulate where the source category is not otherwise subject to a standard under Section 112 (i.e., NESHAP), and EGUs are subject to such a standard. Moreover, many policy reasons counsel against proceeding with existing source regulations under Section 111(d).
  The EPA is finalizing standards for modified and reconstructed units in this acton.
Several commenters (2470; 3862; 9194; 9408; 9486; 9678; 9730, 9770; 9591; 10100; 10031; 10242; 10660; 10952; 10098; 2470; 10606; 9396; 9649; 9003) support decision to exclude modified and reconstructed sources from new source standards.
Several commenters (9678-; 9730; 10100) stated that they support EPA's proposal to focus on newly constructed sources in this rulemaking and to not regulate existing units that are modified or reconstructed as new units. According to commenters (9678, 10100), they are not required to establish corresponding standards for modified or reconstructed sources at the same time that they set new source standards. The regulation of GHG emissions from EGUs is complex and far-reaching, and EPA lacks sufficient information to develop a standard for modified and reconstructed sources. The commenter (9678, 10100) cited court cases and other legal precedents as supporting EPA's decision to regulate only new sources at this time. The commenter stated that under CAA section 111(a), EPA has the ability pursuant to CAA section 111(b)(2) to distinguish among classes, types, and sizes within categories and set standards for modified and reconstructed sources that are different than for new greenfield sources. 

One commenter (10100) stated that EPA's exclusion for modified and reconstructed units will create an incentive for existing coal-fired EGUs to invest in retrofits (such as repowering to natural gas) that will increase efficiency and reduce CO2 emissions. Without the exclusion, EGUs may avoid making such improvements to avoid triggering applicability of the NSPS, which may not even be achievable by existing sources.

Two commenters (9194; 9408; 10100) stated that applying the new unit NSPS to modified and reconstructed sources would have negative impacts. Commenter (10100) stated that applying the NSPS to modified and reconstructed units would be inappropriate, impractical and infeasible because the emissions standards cannot necessarily be met by existing units, even when a modification is made or the unit is reconstructed because they do not have the same design flexibility as new units when planning for modifications or reconstructions that may subject them to NSPS requirements. One commenter (9194-6611) stated that applying the proposed new unit standard to modified or existing units would force shutdowns of affected modified and existing units, causing unprecedented and severe impacts on electricity supply, reliability, and costs to consumers. 

One commenter (10606) stated that an existing or reconstructed EGU would likely have to comply using add-on controls. However, the only add-on control system is based on CCS technology, which has not been proven to be economically viable and may not be technically feasible in Florida, given the state's geology with only deep saline aquifers available for CO2 sequestration. 

One commenter (10952) stated that due to the other clean air regulations applicable to coal-fired EGUs and many currently in the implementation stages, many of these units are undergoing modifications presently or will over the next several years. Many actions undertaken at these units to achieve regulatory compliance could increase unit CO2 maximum hourly emissions rate and thus trigger an NSPS modification requiring new unit NSPS. The record for this current rulemaking is devoid of any information that EPA has evaluated emission mitigation options for implementing existing unit CO2 NSPS. It is therefore appropriate that coal-fired modified or reconstructed units be expressly exempt from the current proposed CO2 NSPS.

One commenter (9780) stated that when EPA ultimately promulgates section 111 GHG standards for modified EGUs, the Agency should ensure that owners and operators of such EGUs may avail themselves of the same compliance options and flexibility as owners and operators of other existing EGUs. Because modified and existing EGUs face more or less identical challenges in limiting their GHG emissions, it is good policy for EPA to consider them together and to afford the former the same compliance flexibility as the latter. 
 The EPA is finalizing standards for modified and reconstructed units in this action.
Several commenters (9425; 9665; 10100; 10031) agreed that EPA has insufficient information with which to propose regulations of modified and reconstructed sources.
One commenter (9425) stated that the information that EPA needs should include the types of physical or operational changes sources may undertake, the amount of increase in CO2 emissions from those changes, the types of control actions sources could take to reduce emissions, including the types of controls that may be available or the cost or effectiveness of those controls. The most likely candidates for control actions would be efficiency measures. 

One commenter (9425) stated they agree with EPA that there have been too few reconstructed sources in number to allow EPA to develop adequate information about the type of source; the type of changes; the extent of emissions increases; and the type of control measures, including their cost and associated emissions reductions, needed to propose a standard of performance for reconstructions. Therefore, the commenter agrees with EPA's decision not to include reconstructed sources in the proposed rule.

One commenter (9665) stated that EPA has properly decided to defer standards for modified and reconstructed units and that it has the legal authority to delay adoption of such standards to a later date. Indeed, regulating such units now would run counter to the goal of reducing future carbon emissions nationwide.

One commenter (10100) stated that because the proposed standards were developed based on a determination that they constitute BSER for new units, the standards could not be applicable to existing sources undertaking modifications or reconstruction. The proposed standards cannot constitute BSER for modified or reconstructed units because EPA has undertaken no analysis to determine whether such technology has been "adequately demonstrated" for these sources.
 The EPA is finalizing standards for modified and reconstructed units in this action.
One commenter (9665) stated that EPA's determination that the proposed NSPS will not establish a "BACT floor" for modified EGUs under the PSD program is reasonable and appropriate under the statute.
One commenter (9422) stated that a provision should be added to the proposed regulation that the CO2 standard does not set a floor for a PSD BACT determination for a modified unit.
This is addressed elsewhere in the RTC.
One commenter (8909) stated that they support EPA's plan to propose standards for modified and reconstructed sources under Section 111(b) in a separate proposal, in tandem with its forthcoming proposal to regulate GHGs from existing sources under Clean Air Act Section 111(d).  The commenter urges the Agency to solicit input from state and local air pollution control agencies as it has done with the forthcoming Section 111(d) proposal.
 The EPA is finalizing standards for modified and reconstructed units in this action.
Several commenters (8937; 9422; 9602; 10052; 10097; 10098; 10100; 10239; 10395; 10500; 10618; 10952; 10618; 9780; 9734; 9382) stated that the proposal does not sufficiently exclude modified and reconstructed sources from the proposed standards for CO2 and needs to be stated explicitly in the rule.
One commenter (10100) stated EPA should add an explicit exclusion for modified and reconstructed units. There is no "applicable standard of performance" for modified and reconstructed units that would subject them to regulation under Section 111 for GHG emissions. It is important that EPA clearly state that the new source standards are not applicable to modified and reconstructed EGUs. As a result, the commenter is concerned that outside groups may attempt to impose the NSPS on modified or reconstructed units through litigation, contrary to EPA's intent. To avoid regulatory uncertainty and unintended consequences, EPA should include clear language in section 60.5509(b) stating that the performance standards in the NSPS do not apply to existing sources undertaking modifications or reconstructions. 

One commenter (10098) stated that EPA's failure to include modified and reconstructed sources is unclear and creates uncertainty. EPA offers no justification for exempting reconstructed and modified sources and it is not clear that the proposed regulation actually accomplishes the exemption. Section 111(a)(2) defines a "new source" to include modified sources. See also 40 C.F.R. section 60.1(a), (b) (NSPS applicable to modified sources); 60.15(a) (NSPS applicable to reconstructed sources). The proposed rule provides no explanation of why the CAA and EPA's own regulations do not compel it to cover modified and reconstructed sources at the same time as new sources. EPA should make the exclusion of modified and reconstructed sources clear through a modification to subparts Da and KKKK (or alternatively TTTT). If EPA decides to withdraw the exclusion, they must do so through an ANPR. Alternatively, EPA should synchronize this proposed rule with any proposal that addresses modified and reconstructed sources such that the two rules are promulgated simultaneously.

One commenter (9422) stated that Table 1 to proposed Subpart TTTT indicates that 40 CFR 60.14 and 60.15, pertaining to the definition of modification and reconstruction, respectively, do not apply to Subpart TTTT. EPA should assess whether there are ramifications regarding omission of these sections as applicable to proposed Subpart TTTT since the PCP exclusion portion of the definition of modification is found in 40 CFR 60.14. Since 40 CFR 60.14 would not apply to Subpart TTTT, the definition of modification found in 40 CFR 60.2, which doesn't include the PCP exclusion, would apply.
 
One commenter (10052) stated that they support the adoption of EEI's recommended language to expressly exclude modified electric generating units in the regulatory language.
 
One commenter (10788) stated that while they support EPA's conclusion that the NSPS are not appropriate for modified and reconstructed sources, EPA did not make this finding in its Proposed Rule, and instead just declined to cover modified and reconstructed units without addressing why the standard should not be applicable to these units. Under the CAA and EPA's implementing regulations, modified and reconstructed sources are new sources. EPA should have addressed these units in the same proposal because they are definitionally "new" sources. By not addressing these units, EPA has potentially "piecemealed" its obligations, such as its duty to perform a cost-benefit analysis. 
 The EPA is finalizing standards for modified and reconstructed units in this action.
Two commenters (9665; 9665) stated that they support EPA's decision to include explicit regulatory language to clarify that regulation of CO2 under Section 111 triggers the Tailoring Rule GHG emission thresholds. To remove any legal uncertainty regarding the application of the Tailoring Rule, EPA should include regulatory language in the Part 52 PSD regulations that the Tailoring Rule thresholds apply to the regulation of CO2 triggered by Clean Air Act Section 111.
One commenter (10619) believes that specific language incorporating the Tailoring Rule thresholds should be added to each new NSPS Subpart that contains requirements for GHGs or a GHG containing revision to an existing Subpart.
  See final preamble section XII.
Several commenters (9194-; 9407-; 9600-; 9665; 9770; 10095) stated that EPA should include rule language that clearly shows subpart Da sources are not subject to NSPS modification requirements. The proposed regulatory text for revised Subpart Da does not include language similar to that in subparts KKKK and TTTT to make it clear that modification and reconstruction requirements are not applicable to subpart Da. 
This is clear in the final rule language.
Several commenters (5537; 9723; 10869) stated that it is urgent that EPA issue and finalize carbon standards for existing power plant, including modifications and reconstructions.  
One commenter (5537) stated that without requirements for modified or reconstructed EGUs, the EPA may create incentives for incremental changes at existing EGUs that extend their lifetimes while avoiding implementation of GHG reduction measures. The EPA should act quickly to ensure that the lack of GHG requirements for modified or reconstructed EGUs does not encourage the prolonged lifetime of less efficient, higher emitting facilities.

One commenter (9723) stated that EPA should propose rules for modified or reconstructed EGUs in a separate rule as soon as possible due to the concern that any modification or reconstruction to an EGU at this time could potentially be subject to the emission limits in the Reproposal until a separate standard has been proposed for modified or reconstruction EGUs.
 The EPA is finalizing standards for modified and reconstructed units in this action.
One commenter (9514; 10681) stated that EPA is properly taking action to develop standards for modified and reconstructed sources. As a policy matter, it is critical that EPA's performance standard for modified plants be sufficiently protective, since modifications may entail significant increases in carbon pollution. Performance standards for reconstructed sources are particularly important; without them, an operator could simply take an existing facility, demolish everything but a few parts, and then construct a new plant in its place. According to section 60.15(b)'s definition, this would constitute a "reconstruction," and the absence of regulations for reconstructed sources would permit this effectively new facility to escape the new source standard entirely. Under these circumstances, the loophole would permit what is for all intents and purposes a brand new power plant to "increase emissions without application of BSER. Accordingly, it is wholly appropriate that EPA's rule for modified sources will cover power plant reconstructions as well.
 The EPA is finalizing standards for modified and reconstructed units in this action.
Several commenters (9194; 9197-; 9422; 9425; 9723-; 9187; 9780; 9396; 9592; 9649) stated that EPA must continue to recognize and apply the Section 111 regulations' pollution control project (PCP) exemption, which exempts from the definition of "modification" "the addition or use of any system or device whose primary function is the reduction of air pollutants." If they are able to take advantage of this exemption, most environmental compliance projects, including projects to ensure compliance with the MATS, would be deemed PCPs that are exempt from NSPS for modified units, allowing them to be regulated as existing units. This exemption should also apply to changes to the plant that may be needed for compliance with future water pollution regulations, such as new intake equipment or cooling towers for 316(b) or new fly ash and/or bottom ash handling systems for the Effluent Guidelines regulations. One commenter (9723-7011) stated the PCP exemption is especially important since there are no available or feasible add-on CO2 emission control technologies that can be installed on existing EGUs that would provide a lower CO2 emission rate than what an existing EGU is currently capable of.
 The EPA is finalizing standards for modified and reconstructed units in this action.  See RTC for modification and reconstruction proposal. The PCP exemption is not being opened as part of the final rule. 
Several commenters (1900; 10119; 10396) oppose the exemption for modified and reconstructed sources.
One commenter (10119) stated that EPA once again proposes to completely exempt modifications, reconstructions, and certain hand-picked "projects under development" from any standard whatsoever. EPA's applicability standards also effectively exempt simple-cycle natural gas turbines, despite ample evidence that this will continue to be an important part of the power sector in the future, as well as low capacity factor NGCC turbines that could readily meet standards even more stringent than EPA has proposed here for high capacity factor NGCC plants.

One commenter (10396) stated that the CAA does not allow for a bifurcation of a rule for new and modified.

One commenter (9195) stated that EPA must explain rational for not including modified sources in the 111 (b) proposal. Provide a detailed legal rationale and any supporting examples or precedent. a. Will the Agency propose a separate rule for modified sources under section III or will this rule be combined with the upcoming 111(d) proposal? Provide EPA's legal rationale for this decision. b. What will be the triggering thresholds for modification? Provide a detailed legal rationale for this decision. c. What will be the effective date for the section III modified source rule-proposal, finalization, or some other date? Provide a detailed legal rationale and any supporting examples or precedent.
The EPA is finalizing standards for modified and reconstructed units in this action.  See RTC for modification and reconstruction proposal
One commenter (9425) requested that EPA exercise the flexibility that exists under the NSPS and treat modified sources as existing sources for both NSR and PSD programs when implementing the GHG NSPS standard, rather than treated as new sources, and that the requirements for existing sources be phased in over time.
One commenter (2470) stated that modified plants should be treated like existing sources under the guidelines of Section 111(d) since modified plants have the same limited options to reduce emissions as existing sources. Requiring modified plants to meet the proposed standards for new sources would necessitate the requirement of CCS installations at existing coal, oil, and some natural gas-fired plants.
The EPA is finalizing standards for modified and reconstructed units in this action.  See RTC for modification and reconstruction proposal
Conditions That Constitute Modifications
One commenter (10098) stated that their members will be harmed because this rule is a legal prerequisite to EPA's apparent intent to regulate existing EGUs under Section 111(d).
 The EPA is finalizing standards for modified and reconstructed units in this action.  See RTC for modification and reconstruction proposal
One commenter (9514) stated that EPA's forthcoming regulations must cover all modifications as that term is defined in section 111, including PCPs. The commenter states that EPA's current NSPS regulation specifically exempt from the definition of "modifications" any PCPs. Citing a D.C. Circuit decision striking down an identical PCP exemption in the context of the statute's New Source Review program as contrary to the CAA, EPA not rely on it when promulgating its performance standards for modified sources, and must ensure that PCPs are covered under the forthcoming rule.
The EPA is finalizing standards for modified and reconstructed units in this action.  See RTC for modification and reconstruction proposal
One commenter (10394) stated that most changes inclusive of turbine replacement would not exceed the 50 percent capital cost trigger in the definition of "reconstruction" as construction costs often exceed the equipment costs. Regardless, the commenter would support a limit commensurate with a new turbine construction. In order for a project to be considered a reconstruction, the majority if not all major components including the combustion turbine, Heat Recovery Steam Generator (HRSG), and steam turbine would have to be replaced. Modifications which result in emission increases need further analysis specific to the modification to determine if a GHG limit should be developed. At minimum, the modification should include a condition to maintain a historically determined GHG level for operations from this point forward.
 The EPA is finalizing standards for modified and reconstructed units in this action.  See RTC for modification and reconstruction proposal
One commenter (9035power plants (Section 111(b)) would ever have to comply with carbon pollution standards for existing plants (Section 111(d)), or if such a plant would be permanently exempt from future emission cuts. Several states have been discussing their preference for a Section 111(d) rule that authorizes a statewide carbon budget to cap and reduce emissions from existing power plants. In such states it may be more administratively efficient and cost-effective simply to place new plants immediately under the carbon budget determined in accord with the Section 111(d) guidelines. These states would benefit greatly from knowing as soon as possible how and when to factor new plants into their carbon budgets. Additionally, it is necessary to specify whether modified or reconstructed plants will be covered by Section 111(d) rules, in addition to Section 111(b). 
The EPA is finalizing standards for modified and reconstructed units in this action.  See RTC for modification and reconstruction proposal
One commenter (1899) stated that to the extent EPA's guidelines are based on replacing equipment to improve the efficiency of the generating unit, EPA should exempt such activities from being considered a "modification" for purposes of NSR permitting. These guidelines proposed by EPA need to be based on an inside-the-plant-fenceline approach allowing the states broad flexibility in developing plans to meet and implement guideline requirements.
The EPA is finalizing standards for modified and reconstructed units in this action.  See RTC for modification and reconstruction proposal
One commenter (1899) stated that State's should have the option to allow credit for all reductions since 2005, including plant retirements, fleet-wide averaging/trading, improving unit heat rates, equivalency for state programs, averaging/bubbling, trading, unit-specific or generally applicable variances, purchasing energy efficiency credits, adding new lower-emissions fossil fuels and renewable energy, offsets, and other cost-containment mechanisms. States should not be constrained to unit-specific requirements such as heat rate improvements or thermal efficiency improvements
The EPA is finalizing standards for modified and reconstructed units in this action.  See RTC for modification and reconstruction proposal
Potential Impacts on Modified and Existing Sources from EPA's Proposal
Two commenters (9660; 9514) stated that EPA must promptly issue emission guidelines under 111(d) for existing sources. The commenters stated that EPA's proposal of standards of performance for new sources triggers the agency's duty to propose guidelines for States to develop plans to limit CO2 emissions from existing sources. The President's climate plan directed EPA to propose emission guidelines by June 2014 and finalize them by June 2015. The States therefore request that EPA propose section 111(d) guidelines by June 2014. 
One commenter (9660) described legal proceedings, international agreements and assessments from the NAS committing the US government to act to address greenhouse gases in the near term. In addition, EPA's position that it lacks sufficient data at the time to propose standards for modifications under section 111(b) provides additional impetus for the agency to ensure that in the meantime those sources are at least subject to standards applicable to existing sources. Without prompt action by EPA, EPA and the states cannot begin the necessary collaborative process to require significant, cost-effective reductions in CO2 emissions from existing power plants. 

One commenter (2525) supports the proposal but stated that eventually old plants need to be phased out or we will become overly reliant on the most inefficient and most polluting plants. There should be standards for old plants and a time when they will not be "grandfathered" out of needed regulation. Coal Plants also emit mercury, sulfur, arsenic, cyanide, soot, and lead and not held responsible for health effects or clean up when coal ash spills. We should be strengthening - not weakening - reasonable restrictions on coal. 

One commenter (9514) stated that regulation of existing peaking units under section 111(d) provides an opportunity to obtain meaningful emission reductions at a reasonable cost. Thus, EPA should not exempt new peaking units and thereby unnecessarily complicate the opportunity to examine these issues in more detail in the upcoming rulemaking concerning existing units.
 The EPA is finalizing standards for modified and reconstructed units in this action.  See RTC for modification and reconstruction proposal
One commenter (8972) recommended that energy efficiency (including combined heat and power, waste heat to power, and utilization of waste heat recovery), renewable energy options, as well as natural gas and propane be made eligible as compliance options under the EPA guidelines for existing power plants. In addition, these cost-effective compliance options will help grow the economy, create jobs and strengthen our energy system through diversification. The flexibility of a system-wide approach will be important to utilities in order to make these clean energy technologies viable as compliance options. The commenter noted the importance of this and other key considerations, such as providing credit for programs and policies that have already made strides to reduce emissions.
One commenter (9591) stated that the applicability scope of the emission guidelines under section 111(d) of the Clean Air Act must mirror the applicability scope of the authorizing new source performance standard under section 111(b). If EPA intends to allow states the flexibility to develop a market-based program, the commenter encourages EPA to require these states that choose this option to evaluate the impact of such a program on all electricity generating sources that sell to the grid to ensure generation does not shift to uncovered, but higher-emitting, sources. The commenter encourages EPA to approve state plans that include new sources in a state-designed market-based program that puts a price on CO2 emissions under section 111(d) and cited CAMR as an example of such a program. The commenter recommended that EPA align compliance demonstration requirements included in the existing source guidelines with current requirements, such as the Acid Rain Program, to the extent feasible. The commenter recommended that EPA's final rule under section 111(d) could include recognition of existing programs that reduce GHG emissions from the electric sector, such as the Regional Greenhouse Gas Initiative and California's AB32, as well as recognition of new state or regional programs that allow averaging, trading, or credit for early action. 
The EPA is finalizing standards for modified and reconstructed units in this action.  See RTC for modification and reconstruction proposal
One commenter (8973) stated that while it is impossible to estimate compliance costs for impacted municipal utilities in advance of EPA issuing proposed standards for existing units, decisions made by EPA and by states will ultimately impact compliance costs and the overall cost-effectiveness of any standards for existing units.  The commenter stated their concern that EPA's assumption "that there are not costs to its new unit NSPS proposal" could be carried forward into the agency's upcoming existing source rule.
  This comment is out of scope for this rulemaking.
One commenter (9666) stated that even if the form of a rule for existing sources has not yet been determined, EPA should have, at a minimum modeled degrees of uncertainty regarding the ability to operate existing coal-fired units under a section 111(d) program. This regulatory uncertainty creates a significant obstacle to future investments in the power sector and a considerable cost to the sector that is not reflected in EPA's cost assessment.
One commenter (9591) stated there are a number of existing units subject to subpart Da and combust oil and/or natural gas. As EPA contemplates regulation of existing Da sources under section 111(d), it should recognize that many existing gas and oil steam units serve load-constrained areas of the country and may be subject to state or regional fuel diversity requirements. The commenter ask that EPA allow these units a path to compliance.

One commenter (2470) stated that that many the state's existing plants will require modification to meet the requirements of other EPA rules, including the Cross-State Air Pollution rule, the Mercury and Air Toxics rule, the Cooling Water Intake Structures rule, and the Coal Residuals rule. Electric generators and their consumers should not be placed in the position where investments to meet one EPA rule trigger an unobtainable CO2 standard for existing coal- and oil-fired generators.
This comment is out of scope for this rulemaking.
One commenter (9666) stated that if EPA is correct that once it regulates CO2 emissions from new sources under section 111(b), it must regulate existing sources in the affected source categories under section 111(d), then EPA should have estimated the economic impacts of this proposed rule for existing sources.
The EPA agrees with this comment.
One commenter (8973) stated that the agency's assumptions about the availability of CCS are unreasonable and unproven and should not be used as the basis for emissions standards in the existing source rule.  The commenter urged EPA to not adopt these assumptions in the existing unit rule in light of the agency's assertion that it is seeking cost-effective and flexible solutions.
 This has been addressed elsewhere in the RTC (see Chapter 6).
One commenter (8954) stated that utilities are building plants fueled by natural gas instead of coal, in part due to EPA's burdensome, costly regulations. According to the commenter, EPA's actions in the energy economy will impose undesirable and unnecessary risks for American businesses and consumers. Regarding the current low cost of natural gas, the commenter stated no one can predict events that can trigger changes in the supply, demand and price of energy commodities. The commenter provided several examples of ongoing price volatility based on recent periods when cold weather pressured natural gas prices and increased electricity costs. The commenter provided examples of geographic differences in the price of electricity produced using natural gas and, unlike coal, natural gas cannot be stored to the extent that coal can be in order to respond to high energy demands.  The commenter compared the cost of three energy sources (coal, natural gas and oil) in the mid-Atlantic and Midwest, and how coal is more economical in comparison to others and maintains price stability throughout the years.
This has been addressed elsewhere in the RTC (See Chapters 2 and 6)
One commenter (9425) stated that depending on market circumstances regarding reliability and economics, companies may reactivate units that have been essentially "mothballed" or placed into cold storage. Reactivation would only be feasible, in most cases, if the unit did not trigger NSPS. In any final rule, EPA should affirm that the GHG NSPS does not change long-standing EPA regulations or practice, as well as state regulations implementing NSPS, regarding the reactivation of a facility. That is, if an EGU is not modified or reconstructed (under NSPS definitions) before restarting, the project does not trigger NSPS, as long as the federal/state operating permit(s) remain effective. 
 This comment has been responded to elsewhere in this final rule. The EPA is making no change to any long-standing EPA provisions or practice, as well as state regulations implementing NSPS, regarding the reactivation of a facility.
One commenter (9201) stated that while EPA has stated that its proposed 111(b) rule only applies to new units and that the Agency plans on proposing standards for modified units in its upcoming rulemaking, the statutory language states that 111(b) applies to both new and modified units. EPA must emphatically state again that this proposed rule does not apply to modified sources that might be retrofitting to comply with existing regulations such as MATS, or for future rules, such as EPA's upcoming rules governing transported air pollution under CAA section 110(a)(2)(d).
One commenter (9592) stated that they agree with EPA that the "new" unit NSPS must not apply to modified, reconstructed or existing units. According to the commenter, applying the proposed new unit standard to modified or existing units would force shutdowns of affected modified and existing units, causing unprecedented and severe impacts on electricity supply, reliability, and costs to consumers. The commenter stated that the regulatory text for revised Subpart Da should be revised to explicitly state that modification and reconstruction requirements under 40 CFR 60.14 and 60.15 are not applicable to the standards for CO2.
This comment has been responded to elsewhere in this final rule.  The EPA is finalizing standards for modified and reconstructed units in this action.  See RTC for modification and reconstruction proposal
One commenter (10239) stated that EPA's proposes to exempt reconstructed and modified EGUs from the proposed standard but offers no defensible explanation of why the CAA and the EPA's own regulations will not subject modified and reconstructed sources to the proposed standards. According to commenter 10239, the EPA's apparent intent to issue different regulations for modified and reconstructed sources does not resolve this issue. Unless and until such alternative standards are issued, there is a risk that modified and reconstructed sources will be required to comply with the proposed standards for new EGUs, resulting in significant harm to existing sources. Even if the proposed standards are not directly applicable to modified and reconstructed sources, PSD permit writers may still apply CCS as BACT if the modification or reconstruction trigger PSD applicability thresholds. The commenter cited GHG Guidance at G-1 (NSPS from other source categories may be "a useful starting point" for BACT analyses).
One commenter (9777) stated that the proposed NSPS would discourage companies from taking measures to increase fuel efficiency or maintain reliability. EPA's enforcement personnel have taken the erroneous position in litigation that routine maintenance, repair, and replacement work at existing units are "major modifications" under the CAA that require a PSD permit that imposes BACT emission limitations. While the commenter strongly disagrees with EPA's enforcement position, and many courts have rejected it, if the proposed rule is finalized, it would nonetheless discourage reliability projects in light of EPA's enforcement position and the possibility that the GHG NSPS would be part of the BACT analysis.
 This comment has been responded to elsewhere in this final rule 
One commenter (10239) stated that the Agency should avoid regulation of GHG emissions from existing sources for policy reasons. The following reasons, discussed in detail in their comment submittal, were given for not regulating GHG from existing sources under 111(d):
      -The regulation of existing sources already subject to Section 112 would add a layer of regulatory complexity. -Section 111(d) is a state-driven program, which will create independent and potentially inconsistent rules for existing sources with significant economic impacts because energy is a fungible commodity that can be marketed across state lines. 
      -EPA creates a risk of particularly adverse impacts for other trade-exposed sectors. Most of the manufacturing sectors subject to Section 112 are trade exposed. 
      -Subjecting the same source to regulation under both Sections 111(d) and 112 would result in duplicative and burdensome regulations and would be contrary to Congress' intent to regulate existing sources primarily under Sections 108 and 112.
      -Applying Section 111(d) to the new source category would unreasonably burden state permitting agencies, given the large number of existing sources.

One commenter (10098) stated that EPA should refrain from regulating GHG emissions from existing sources under Section 111(d) because EPA lacks the legal authority to regulate GHG emissions from existing sources that are already subject to a Section 112 NESHAP. The commenter stated that there are also policy reasons for not regulating existing sources. The commenter provided extensive argument in support of their position. The commenter stated that in the event that EPA does intend to regulate CO2 emissions from existing sources, it must not incorporate CCS into any future standard or guidance.
This comment has been responded to elsewhere in this final rule 
Two commenters (10098, 10239) stated that the industry will be harmed by a final GHG NSPS because it is a necessary legal step in EPA's plan to regulate GHG emissions from existing sources under Section 111(d). While EPA is legally barred from regulating GHG emissions from fossil-fuel fired EGUs under Section 111(d), EPA interprets Section 111(d) to require regulation of existing sources once an NSPS under Section 111(b) is final. The regulation of GHG emissions from existing coal-fired EGUs will have a significant impact on those facilities, producers and transporters of coal and petcoke, and retail electricity consumers. And those effects are directly attributable to this rulemaking because it is a legal prerequisite for the regulation of existing sources under Section 111(d). The commenters stated that EPA acknowledges that the GHG benefits from this rulemaking will come from existing sources, not the new sources directly regulated under Section 111(b). Thus, if the EPA seeks credit for future GHG emissions reductions from existing sources, it cannot ignore the costs and other harms that those emissions reductions will cause for the nation's leading energy, agriculture, and manufacturing sectors.
This comment has been responded to elsewhere in this final rule 
One commenter (10239) stated that EPA must clarify inconsistent language in the proposed rule regarding the applicability of the standards at the facility level or at the unit level. At times the standards apply at the facility level. See 79 Fed. Reg. at 1,459 ("In today's rulemaking, we propose that standards of performance apply to a facility . ."); proposed 40 C.F.R. Section 60.46Da(a) ("Your affected facility is subject to this section if construction commenced after [DATE OF PUBLICATION IN THE FEDERAL REGISTER], and the affected facility meets the conditions specified in paragraphs (a)(1) and (a)(2) of this section . ."). But under Subparts KKKK and TTTT the rule would apply only to individual units. See Proposed 40 C.F.R. Section 60.4305(c) ("For purposes of regulation, of greenhouse gases, the applicable provisions of this subpart affect your stationary source turbine if it meets the applicability conditions in paragraphs (c)(1) and (c)(5) .."); 60.5508 ("This subpart establishes emission standards and compliance schedules for the control of greenhouse gas (GHG) emissions from a steam generating unit, IGCC, or a stationary combustion turbine that commences construction after [DATE OF PUBLICATION IN THE FEDERAL REGISTER]."). This difference is important to existing facilities that may add new EGU capacity. The commenter urged EPA to clarify in the preamble and the regulatory text that the standards are applied on a unit-by-unit basis. Thus, any new capacity would be subject to the proposed standards, while existing units would be regulated, if at all, under Section 111(d). The commenter stated that this approach is preferable to one where such facilities would presumably be regulated as modified sources under Section 111(b).
This comment has been responded to elsewhere in this final rule 
One commenter (9192) supports credit for early action as an important component of establishing greenhouse NSPS for existing power plants. Utilities that reduced greenhouse gas emissions prior to establishment of this pending standard should not be punished for having taken early action. These activities should be allowed as compliance options in order to meet any future requirements applicable to existing sources.
 This comment has been responded to elsewhere in this final rule
BACT Determinations
One commenter (9514) stated that the NSPS established by this rule will affect future BACT determinations under the PSD program. It is therefore important that EPA establish strong performance standards in the current rulemaking: not only are the NSPS crucial for reining in CO2 pollution from coal and gas plants, they will also lay the groundwork for future BACT determinations for EGUs subject to the PSD program. This is particularly relevant to gas plants, which will comprise the vast majority of new fossil-fired EGUs in the foreseeable future. Accordingly, the commenter reiterates the need for performance standards that truly reflect the cutting edge technology, and urge EPA to adopt the stricter emission limitations they have suggested.
The commenter is correct that promulgated standards of performance under section 111 create a level of minimal stringency ("BACT floor') for BACT determinations for sources from the same source categories. However, this consideration is not directly relevant in determining standards of performance under section 111(a) and thus EPA did not base the standards of performance adopted in this rule on the standards' establishing a control technology floor for future PSD permits.    
Several commenters (8957, 9197, 9596, 9600, 10097, 10098, 9472, 9201, 10870, 9487, 9407, 9774, 3488, 8188) stated that CCS is not adequately demonstrated as BACT. The effect is that EPA is setting NSPS more stringent than BACT.
One commenters (10098) stated that the industry will be harmed by the potential application of CCS as BACT under PSD permitting decisions. There is a significant probability that permit writers will rely on the NSPS standards for solid fuel-fired EGUs when conducting BACT determinations under the PSD permitting program. There is also a substantial risk that the NSPS could be relied upon by permit writers to require CCS as BACT for modified solid-fuel-fired EGUs or for entirely separate source categories.

One commenter (9472) stated that EPA's proposed standard is inconsistent with the determinations as to what constitutes BACT for limiting CO2 emissions from new facilities under the PSD program. Both EPA and state permitting authorities have determined that CCS is neither demonstrated at a utility scale nor a cost-effective commercially available technology. The commenter provided a list of six plants for which CCS has been rejected as BACT. A similar record exists for the non-electric generation projects that have received CO2 BACT permit limits, including cement and steel manufacturing facilities. The commenter cites EPA's GHG BACT guidance as demonstrating that additional work is needed before CCS can be integrated at full-scale electric utility applications. The CO2 BACT determinations and EPA's own technical assessments provide further support that CCS is not adequately demonstrated. The commenter stated that the NSPS serves as the floor in setting the BACT limits for new sources while the permitting authority can increase the stringency of the emissions control requirement beyond the NSPS levels on a source-by-source. It makes little sense for EPA to set a more stringent CO2 control level under the less-rigorous NSPS standard-setting process than what EPA and state permitting authorities have recently set on a source-by-source basis through the prescriptive BACT standard-setting process.

One commenter (10039) stated that because CCS has failed to be determined to be BACT for any coal fired EGU to date, all BACT determinations have eliminated CCS based on costs, energy, environmental and/or economic impacts. Because BACT is a requirement of the federal NSR rules, EPA has the ultimate oversight and must review every BACT determination for CO2 yet no permits require CCS as BACT. US EPA has therefore not determined CCS to be BACT in a PSD permit.

One commenter (9201) stated that EPA must clarify that the proposed rule cannot set the "BACT Floor," as previous NSPS rulemakings have done. If the BACT Floor is "reset" to require CCS, EPA's proposal will have significant negative impacts on the ability of the existing fleet to improve its environmental performance or to comply with other existing and future EPA regulations. To date, the BACT permitting process has rejected the installation of CCS. According to the commenter, if EPA requires CCS for BACT, that determination would effectively forestall and freeze facilities from installing pollution controls or upgrading their efficiency. The commenter requests that EPA unequivocally state in the final rule that the standard has no applicability, direct or indirect on these existing EGUs or the BACT permitting process whatsoever in order to avoid confusion and the potential negative impacts on the BACT process in the future.
One commenter (10097) stated that the proposed BSER of partial carbon capture is not available over reasonably wide geographic areas and is therefore not adequately demonstrated. In EPA's PSD Greenhouse Gas Permitting Guidance for determining BACT, the agency acknowledges that massive infrastructure is needed for CCS and that where the necessary infrastructure is not available, CCS is not applicable. EPA offers no justification in this rulemaking to rationally support a radical departure from its most recent position on BACT permitting, including that CCS in any form may not be required as BACT.Most of these comments are addressed in section XII.C of the preamble to the final rule.  In brief summary, EPA there states that BACT determinations are made case-by-case so that individual determinations are not determinative of national standards; that information on technical and economic capabilities of CCS evolve over time, so that information has evolved since EPA adopted the 2011 GHG Permitting Guidance; and that the GHG Permitting Guidance is not inconsistent with any of the findings made in this rulemaking regarding partial CCS as BSER (especially given that the Guidance indicates that full CCS is an available technology for sources emitting large amounts of CO2 under step 1 of a top-down BACT analysis).  The Guidance does note (at p. 36) that application of CCS can involve substantial expense and can raise issues of infrastructure availability. In determining that partial CCS is BSER for new fossil fuel steam electric plants, EPA has carefully considered the issue of logistics (including cost estimates for land acquisition, transportation, and sequestration) and costs generally and determined that any such issues either can be surmounted, or, for new sources that construct without access to sequestration or EOR opportunities, that alternative options exist for meeting the standard which do not pose any logistical issues, including use of IGCC, or other means of compliance. Nor would new plants face the same types of constraints as modified or reconstructed sources in a BACT determination, since a new source has more leeway in choosing where to site. See text at preamble section VG3. Moreover, the GHG Permitting Guidance considered BACT determinations for all types of sources, not just those for which EPA has determined in this rule that partial CCS is the best system of emission reduction, and the concerns voiced in the Guidance thus must be considered in that broader context.
Commenters mistakenly suggested (or voiced concerns) that determinations for new sources establish a BACT floor for modified or reconstructed EGUs.  This is not the case.  EPA has adopted separate standards for CO2 emitted by modified and reconstructed EGUs and that standard creates the BACT floor for such units if they become subject to PSD review.
One commenter (9487) stated that EPA cannot promulgate NSPS standards and in and of themselves have the unavoidable effect of favoring some states over others. At the very least, therefore, NSPS requirements must be technically feasible and sustainable in all states.
EPA has done so. The promulgated standard can be met anywhere in the country, including areas where sources are unable to access sequestration or EOR (even using coal-by-wire), since there are compliance alternatives (including using IGCC and advanced technology likewise available at reasonable cost without collateral adverse non-air quality health or environmental impacts or adverse energy impacts) not involving sequestration or EOR or any other geographic constraint.
One commenter (9197) stated EPA should base the CO2 NSPS for new coal-fired EGUs on state-of-the-art, highly efficient generation technology without CCS.
As explained in section V.P of the preamble to the final rule, EPA has determined that superior performing technologies which are adequately demonstrated exist, so that it would be inappropriate to determine that efficient boiler design is BSER.
One commenter (10047) stated that the NSPS for coal-fired EGUs is based on CCS and is more stringent than any existing BACT determination. Thus, it appears EPA is proposing that the NSPS establish BACT. We believe this is neither appropriate nor necessary for coal-fired units as no new coal-fired units are planned for the immediate future. Thus, it appears there would be no environmental impact of proposing a less stringent standard. The commenter recommended that EPA set the NSPS for CO2 emissions from coal-fired units at a level equal to recent BACT determinations and based on maximized efficiency of new units. EPA has proposed the NSPS for gas-fired units based on this principle, and we believe that the same principle should hold for coal-fired units.
The NSPS rests on a sound basis considering the statutory requirements of section 111(a)(1).  The standard does create a floor for BACT for applicable sources, which is the necessary statutory result for any valid NSPS.  The comment is factually somewhat misleading because most of the BACT CO2 permit determinations issued thus far have involved new NGCC units, and EPA has not issued a single BACT permit for a new coal-fired EGU.  See the following response as well.    
There is a sound basis for determining BSER for new coal-fired units based on a different BSER than new NGCC units.  Part of the determination that a system of emission performance is "best" and "adequately demonstrated" is consideration of "energy requirements".  CAA section 111(a)(1).  EPA was especially mindful of the impact on energy requirements of a standard for new NGCC that could reduce availability of new NGCC electricity capacity, given the fact, as voiced by the commenter, that all or virtually all new capacity for the foreseeable future will be NGCC.  These considerations do not apply with coal-fired new capacity since, as the commenter notes, there will be minimal impact on energy requirements given that few if any such sources will be constructed.
One commenter (10030) stated that a recent BACT determination set the GHG emission level at approximately twice the level of the proposed emission level. During the public comment, EPA made no objection to these GHG BACT emission limitations. The permit reflects the only existing GHG BACT determination for coal/petroleum coke fired EGU units of the type which EPA now proposes to subject to a 1,100 lb/MWh standard.
 See section XII.C of the preamble.  To date, EPA has not issued a permit with GHG BACT for a source that would be an affected facility subject to a standard of performance under this NSPS reflecting performance of post-combustion partial CCS (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 federal BACT determinations in setting this standard performance based on the performance of post-combustion partial CCS . Furthermore, PSD permitting requirements first applied to GHGs 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 environmental agency 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 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.
With regard to the specific BACT permit determination referenced by the commenter (Wolverine Power Supply Cooperative), we note that this was a determination of the State of Michigan, not EPA.   The State conducted that review in 2011, and determined that although CCS was an available technology for the project, there was no available sequestration or other infrastructure available for captured CO2, and that CCS would not be cost effective for the project.  Michigan DEQ, Response to Comment Document PTI 317-07 (June 29, 2011) at pp. 102-03.  The State also rejected IGCC as BACT as not being cost effective for control of criteria pollutants (id. at 71-72), and rejected supercritical boiler technology on cost grounds as well (id. at 104-05).  

As just discussed, EPA is not bound in this rulemaking by this site-specific state determination, which in any case reflects information then available, some of which is outdated.  There is more information available now than in 2011 on partial CCS cost and reliability, and compliance alternatives not involving sequestration are available to new sources.  (Indeed, the State rejected supercritical technology as BACT but a number of industry commenters urge adoption of supercritical boiler technology as BSER here, again pointing up that historic fact-specific determinations can be overtaken by more recent information.)  Nor does the standard of performance adopted in today's rule apply to projects under development like Wolverine.  See preamble section III.J.
One commenter (9777) stated that EPA should maintain its interpretation that CCS is not required for modified or reconstructed units. There are no guarantees that EPA's proffered interpretation will withstand a legal challenge or will be the future position of the agency. Should a PSD permit applicant lose that challenge, and be forced to install CCS, it would mean that the applicant would either abandon the reliability project (if possible) or be forced to retire the unit.
One commenter (9423) stated that the proposed NSPS would preclude applicants for PSD permits for coal-fired power plants without CCS from making an economic reasonableness argument, because the proposed NSPS establishes a floor for BACT. EPA suggests that CCS will become economically reasonable in the future, but it is unknown how far into the future that will be, and in the meantime a permit applicant for a PSD permit for a coal-fired EGU would be forced to meet a standard that would require CCS which is currently cost-prohibitive.
One commenter (9765) stated that EPA considers CCS to be a feasible technology. There are several unknowns, however, including potential energy penalties, carbon capture installation and operational costs, and the reliability of the systems. Whether the current estimates for these aspects of CCS meet, exceed, or fall short of the anticipated values can only be known once a facility is constructed and operated for a period. What we know with complete certainty is this: a full-scale CCS system has yet to be demonstrated on a coal- or gas-fired power plant. Because BACT requires a case-by-case analysis and addresses many of the same factors required under Section III, the commenter believes BACT is a more appropriate CAA tool for reducing GHG emissions at EGU's. The EPA must limit the required GHG control technologies to those that have already been demonstrated in practice.
EPA has explained in the preamble to the rule and elsewhere in response to comments why the standard of performance adopted in this rule for new coal-fired EGUs is based on adequately demonstrated BSER and is achievable. Moreover, the commenters are incorrect that partial CCS is not demonstrated at commercial scale. The Boundary Dam facility has been operating full post-combustion CCS at commercial scale and is doing so successfully.
Two commenters (9678, 9780) stated that recent GHG BACT permit determinations do not support the standard. BACT limits are made on a case-by-case basis, and are not necessarily adequately demonstrated for the source category as a whole, hence are not BSER. Moreover, some of the permits referenced by EPA provide more flexibility than the proposed standards and thus do not support the proposition that a lower standard might constitute BSER. 
 See section XII.C of the preamble.  The BSER in this rule is not based solely on recent BACT determinations.   EPA has considered other information to support its BSER determination in this rule. The Boundary Dam facility has been operating full post-combustion CCS at commercial scale and doing so successfully. As noted above, BACT decisions are case-by-base, based on the specific conditions of the proposed source and the location of the proposed source.  While individual BACT determinations may provide information that is pertinent to a BSER determination, there is no requirement that BSER determinations must be based only on prior BACT decisions or that such decision must necessarily match (or exceed) a BSER for a source category. BACT should consider available technologies, and CCS has been a considered technology for recent BACT reviews for GHG emissions. Furthermore, BACT reviews should consider up-to-date information.  Even though a BACT determination for a particular type of EGU may not have selected CCS or partial CCS for the technology in the past, this does not mean the technology could not be potentially determined to be BACT in a subsequent permitting decision or the same or a different type of EGU based on additional information. It should be noted that EPA has not issued a PSD permit with a CO2 BACT determination for a coal-fired power plant.
One commenter (10095) stated that EPA should not have relied on recent GHG PSD BACT determinations to justify the reasonableness of its proposed standards. BACT and BSER are not interchangeable. BACT is a case-by-case analysis and is site-specific. NSPS are standards that broadly apply to the entire industry. Even if a given facility's GHG BACT limit could be set at levels below 1,100 lb/MWh, there is no evidence or information in the record that suggests the balance of economic, environmental, and energy considerations, when applied on an industry-wide scale, would arrive at the same level. Notably, the Edison Electric Institute completed a detailed analysis of recent GHG PSD BACT determinations and concluded these determinations do not support EPA's proposed standard.
 See section XII.C of the preamble. The BSER in this rule is based on more information than recent BACT determinations. We recognize the differences in setting a BSER for an industry and establishing a BACT for a specific source. The EPA is finalizing an emission standard for newly constructed fossil fuel-fired steam generating units at 1,400 lb CO2/MWh-g, a level that is less stringent than the proposed limitation of 1,100 lb CO2/MWh-g. The final standard reflects our identification of the BSER for such units to be a lower level of partial CCS than we identified as the basis of the proposed standards  -  one that we conclude better represents the requirement that the BSER be implementable at reasonable cost. Section V of the final preamble describes the rationale and justification of the BSER determination and the resulting final standards of performance for newly constructed fossil fuel-fired steam generating units.
Two commenters (9678; 10660) stated that they agree with EPA that the GHG NSPS for new sources would not establish a BACT floor for modified sources under the CAA's PSD program.. One commenter (9683-2963) supports the decision to exclude modified sources but believes EPA must clarify how EPA and state permitting agencies can avoid application of the emission standard under an NSPS as the floor for BACT.
Several other commenters (8937; 9597; 9194; 9197; 9677; 9777; 9396; 9003; 8024, 10618) stated that EPA should clarify their position and include regulatory language that this proposed NSPS does not establish BSER or a BACT floor for sources that are modifying an existing EGU.
 The EPA reiterates that the new source NSPS does not create a BACT floor for modified EGUs. The standard of performance for modified and reconstructed EGUs creates the BACT floor for modified and reconstructed EGUs. However, one needs to be careful in this context to distinguish between units and sources.  NSR generally applies to major sources, while this NSPS applies to units that may be within a source. Thus, it is possible that a standard for new coal-fired units may create a BACT floor for some "sources" that are considered "modified" from an NSR perspective (specifically, adding a new EGU at an existing source).
One commenter (10618) stated that The U.S. Supreme Court is considering whether EPA properly concluded that the issuance of mobile source standards under Section 202 of the CAA automatically triggered the regulation of GHG emissions from stationary sources under the Title V and PSD permitting programs. The outcome of that litigation is not yet known. However, if the provisions of the agency's GHG tailoring rule in its PSD permitting regulations are upheld, the regulatory language developed for this proposal must be supplemented to assure that the GHG tailoring thresholds operate effectively to prevent application of the program to minor sources.
The impact of the Supreme Court's decision in UARG is discussed in section XII.B of the preamble to the final rule. This section addresses EPA's final action to assure continued operation of certain provisions adopted in the Tailoring Rule on an interim basis.  
One commenter (-9034-4062, 4063) stated that the Proposed Rule will impact the permitting of new or modified electric generating units. Citing the CAA's PSD pre-construction permit program, the commenter states that the proposed CO2 emissions standards would establish BACT for new fossil-fuel fired electric generating units and natural gas-fired steam turbines covered by the standard. To support their comment, the commenter cited two petitions challenging PSD permits issued for GHG emissions.
One commenter (7977-4801, 4803) disagrees with the EPA's assessment that the proposal does not have any direct applicability on the determination of BACT for existing EGUs that require PSD permits to authorize a major modification of the EGU. This statement contradicts EPA's determination that BACT can be no less stringent than an NSPS; thus, the setting of NSPS does establish the BACT floor. The EPA must establish NSPS applicable requirements consistent with previous BACT determinations and EPA's PSD Guidance document.
See section XII.C of the preamble. Until it is finalized, a standard of performance under a proposed NSPS does not establish a BACT floor for an affected source. Of course, a technology that supports a proposed BSER can be considered an "available" technology in a BACT review, and it may ultimately be selected as the BACT, but this same situation could occur even in absence of a proposed NSPS.  The final new source NSPS does not create a BACT floor for modified EGUs. The final standard of performance for modified and reconstructed EGUs creates the BACT floor for modified and reconstructed EGUs.
Determinations of a standard of performance are based on performance of a best system of emission reduction adequately demonstrated, which may not necessarily equate to previous BACT determinations or statements in a permitting guidance document. Additional information may be considered by EPA in determining BSER. The EPA's BSER in this rule is supported by information other than recent BACT determinations and EPA Guidance. 
Two commenters (9034, 10239) stated that non-EGU industries will be adversely affected by the application of NSPS emissions limits in PSD permitting decisions. Despite EPA's assertion that the NSPS is not applicable to modified and reconstructed sources, the EPA will permit (if not encourage) permit writers to consider the NSPS when making BACT determinations. Thus, while CCS has been consistently rejected in BACT analyses to date, permit writers may rely on the NSPS to determine that CCS is now feasible for PSD permits. The commenter stated that it is possible that permit writers would require CCS for other source categories-including those operated by their members. Thus, the commenter's members would be harmed by the establishment of a standard that would collaterally and negatively affect the PSD permitting process.
One commenter (10098-2151) stated that regulating GHG emissions from the manufacturing sector would neither be prudent nor necessary. Most of the sector already has a powerful incentive - energy cost - to implement the only technologically feasible and demonstrated approach to controlling GHG emissions: energy efficiency measures. A GHG NSPS would be an especially inefficient and inappropriate for the manufacturing sector due to their trade exposure and would raise significant additional challenges and obstacles beyond the regulation of EGUs.

The present rule does not create a floor for PSD BACT determination for any other industry sector. However, EPA agrees that a GHG BACT analysis for a source in another industry sector should consider whether pollution controls that form the basis of this NSPS are transferrable to other industry sectors. Of course, because a BACT analysis is a case-by-case analysis, the particular characteristics of sources in other industry sectors should also be considered in assessing the transferability of technology.  The commenters may raise these considerations in GHG BACT reviews for individual facilities.  Even if EPA was not promulgating this NSPS, information regarding control technologies considered in this rule would still be relevant to a BACT determination for any industry sector to which that technology could potentially be applied.  Thus, EPA does not agree that this NSPS has an adverse effects on sources in other industry sectors.
One commenter (9504) stated that neither CCS, nor partial CCS, should be considered in a BACT determination for a non-EGU unit. The commenter stated that in the final rule EPA should state "we do not believe that the content of this rule has any direct applicability on the determination of BACT for any modified or reconstructed sources or any other source, other than a new EGU, obtaining a PSD permit." The commenter noted that EPA's current BACT Guidance for GHG should be amended because it requires consideration of CCS in BACT determinations for new major sources and major modifications of GHG emitting equipment even though the proposed rule states that BSER for new EGUs (only) is "partial CCS." 
According to the commenter, its members are making large capital investments in a variety of manufacturing processes (that include combustion equipment). The commenter stated that if the EGU NSPS rule is not BACT for any part 60 modified or reconstructed source obtaining a PSD permit, it also should have no direct applicability to any non-Part 60 source. EPA should restate its determination that that CCS is not BACT for (a) new gas or biomass fired units and (b) for modifications of any existing major GHG sources. These changes also should be made to EPA's 2011 GHG Permitting Guidance.
The commenter stated that EPA's current GHG Permit Guidance should be amended to allow new non-EGU sources and major modifications of all sources to remove CCS and/or partial CCS from BACT analysis, based on this rule's findings that CCS and partial CCS are not adequately demonstrated for other combustion units and are not cost effective. Based on the record of evidence in this rulemaking, full and partial CCS should not be required during a BACT review for any source of GHG emissions until it is ultimately demonstrated for these and other sources. The BACT determination process is a long and highly expensive undertaking and has always been a target for NSR permit objections and in recent years Title V permit objections. EPA could eliminate these issues by speaking to this issue in this rulemaking. Even if PSD itself is a technology forcing program, since EPA has proposed to find that partial CCS is not adequately demonstrated or achievable for either existing EGUs or new/existing gas plants based on existing information, it would be wasteful for industrial sources to keep chasing that information on the basis of technology transfer principles.
See section XII.C of the preamble and the preceding comment response.  This rulemaking does not involve, and necessarily cannot predetermine, case-by-case BACT determinations. Since CCS is an available technology for many types of source categories, and analyzing all available technologies is important in order to adequately support a BACT determination for any type of source, even without this final rule, many BACT reviews should evaluate CCS as a potential control for GHG emissions (as they have done prior to the issuance of this NSPS). This rule does not preclude consideration of the particular characteristics of non-EGU units in assessing whether CCS or partial CCS can be applied to such units and should be required as BACT (or not) in a particular permit decision.  
One commenter (8957) stated that generally, NSPS are less stringent than BACT standards. NSPS establishes the minimum emission control standard or "floor" for determining a facility's BACT requirements. Under Section 169(3) of the CAA, application of BACT may not result in emissions that exceed those allowed by the applicable NSPS. The point of BACT is to force individual sources to evaluate technology and controls that achieve emission reductions greater than those required for the category-wide performance standards.
The EPA largely agrees with commenter's description of how the NSPS and PSD BACT requirement are designed to work together. However, the dynamic described by the commenter is usually observed when the NSPS rule precedes a BACT determination for a source in that same industry sector. The relationship of these two CAA requirements does not necessarily mean that an NSPS must be less stringent than BACT determinations that were developed before the NSPS. The relative stringency may depend on the timing of an NSPS rule and BACT determinations. As discussed in section IX.C of the preamble, information on pollution control technology evolves over time.   
One commenter (10618) stated that although the proposed rule discusses the inapplicability of the proposed standards to any modification or reconstruction of an existing unit, no changes are proposed to the definition of BACT in the PSD regulations, or otherwise effectively constrain permitting authorities from applying these new standards as a "floor" for purposes of the BACT analysis. Even though the EPA "does not believe" that the standards will be applied in this way, this belief does not amount to an effective binding rule. The commenter stated that the regulatory language must be supplemented to clearly reflect the agency's intent that these standards will not represent a "floor" in any future BACT determination for a modified source under the PSD program.
One commenter (9592) stated that EPA should clarify in both the Preamble and the final rule that NSPS will not set the floor for BACT analysis for unit PSD modifications. One commenter (10788-5257) stated that EPA should avoid conflating a BACT determination with an NSPS BSER analysis. The standards for each determination are distinct. One commenter 10952) stated that by statute NSPS can never be more stringent than BACT for any source within a source category. 

One commenter (10100) stated that to ensure that the final rule does not unintentionally apply to existing units through the BACT determination process, EPA should state in section 60.5508 that the standards do not apply to existing EGUs and should not be considered in determining BACT. The commenter stated that the NSPS has the potential to affect the PSD permitting process because an NSPS standard effectively serves as a floor for BACT determinations. According to the commenter it is possible that a source seeking a PSD permit for a major modification would face legal challenges to any BACT determination that is not at least as stringent as the NSPS. These challenges could affect any PSD permit issued to an existing modified fossil fuel-fired unit because these units cannot meet the proposed standards. The commenter expects such challenges to be made, wasting time and resources. 

One commenter (9591, 9504) stated that they support EPA's contention that the proposal does not have any direct applicability on the determination of BACT for existing EGUs that require PSD permits to authorize a major modification of the EGU. As EPA explains, upon finalization, this rule will establish a so-called "BACT Floor" (e.g., minimum stringency) for PSD permits issued to affected facilities covered by an NSPS. In other words, it would function as a floor to PSD permits for new sources only. The commenter encouraged EPA to finalize clear language in the preamble confirming EPA's determination that this rule will have no precedence for BACT determinations for modified sources. 
See section XII.C of the preamble and the preceding comment response.  While NSPS and BACT determinations are related in some respects, there is nothing in the Act that dictates that an NSPS can never be more stringent than prior BACT determinations for sources in the applicable category. The EPA agrees that BACT determinations and BSER determinations are distinct, and, consistent with the comment, EPA has not conflated the two here. The EPA also agrees that once an NSPS is established, it creates a floor for BACT purposes so that subsequent BACT determinations must reflect at least that level of stringency. As noted above, the NSPS for new sources creates a BACT floor for new EGUs only, and not to modified EGUs. This distinction is not needed to be expressed in the NSPS rule since the Clean Air Act at section 169(3) clearly specifies that BACT cannot be less stringent than any applicable standard of performance under the NSPS. Thus, since the new source NSPS is not an "applicable standard" for a modified EGU, it would not set the BACT floor for a modified EGU unit (in the same way it would not set the BACT floor for a cement kiln).  One needs to be careful in this context to distinguish between units and sources.  NSR generally applies to major sources, while this NSPS applies to units that may be within a source. Thus, it is possible that a standard for new coal-fired units may create a BACT floor for some "sources" that are considered "modified" from an NSR perspective (specifically, adding a new EGU at an existing facility).
One commenter (9425) stated EPA should affirm that since the proposed GHG NSPS would apply only to new sources, the NSPS would not be applicable for the establishment of BACT for an existing source that is restarted. While PSD and BACT requirements may independently apply to a mothballed unit that is brought back online, EPA indicates that nothing in the proposed GHG NSPS acts to determine BSER for existing, modified and reconstructed sources. Thus, the GHG NSPS would have no applicability to a restarted unit that must otherwise comply with BACT.
First of all, this NSPS no longer applies only to new EGUs; it also contains standards of performance that apply to reconstructed and some modified EGUs. Under EPA's reactivation policy, a restarted source is considered a new source under PSD if the shutdown was determined to be permanent  -  which is, in general, means a period of 2 years or more of shut down, along with consideration of other factors. Nothing in this NSPS will change how new sources are viewed under PSD. 
Two commenters (8944, 10098) stated that the EPA should prohibit the NSPS CO2 limit from being adopted as the presumptive CO2 BACT level for simple cycle turbines. The commenter is concerned that the NSPS levels may be misinterpreted and assumed to be BACT for all gas turbines, including simple cycle projects. Such a misinterpretation would effectively ban simple cycle gas turbines. One commenter (8944) suggests that the proposed rule be amended to add the following: "Any emission limits established by this section are not intended to and shall not be used as a basis for establishing for simple cycle combustion turbines what constitutes "best available control technology (BACT)."
For natural gas-fired nominal peaking stationary combustion turbines, the EPA is finalizing the BSER as combustion of "clean fuels" and a corresponding heat input-based standard. This standard of performance will apply to the vast majority of simple cycle combustion turbines, and we think this change in rule applicability and requirements alleviates the concern expressed by the commenter.  
Implications for GHG Applicability Thresholds Related to Permitting
One commenter (10098) stated that the proposed rule undercuts the Tailoring Rule because it could trigger GHG regulation under the PSD and/or Title V program at the statutory thresholds, rather than the Tailoring Rule thresholds. The comment asserted the following points: the EPA's interpretation in the NSPS regulations may not overcome the plain meaning of the PSD regulations; the EPA must withdraw the proposed rule since the EPA's intentions and interpretations may not be sufficient to overcome the plain meaning of the PSD and Title V regulations; and the proposed NSPS may mean that sources would be subject to Title V for carbon dioxide (CO2) at the statutory thresholds.
Several commenters (10051, 3805, 3838) also expressed concern that the EPA may issue GHG NSPS to other source categories that are also inconsistent with the Tailoring Rule, asserting the following points: The EPA's use of the definition of "subject to regulation" in the PSD regulations to address this issue does not eliminate the separate PSD applicability trigger related to section 111. The Tailoring Rule threshold is for "GHGs," while the proposed NSPS applies only to "carbon dioxide." In Christensen v. Harris County, 529 U.S. 576, 588 (2000), the Supreme Court made clear that an agency's interpretation of its own regulations is entitled to deference "only when the language of the regulation is ambiguous" but the PSD regulations themselves appear clear on their face that they require triggering for CO2. The commenters further claim that the proposed fix should be to the PSD and title V rules, not the NSPS rules, because the EPA's fix will only affect EGUs and the fix will have to be repeated in subsequent GHG NSPS. In addition, these comments assert that: The EPA does not address how this issue may play out among the EPA-approved PSD programs, as the interpretation may not literally apply if state and local provisions are not worded exactly as the EPA regulations; that the issue will remain until states revise their regulations and the SIPs are approved by the EPA; and that these states may not interpret their SIPs in this manner.

One commenter (10619) stated that the EPA's plan to issue a SIP narrowing rule would not resolve the issues that states have in maintaining the Tailoring Rule thresholds for GHGs once the NSPS is finalized. The EPA must first issue an ANPR to survey state and local laws and take steps to revise PSD and Title V rules to make the Tailoring Rule thresholds applicable in light of promulgation of the NSPS for GHGs.

One commenter (10618) stated that the EPA should have included SIP narrowing language in it proposal to ensure that a regulatory gap will occur which will result in lower GHG thresholds applying between the date of the proposal and the date of approval of the final NSPS. It is not clear that the proposed solution will resolve the potential for this regulatory gap during this period.

One commenter (9504) stated that whether or not the Tailoring Rule is upheld by the Supreme Court, EPA must revise the PSD regulations to ensure that no NSPS that regulates GHGs triggers preconstruction permitting at the PSD levels. The Commenter is a respondent in Utility Air Regulatory Group v. EPA, S. Ct. Case 12-1146, in which industry asks the U.S. Supreme Court to reverse the holding of the U.S. Court of Appeals in Coalition for Responsible Regulation, Inc. v. Envtl. Prot. Agency, 684 F.3d 102 (D.C. Cir. 2012), upholding the GHG Tailoring Rule. NEDA/CAP. Commenter further stated that in the lawsuit the EPA does not have legal authority for regulating GHG's under the PSD and Title V program. Commenters also stated that however as EPA points out in the January 8, 2014 proposed NSPS rule for EGUs, 40 CFR Section 51.166(b)(50), could independently trigger PSD when an NSPS is issued for GHGs, regardless of the outcome of the Supreme Court's review of the GHG Tailoring Rule, re-establishing Clean Air Act's permit definitions of "major source" at 100 and 250 tons for PSD and 100 tpy for Title V. See 79 Fed. Reg. 1420, at 1488.
One commenter (10660) stated that EPA should amend the PSD rules to ensure the final NSPS does not cancel out the Tailoring Rules GHG thresholds. Sources would look to the PSD regulations to the thresholds, not the Part 60 regulations that do not affect their particular industry. There will be a regulatory gap where the SIP does not incorporate or has been interpreted to incorporate 40 CFR Section 51.166(b)(48) and it is unclear how the NSPS will apply to states currently under a FIP for GHG permitting. The EPA should proceed with a separate SIP narrowing rule to exclude GHGs below the 100,000/75,000 tpy threshold and to clarify NSPS applicability for states that have incorporated 40 CFR section 51.166(b)(48) and states under a FIP for GHG permitting. The EPA should analyze state regulations to see if SIP revisions are necessary to maintain the Tailoring Rule thresholds before finalizing the proposal. Absent such an analysis, finalizing the rule may trigger lower permitting thresholds for projects in affected states. 

Three commenters (10095, 9198, 9648) also took issue with the proposed approach to ensure that the Tailoring Rule GHG thresholds will continue to apply after the NSPS is finalized and asked instead that the PSD regulations be revised for this purpose. One of these commenters 10095) added that revising the PSD rules will allow states adequate time to revise their SIPs and that the proposed approach will lead to SIP adoption issues in some states. One of these commenter (9198) also requested that EPA revise the "NSPS trigger provision" of the PSD rules, 40 CFR 51.166(b)(49)(ii), as follows: 
  "Any pollutant that is subject to any standard promulgated under section 111 of the Act; except that GHGs shall be subject to the applicability provisions and thresholds for GHGs set forth in 40 C.F.R. Section 51.166(b)(48)."
Another of these commenters (9648) added that failure to revise the definition of "regulated NSR pollutant" will result in GHGs becoming a "regulated NSR pollutant" with no significant emission rate (i.e. a rate of zero) and asked for the EPA to simply revise the definition of "Regulated NSR Pollutant" at 51.166(b)(49)(ii), and include similar language in the title V rule, as follows:
"(ii) Any pollutant that is subject to any standard promulgated under section 111 of the Act, except for GHG in accordance with (b)(49)(iv) below;" 
Two state commenters (9646, 10870) said that after the NSPS is finalized, their approved PSD/NSR regulations and SIPs will not need to be revised to ensure that the Tailoring Rule thresholds will continue to apply. Another state commenter (0840) stated that the State plan they have developed should be adequate to comply with the regulations and the EPA should approve it, citing the 10th Amendment. One state commenter (10869) stated the PSD thresholds of the Tailoring Rule should continue to apply after the NSPS is finalized. Another state commenter (9423) recently adopted the Tailoring Rule thresholds so that GHGs are "subject to regulation," so that once the NSPS is finalized and the EPA approves the Tailor Rule changes in the SIP, they can interpret the SIP to apply the Tailoring Rule thresholds. 
In our January 8, 2014 proposal, the EPA proposed to adopt regulatory language in 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 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 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 specified requirements, including application of Best Available Control Technology (BACT) to each pollutant subject to regulation under the Clean Air Act. 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, the 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 Clean Air Act. 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. 75 FR 17004 (Apr. 2, 2010). On the date the EPA's regulation of GHG emissions from motor vehicles first took effect, GHGs became subject to regulation under the CAA and the fourth subpart of the 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 Clean Air Act 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 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 Clean Air Act. 79 FR at 1487-1488. As discussed above, the definition of "regulated NSR pollutant" in the PSD regulations contain a separate PSD trigger for pollutants regulated under the NSPS, 40 CFR 51.166(b)(49)(ii) (the "NSPS trigger provision"). Thus, when greenhouse gases become subject to a standard promulgated under section 111 for the first time under this rule, then PSD is triggered for that air pollutant on an additional basis besides the regulation of greenhouse gases from 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 were independently triggered for greenhouse gases by the NSPS that the EPA is promulgating in this rulemaking. 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 Clean Air Act 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 insure 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 proposed language makes clear that the thresholds for GHGs in the EPA's PSD definitions of "subject to regulation" apply through the second subpart of the definitions of "regulated NSR pollutant" to GHGs regulated under this rule.
     
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 the 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 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) required to obtain a PSD permit. 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 Best Available Control Technology (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 the 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 to make such revisions.
     
The practical effect of the Supreme Court's clarification of the reach of the Clean Air Act is that it eliminates the need for Step 2 of the Tailoring Rule and subsequent steps of the phase in that the EPA had planned to consider. This also eliminates the possibility that the promulgation of GHG standards under section 111 could result in additional source 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 Clean Air Act.
     
The Clean Air Act 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 that would establish a de minimis threshold level for permitting GHG emissions under PSD. As part of this proposed 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. This revised rule will then provide a framework that states may use when updating their SIPs consistent with the Supreme Court decision.
      
While the rulemaking described above 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 section 111, the EPA has concluded that it continues to be appropriate to adopt the proposed language in section 60.5515 (subpart TTTT). Because the EPA is not finalizing the proposed regulations in subparts Da and KKKK, it is not necessary to adopt the comparable provisions that the EPA proposed in sections 60.46Da(j) and 60.4315(b).

The EPA has evaluated section 60.5515 in light of the Supreme Court decision and the comments received on the question of whether this 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 section 111 does not make this BACT applicability level for anyway sources effectively inoperable. The language in section 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 Code of Federal Regulations. As a result of these steps, the language of final section 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 section 60.5515 for this purpose without substantial change.
      
As to the concern expressed by some commenters that revisions to Part 60 alone are not sufficient, the rulemaking described above will include proposed revisions to the PSD regulations in part 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 discuss 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 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 section 111, the EPA believes it will 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 section 111 standards for GHGs, the EPA will need to consider adding provisions like section 60.5515 to other subparts of part 60. In a separate rulemaking finalized concurrently with this rule, the EPA is also finalizing corresponding edits to 40 CFR 60.5705 in Subpart UUUU to clarify that the regulated pollutant is the same for both the CAA section 111(b) and section 111(d) rules. As of this time, the EPA has not proposed GHG standards for other source categories under 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 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 section 111. However, the language in section 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 Clean Air Act. See 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 section 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.
      
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 the EPA-approved State title V programs, though the EPA also issues title V permits to sources located in certain areas, such as tribal lands, through the permitting program contained in 40 CFR Part 71.
      
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 the 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 the 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.
      
With respect to the public comments that the proposed rule could undercut the Tailoring Rule because it could trigger title V permitting obligations for GHG or CO2 at the statutory major source thresholds, the EPA does not agree that this would result. As explained elsewhere in this rule, after the Supreme Court's decision in UARG v EPA, the 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. The EPA intends to conduct future rulemaking action to make the appropriate revisions to the operating permit rules to respond to the Supreme Court decision and the D.C. Circuit's amended judgment after that decision. To the extent there are any issues related to the potential interaction between the promulgation of CAA section 111 requirements for GHGs and title V applicability based on emissions above major source thresholds, the EPA expects that those revisions to the title V provisions would inherently address them. There will also be an opportunity for the Agency to consider, and for the public to raise, any such issues during that rulemaking. The EPA believes that it is more efficient to address any such issues in a comprehensive fashion through that rulemaking. With respect to commenters' concerns about potential implications for the Tailoring Rule regulatory thresholds for title V, to the extent that those thresholds remain in place, the EPA does not believe that this rulemaking should undermine those thresholds for the reasons explained in the proposal. 79 FR at 1489-90.
 
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.

Title V Permitting Fees
One commenter (10554) stated that the NSPS rulemaking is not the proper place to propose a change to the fee calculation methods under the operating permit rules.
One commenter (9198) stated that the EPA's decision to address title V fees for GHGs for a broad range of stationary sources that are not limited to EGUs within the proposed GHG NSPS rulemaking may result in fewer commenters having knowledge of the proposed approach and the opportunity to comment, as compared to a separate rulemaking dedicated exclusively to fees. Another commenter (9666) believes permitting authorities may not provide detailed comments on this rulemaking action because the NSPS is limited to a single source category, so some states and sources in other source categories may be unaware that this notice contains a part 70 presumptive minimum cost adjustment proposal.

One commenter (9198) stated that GHGs emitted from biogenic sources present unique considerations and will affect a broad range of stationary sources. The commenter believes GHG emissions from biogenic sources must be specifically considered in the fee context and that a separate rulemaking would better facilitate these considerations, so long as the separate rulemaking could be completed before GHGs became regulated pollutants for the purposes of title V fee requirements.

One commenter (9648) stated that the proposal was too vague and not defined enough for states to comment on the details of any of the proposed GHG "cost adjustment" options.
Despite adverse comments on the use of this NSPS rulemaking to revise the Title V fee rules, the EPA believes it is appropriate to move forward with final action amending the title V fee regulations as part of this rulemaking action. As we explained in the preamble for the proposal and elsewhere in the final rule, 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. The EPA further believes that 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 opportunity to comment, the EPA believes sufficient opportunities were provided on the fee rule changes because the proposal met all applicable public participation requirements and we conducted additional public outreach, including to state and local permitting authorities, on 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. 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.
      
In response to the comment that GHG emissions from biogenic sources must be considered in the fee context and that a separate rulemaking would better facilitate these considerations, we disagree for several reasons. There are no statutory requirements with respect to the treatment of fees for GHG from biogenic sources, we made no specific proposal related to the treatment of GHG from biogenic sources with respect to fees and the final rule makes no distinctions with respect to the type of sources that are subject to fees. We explain in response 9.7.4 of this RTC the reasons we believe the consideration of title V fee issues related to GHGs from biogenic sources do not necessitate any delays in finalizing this rule. Also, it is within the EPA's discretion for rulemaking to not conduct a separate rulemaking action to address any fee considerations with respect to biogenic sources as we explain in response to comment grouping 1 of this RTC.

The EPA also disagrees that its proposal was impermissibly vague. The EPA provided a thorough discussion of our rationale in the proposal, including the basis for the GHG adjustments, and we proposed regulatory text to implement our proposal. We explained in the proposal that support for the cost adjustment for GHGs under option 1 is contained in several analyses performed by the EPA and approved by the OMB related to the effect of the addressing GHG requirements in operating permits. These analyses have been placed in the docket for this rulemaking. The analyses include: the Regulatory Impact Assessment (RIA) for the Tailoring Rule (see Regulatory Impact Analysis for the Final Prevention of Significant Deterioration and Title V Greenhouse Gas Tailoring Rule, Final Report, May 2010); the part 70 ICR change request for the Tailoring Rule (which was based on the RIA for the Tailoring Rule); and the current ICR for part 70 (EPA ICR number 1587.12; OMB control number 2060 - 0243).
Several commenters (3862, 9198, 9381, 9425, 9504, 9591, 9666, 10023, 10048) supported the proposal to exempt GHGs from presumptive fee calculations. Many of these commenters agreed that using the existing fee rate for GHGs would be inappropriate because it would result in excessive fees, far above the reasonable costs of a title V permit program. The commenter also added that states that believe that the presumptive minimum is not adequate can exercise their right to establish a different schedule. The commenter stated that EPA's finalization of the GHG exemption would facilitate states not needing to forgo use of the presumptive minimum approach and develop alternative fee schedules simply to avoid collection of fees that may not be needed. Supporter (9504) pointed to Congress's exclusion of CO from fee requirements because of high emission rates compared to conventional pollutants as support for the GHG exemption and stated that the issuance of the NSPS for GHGs could trigger title V permits fee in excess of $47 a ton of GHGs emitted by any permittee.
On the other hand, some commenters (8909, 9730, and 10394) opposed the proposed GHG exemption because they believe exempting GHGs from fee calculations may negatively impact the state' ability to recover fees sufficient to cover all title V permitting program costs. One commenter (9739) added that some states are barred from exceeding minimum requirements imposed by the EPA and finalizing the GHG exemption may hinder states' ability to collect fees sufficient to fund their operating permit programs. One commenter (10017) further stated that EPA's proposed approach departs from 40 CFR §70.9, and that the fees implemented for CO2 should be based on the same $25/ton presumptive minimum approach used for other title V pollutants, since this approach is consistent and provides a baseline nationwide for funding the title V program. 
The EPA is taking final action to revise the definition of regulated pollutant (for presumptive fee calculation) in 40 CFR §70.2 and regulated pollutant (for fee calculation) in 40 CFR §71.2 to exempt GHG emissions. This regulatory amendment will have the effect of excluding GHG emissions from being subject to the dollar per ton ($/ton) fee rate set for the presumptive minimum calculation requirement of part 70 and the fee calculation requirements of part 71. The majority of comments received on the exemption issue were supportive, including from state and local permitting authorities. We are finalizing this portion of the proposal for the same reasons we explained in the preambles to the proposed and final rule notices, 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) are consistent with the CAA requirements of section 502(b)(3)(B)(i).
The EPA disagrees with the adverse comments that some states are not allowed to do anything beyond the minimum floor set by EPA and that following the $25/ton approach for GHGs is consistent with and provides a nationwide baseline for fees. On the first adverse comment, part 70 allows any state to use either the presumptive minimum approach of §70.9(b)(2) or the detailed accounting approach of §70.9(b)(5). States using the presumptive minimum approach must collect at least the minimum fee revenue target, but they are free to collect more than the minimum, and a state must collect more than the minimum if the minimum would not be sufficient to fully fund all the state's part 70 program costs. Any state that wishes to set a fee revenue target below the minimum may switch to the detailed accounting approach, provided the detailed approach results in sufficient funding for the program. Also, on the second adverse comment, the Act does not require the calculation of $25/ton multiplied by tons of regulated pollutants (for presumptive fee calculation) to necessarily be the only way that a state may demonstrate it has sufficient funding for the program, even if the state uses the presumptive minimum approach. CAA section 502(b)(3(B)(i) allows the EPA to approve a state program that collects at least the presumptive minimum "or such other amount as the Administrator may determine reflects the reasonable costs of the permit program" and the "or such other amount" provision is the statutory basis for the detailed accounting approach of part 70 and the GHG adjustment we are making to the presumptive minimum approach of part 70 to account for GHG permitting costs.
Several commenters (10240, 9730, 8909, 5537, 8957, 9646, 10394, 10095, 10243, 10619; 9317; 9423; 9765; 8213) supported the EPA's proposal to allow states to set their own fee schedules to provide various ways for fees to be charged to sources. One commenter (5537) stated that states should have the flexibility to decide how to charge title V fees according to their own circumstances, including not charging any fees based on GHG emissions if a state already collects sufficient fees to meet the program support requirements. One commenter (10243) recommended that the EPA preserve flexibility for states to develop their own fee collection process and asked that states be allowed the option of making no GHG adjustment if existing fees are adequate to cover the additional costs of GHG permitting. The commenter stated that, since most sources would already be subject to part 70 for other pollutants, the incremental costs for GHG permitting are minimal and  significant additional fees should not be needed to cover the reasonable costs of an operating permit program. One commenter (9198) supported the EPA's determination that it will not require fees for GHGs if a state can demonstrate that its fees are sufficient to cover the reasonable costs of its operating permit program, and not to propose any new requirements for states that do not use the presumptive minimum approach.
One commenter (10095) stated that the EPA should not require states to adopt the proposed alternatives to the presumptive minimum approach, and that the EPA should continue to provide flexibility in developing fee structures to states that do not use the presumptive fee approach. One commenter (9507) stated that part 70 states should be allowed to determine the level of effort required to satisfy these requirements and charge for those services accordingly.
      
One commenter (10394) stated that in the commenter's state, a recently enacted proposition limits fees that state or local government can charge to no more than necessary to cover reasonable regulatory costs. Therefore, in order to be able to make this showing, the commenter believes that the EPA should provide the flexibility to the state to base the cost of fee adjustment on either option 1 or 2 to cover the costs of the state. Therefore, the commenter requested that the EPA leave open the option of establishing fees based on time and materials or on an emissions basis, for local and state agencies that choose either route to establish their fees.
As explained in the final preamble, the EPA believes the final rule will not limit states' flexibility to charge fees to particular sources in order for them to collect annual revenue from all sources that they have determined would be sufficient to fully fund the program. See CAA §502(b)(3); 40 CFR §70.9(b)(3).
If a state does not wish to use the presumptive minimum approach of part 70 to demonstrate they have sufficient funding for the program, it may use the "detailed accounting" approach instead. The detailed accounting approach involves a state-specific demonstration "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. If a state believes that the existing fee collection is sufficient to fully cover program costs, they collect no more than the minimum required under the originally promulgated presumptive minimum approach [$25/ton multiplied by regulated pollutants (for presumptive fee calculation), without a GHG adjustment], and they do not wish to adopt the GHG adjustment required by the final rule, then the state must switch to the detailed accounting approach. Such a switch will trigger a requirement for the state to submit a program revision to the EPA. Among other elements, the program revision submittal must include a demonstration that the amount they will collect will be sufficient to fully fund the program.
      
Also, as described previously in this section of the RTC, a state always has flexibility under the presumptive minimum approach to collect more revenue than the absolute minimum allowed, so if a state has adopted the presumptive minimum approach and it currently charges more than the minimum, the state may continue to use the presumptive approach if the amount they will collect in the future would continue to meet or exceed the revised presumptive minimum of the final rule.
       
The EPA believes that most states that implement the presumptive minimum approach will likely need to make alterations to their title V fee collection system in order to comply with the EPA's final rule. 
       
The EPA notes that the final rule does not revise any fee requirements for states that rely on the detailed accounting approach. However, these states 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.
Several commenters (9425, 9507, 9780, and 10660) generally supported the concept of increasing permitting fees to cover the costs of GHG permitting. One commenter (10619) stated that they have no objection to the alternative GHG adjustment approaches. Another commenter (9591) stated that fees should only be increased to the extent necessary to cover the increased cost of GHG permitting. One commenter (9425) stated that any fees associated with CO2 emissions should cover the cost of processing CO2 permitting only and not be used to supplement other title V program costs. One commenter (9507) agreed that the title V fee program is a suitable mechanism for funding incremental program costs associated with new source standards or new source permitting attributable to GHG rules. The commenter noted that these costs, to the extent they exist, should properly be covered by permit application fees and borne by proposed new source project developers.
Several commenters did not support any cost adjustment to account for the additional costs of GHG permitting. One commenter (9666) stated that the EPA has not provided adequate support for a conclusion that a cost adjustment procedure is necessary to ensure that fees collected will be sufficient under the presumptive minimum approach. One commenter (10554) argued that no cost adjustment is needed, but stated that if EPA finalizes a GHG cost adjustment, any additional fees charged should be consistent with the incremental costs of GHG permitting and should be used solely for the title V program. One commenter (9780) stated that before finalizing any adjustment option, the EPA should consider whether current fees already cover some or all of the costs of GHG permitting, and that fees should only be increased enough to cover the actual costs that are not currently covered. One commenter also suggested that GHGs can be excluded from fees entirely because permitting costs are presumably covered by existing fees, because there are a minimal number of GHG permit terms for incorporation in title V permits, facilities with GHG PSD permits may already have title V permits, the GHG Emission Reporting (40 CFR. part 98) requirements are excluded from permits, and there are no current GHG technology standards. One commenter (9780) alleged that current fees are already sufficient to cover the costs of adding new CO2 requirements under section 111 into permits, rendering any fee adjustment unnecessary. Another commenter (9198) argued that no GHG adjustment is needed because sources with GHGs will also have emissions of non-GHGs subject to fees, and the costs of permitting will be accounted for without charging additional fees related to GHGs. One commenter asserted that the GHG emission limit components of most title V permits are likely to be "hollow," because in most cases, they will not require additional control technologies other than those that would already be required to control other pollutants. Moreover, the commenter argued, costs of state agencies and the EPA of inventorying GHG emissions for title V purposes are zero because GHGs must already be reported under the EPA's Mandatory GHG Reporting Rules.

One commenter (9198) stated that they do not believe there is a sufficient basis at this time to evaluate the fee implications of GHG emissions, especially where the EPA has not finalized an approach to account for GHG emissions from biogenic sources. Further, the commenter questions whether the EPA has received sufficient input from states and whether states are able to quantify incremental costs associated with GHGs, given the nascent state of GHG permitting. Finally, the commenter is concerned that cost adjustments based on GHG emissions will impose a financial burden on sources that emit GHGs in addition to fees they already pay for non-GHGs. One commenter (10618) stated that the EPA has not demonstrated that any adjustments are necessary given that the proposed NSPS will not expand the universe of sources subject to regulation, EGUs and other sources would already be subject to title V based on non-GHGs that are subject to fees, and there is no basis to conclude that the current fees are inadequate.

Another commenter (10660) stated that the EPA should exclude GHGs from the presumptive fee calculation and make no other GHG fee adjustments before the development and finalization of Step 4 of the Tailoring Rule. The commenter argued that there is currently no basis to charge additional fees to account for GHG permitting expenses, but after Step 4 of the Tailoring Rule is finalized, the EPA may be able to justify adjusting the permitting thresholds. The commenter noted that finalization of Step 4 of the Tailoring Rule will lower the GHG applicability thresholds and increase the number of PSD permits and sources subject to title V permitting, which may potentially warrant the addition of a fee to cover GHG permitting costs.

Several supporters (9666, 10048, and 10023) stated that the EPA should leave the issue of any cost adjustment to a future rulemaking under part 70 when broader notice can be provided, and additional information on actual costs will be available from, for example, the update of the ICR for the part 70 rule.
As explained in the proposed rule and the final preamble, 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). Consistent with CAA §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.
To the extent that commenters intended to argue that the adjustments we proposed would exceed the actual costs of GHG permitting, no commenters provided any information or analysis to support that position. Some commenters did state that the costs associated with GHG-related permitting should be minimal because few or no applicable requirements will apply to GHGs. As stated earlier in this notice, EPA's cost estimate for the proposal concerned the incremental costs of GHG permitting for any source, not just those that would have, at the time of the analysis, triggered the requirement to get a permit based on GHG emissions or applicable requirements.
      
Concerning the comment that the costs to state agencies and the EPA for inventorying GHG emissions for title V purposes are zero because GHGs must already be reported under the EPA's Mandatory GHG Reporting Rules, we disagree because the title V and GHG reporting rules do not require GHG emissions to be measured in the same manner and for the same sources. For example, the Mandatory GHG Reporting Rule generally requires reporting of actual emissions, but not for all types of sources that may be required to get a title V permit, while the title V rules generally require emissions to be reported in terms of actual emissions and/or potential to emit.
In response to the statements that any GHG cost adjustment should be limited to the costs of adding the NSPS for EGUs into a permit and that there are no costs for Title V because the costs are covered under the PSD programs, the EPA disagreed with these statements. The GHG adjustment of the final rule do not include the costs of implementing particular standards, such as any particular NSPS, or other permitting requirements, such as PSD permitting requirements, through title V permits. Rather, as noted previously, the GHG cost adjustment is designed to account for the incremental cost of analysis to address the GHG emissions and applicable requirements for any source.

Despite some comments received to the contrary, the EPA does not believe it is appropriate to delay the finalization of the GHG adjustment. The EPA does not believe such delays would be consistent with CAA § 502(b)(3)(A) because states have been incurring costs attributable to GHG permitting for several years now and increased fees must be collected to cover the increased costs. The regulatory changes being finalized in this action provide the states with optimal flexibility and sufficient funding to implement their operating permit programs. Concerning the request for delay based on the completion of the next ICR renewal process, we respond additionally that the ICR renewal process is not required to be completed until after the time that EPA intends to finalize this rulemaking, and we have adequate information at this time to make GHG adjustments to title V programs costs; thus, we will not delay the adjustments until the next ICR renewal is completed. 

Concerning the Tailoring Rule, subsequent to the Supreme Court's decision in UARG v. EPA, the EPA provided next steps and preliminary views on the application of Clean Air Act permitting programs to GHGs in a July 24, 2014 memorandum. In the memorandum the EPA explained that it does not intend to take further action on "Step 4" of the Tailoring Rule.  As explained in the preamble to the final rule, the EPA believes that it currently has a sufficient basis to finalize the revisions we are making to the fee provisions of the title V rules and we do not believe that we need to wait until the finalization of Step 4 of the Tailoring Rule before taking this final action with respect to fees.  The EPA's review of the effect of the Supreme Court decision on the burden hour assumptions for the GHG review activities under proposed option 1 is that the effects are not significant enough to warrant revision of the burden hour assumptions in the final rule. Proposed option 1 was based on the assumption that permitting authorities would need to evaluate all permit applications for initial permit issuance, significant and minor permit modifications, and permit renewals for GHG issues (even if there are no applicable GHG requirements). Even after the UARG v. EPA decision, permitting authorities will continue to need to evaluate for GHG issues for sources applying for a title V permit and for permit modifications and renewals for existing permits, and we do not anticipate that the decision will significantly affect the total number of such evaluations that will occur in any given year compared to the assumptions in our analysis, which were based on the incremental costs of GHG permitting for any source. Thus, we are finalizing the burden hour assumptions as they were proposed. See NSPS proposal at 1494 and the supporting statement for the 2012 part 70 ICR renewal. Also, as discussed previously, we remain committed to collecting and analyzing additional data on costs and we may adjust the burden hour assumptions or other aspects of option 1 in a future rulemaking, if needed.
      
Concerning the request for delay related to developing an approach for biogenic CO2, the fee rule changes being finalized in this action will not be affected by any subsequent EPA's decisions regarding the treatment of biogenic sources. The fee provisions of the final rule do not depend on the type of source or its emissions. Also, the EPA notes that the term "GHG" includes CO2 as a constituent.
      
Finally concerning requests for delays to collect additional information to set fee adjustments for GHGs, the EPA notes that we believe we have an adequate basis for making the GHG adjustments at this time, as we explain in response 9.7-1 of this RTC, and we remain committed to collecting and analyzing additional data on costs attributable to GHG permitting for operating permit programs. We may adjust the GHG cost adjustments in future rulemakings if necessary to comply with the requirements of the Act.
One commenter (9504) stated that they generally agree with EPA's proposal to include an additional cost for each GHG-related activity of certain types that a permitting authority would process (option 1) to the extent that it is used to cover the cost of incorporating new permit terms for newly applicable NSPS requirements or new GHG requirements, but the commenter does not support codifying option 1. The commenter does not understand why incorporation of new PSD GHG requirements in a permit would require much additional effort, but incorporation of the NSPS standards into a permit might be more difficult than the EPA proposes, and that there would be no additional administrative burden for administering fees. One commenter (8909) stated that basing the cost adjustment on activities performed by states is more appropriate than on a cost-per-ton basis. One commenter (10660) that supports option 1 recommended that the EPA set a maximum number of annual hours that can be used to set a fee under option 1, which would overstate the actual costs of the program. If option one is finalized, the fees should be "annualized," since most of the activities do not occur on an annual basis. 
Regarding the three activities that the EPA proposed to include in its alternative fee calculation, some commenters (9730; 8909; 9646; 9765) stated the list is not comprehensive. The commenters noted that all three of the activities are associated with the writing of title V permits. The commenters alleged that the proposed list of activities does not address the burden of public notice and the significant resources required if hearings are requested and held or the costs of managing and enforcing the title V program as reflected in Section 502(b)(3)(A) of the CAA and the EPA regulations at 40 C.F.R. 70.9(b)(1), both of which list specific costs that title V fees are to cover. The commenters noted that these statutory and regulatory provisions include, for example, the costs of implementing and enforcing the terms of title V permits, tracking emissions, and compliance reporting. The commenters argued that the GHG adjustment should be based on the existing statutory list rather than the less-comprehensive list of activities proposed by the EPA.

Another commenter (8957) recommended the EPA include title V implementation costs such as inspection, enforcement, emission testing, emissions monitoring and tracking.
      
A separate commenter (9504) stated that the EPA should only list activities to account for permitting authorities to review and act upon an application for a title V permit renewal and incorporation and/or modification of title V permits with new applicable requirements at the time of permit renewal. 
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 is also finalizing the list of activities as proposed, aside from a minor revision of the regulatory text for the second activity, and some clarifications of the meaning of the first and second activities, to ensure consistent implementation of the fee provisions.
       
Several commenters asked for certain specific GHG-related activities to be added to the three activities we proposed under option 1, including providing public notice, conducting hearings, tracking emissions, managing the program, undertaking enforcement, and compliance costs. The EPA directs commenters to the information provided in the part 70 ICR and RIA for the Tailoring Rule, which the Agency used as a resource in estimating the increased burden to permitting authorities associated with GHG permitting. The ICR change request for the part 70 rule with respect to the Tailoring Rule, approved by OMB, clarifies that the EPA included public notice and hearings in the estimates for the activities of "GHG completeness determinations (for initial permit or updated applications)," and the OMB change request also notes that "GHG evaluations for a permit modification" and "GHG evaluation at permit renewal" were also increased by a percentage to account for all underlying tasks necessary to perform such activities, which would include public notice and hearing, if required for the activity. With respect to tracking emissions, enforcement and compliance costs, managing the program, inspection, emissions testing and emissions monitoring, the EPA did not propose specific incremental GHG costs for these activities because the RIA for the Tailoring Rule, and the part 70 ICRs did not find any incremental GHG burden for these activities. The current part 70 ICR includes many of these activities in the baseline burden under "program administration," "reviewing monitoring and compliance certification reports," and "annual enforcement activity reporting" (see page 9 and Table 2 in the current part 70 ICR). The RIA for the Tailoring Rule also did not determine there was any incremental GHG burden for "emissions testing and emissions monitoring." The EPA also notes that these activities are typically costs for subject sources that are required by underlying emissions standards, rather than costs for permitting authorities, and GHGs are not subject to any ambient standards that may require permitting authorities to conduct background emissions monitoring for ambient impact assessment purposes.
      
The EPA disagrees with the comment that there would be no additional costs for GHG permitting because incorporation of PSD GHG requirements into a permit would not require much additional effort and that there would be no additional administrative burden for administering fees. As we have explained in the preambles to the proposed and final rule, the basis for the GHG adjustments is the additional burden for permitting authorities to conduct GHG completeness determinations and GHG evaluation for any initial permit application, permit modification, or permit renewal, regardless of the type of source, its emissions, or its applicable requirements. Also, the EPA found no additional burden for administering fee requirements in its analysis of additional burdens for GHG permitting. See response 9.7-1 of this RTC for more on the basis for the EPA proposed GHG adjustments.
   
Concerning the fee being "annualized," it is unclear to what the commenter is referring because the preamble clearly explained that the GHG adjustments would be added to current fee calculation provisions of the part 70 and 71 rules, which require annual calculations.
      
One commenter was concerned that the activity-based adjustments we proposed (option 1) would overstate the actual costs of the programs and recommended that the EPA set a maximum number of annual hours to be charged to sources (we assume the purpose of this would be to cap the annual GHG fee adjustment for a given state or source). In response to this concern and for other reasons, we made one minor revision to the regulatory text of the second activity and we make certain clarifications as to the meaning of the certain of the activities listed in the final rules. These clarifications and revisions will serve to limit the GHG adjustment amounts that may be counted in certain circumstances and avoid confusion when states or sources calculate the amounts of the adjustments under the final rules.
      .
The first clarification for the final option 1 approach concerns the activity of "GHG completeness determination (for initial permit or updated application)." We have not revised the regulatory text but we clarify that 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. This would be 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 and will ensure that the GHG adjustment will be reasonable and consistent with the actual costs. Any updates to an initial application are included in a single "GHG completeness determination," rather than as a separate activity that is counted 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 second clarification to the final option 1 approach is to revise the regulatory text of "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.

The EPA is also finalizing the third activity as "GHG evaluation at permit renewal." This activity covers the processing of all permit renewal applications and will involve evaluations of whether any GHG applicable requirements are properly included.
In response to EPA's proposed alternative to increase the dollar per ton rates used in the fee calculations for each non-GHG fee pollutant (option 2), one commenter (9507) stated that they do not disagree with establishing option 2 in states where the EPA is involved with PSD permitting, but not in states where GHG review is part of the normal PSD permitting process, which includes fees. Some states have expedited permit review procedures that may be more efficient than the EPA assumes, so they believe the EPA should not dictate to states on the minimum length of time required to review a permit application.
One commenter (9504) opposed option 2 because the commenter believes it is not fair to charge sources for GHGs on the basis of their other regulated air pollutants (such as VOCs), unless the EPA can demonstrate there is a relationship of GHGs to non-GHGs. In other words, it is not reasonable to require states to raise fees for VOC sources that do not emit GHGs to cover the costs of regulating GHGs. One commenter (9780) stated that the 7 percent adjustment factor of option 2 should not be applied to sources emitting only non-GHGs that are subject to title V, since the EPA has not demonstrated that an increased fee is needed for all regulated pollutants to cover title V costs of permitting all new, modified, reconstructed and existing sources, and that this will result in excessive costs without adequate justification.

One commenter (10017) provided an alternative dollar per ton charge than that proposed by the EPA in option 2. The commenter suggested adding a prorated, tailored presumptive minimum fee for CO2 under the existing $25/ton consumer price index (CPI) adjusted fee structure, which would minimize complexity and ensure uniform and timely implementation of funding to implement GHG regulations for title V facilities. Another commenter (9730) stated if the EPA is unable to establish an adequate and reasonable option 2 GHG adjustment, the EPA should at a minimum consider an emissions-based fee that is a simple adjustment to the per-ton calculation in the existing presumptive minimum fee by dividing a source's GHG emissions by 1,000. The commenter stated that this approach was appropriate because under the Tailoring Rule, the GHG emissions threshold for title V is 100,000 tons per year (tpy) of CO2e, compared to a basic threshold of 100 tpy of regulated air pollutants - a difference of a factor of 1,000. The commenter noted that this would equate to a simple presumptive minimum fee (based on the original fee of $25 per ton of regulated air pollutants) of $25 per thousand tons of carbon dioxide equivalent (CO2e), with the base of $25 adjusted by the CPI.
As explained in the final rule preamble, the EPA is finalizing GHG adjustment 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. However, as noted by some commenters, the option 2 approach is tied to the emissions of non-GHG air pollutants, which are not directly related to the costs of GHG permitting. 
Also, we disagree with the comment that there would be no costs for GHG permitting under title V because the reviews would already occur under the PSD program, which also charges fees. We explain in response 9.7-1 of the RTC that the costs of GHG permitting we address in this rulemaking are title V costs, not PSD costs. Section 502(b)(3)(A) requires all title V costs to be covered by title V fees only and this rulemaking action does not address the costs of GHG permitting for the PSD program.
      
As an alternative to the options proposed by the EPA, some commenters asserted that the EPA should make a GHG cost adjustment using a separate, but reduced fee rate ($/ton) for GHGs. We, however, believe that the option 1 approach of the final rule will be more equitable for sources and more representative of actual costs because option 1 considers the costs of the actual permitting activities performed by a particular permitting authority, while any emissions-based approach would not be as directly related to actual costs incurred by permitting authorities. Also, since EPA is not finalizing option 2, we need not further address commenters' points about how option 2 should have been structured or what basis was required to support it.
Concerning the comment that the GHG fees should only cover the costs of GHG permitting, we agree in a general sense to the extent that the commenter is agreeing with our proposal to increase revenue to cover the additional costs of GHG permitting through the GHG adjustment of proposed option 1. The proposal explained that we estimated the costs of GHG permitting and have designed a GHG adjustment, which we are finalizing, to recover only those costs.One commenter (9648) stated that it is unclear why the EPA is applying the results of the GHG Tailoring Rule implementation to pre-define CCS related costs under section 111, as the two programs are completely different in terms of the expected agency resources required.
The EPA did not pre-define CCS costs as Title V costs in either its proposal or in this final rulemaking action. We made no statements in the proposal concerning Title V fees with respect to CCS costs and make no such statements in the final rule. As we explained elsewhere, the purpose of this rulemaking action was to address the cost of GHG permitting for permitting authorities as a whole, without respect to particular emissions or emissions standards.
One commenter (9003) stated that they rely on emissions fees to support the costs of the operating permit program. The commenter noted that in recent years, there have been significant reductions in emissions and the associated fees due to closures and fuel switching at coal-fired utility boilers. The commenter alleged that title V fees will continue to be impacted as the EPA moves forward with regulations for GHG emissions from utility boilers and other rules that result in significant reductions in emissions. The commenter argued that the EPA should consider the costs to states to implement this rule and other future rules.
To the extent that the commenter is suggesting that the EPA should consider adjusting the Part 70 presumptive minimum and Part 71 fee collection regulations to account for the costs to permitting authorities for implementing the section 111 standards and future rules, such as future emissions standards, we respond that such considerations are beyond the scope of this rulemaking action. We have explained elsewhere that the GHG adjustment of this rule are not related to the costs of implementing any particular emissions standards and this rule is also not related to considering the costs of implementing any particular future emissions standards. The commenter also noted that there have been significant reductions in emissions over the years and that this has led to reductions in title V fees for states (presumably they are referring to states that follow the presumptive minimum approach). To the extent that the commenter is suggesting that this rulemaking action should provide an adjustment to the presumptive minimum fee to account for emissions reductions over time due to successful implementation of emission standards, such considerations are beyond the scope of this rulemaking action. However, the EPA notes that this final rule will result in increased fee collection by states following the presumptive minimum approach and under the Part 71 program, which may address concerns over declining title V fee revenue to some extent.
One commenter (10098) stated that they will be harmed by the proposal to impose new fees based on GHG emissions because the EPA is proposing for the first time minimum payment obligations for facilities subject to GHG permitting requirements. Sources are already subject to GHG permitting requirements and would have to pay increased fees under the proposal. Another commenter (10239) stated that under the proposed rule, non-EGU sources will be harmed because under proposed options 1 and 2, fees will increase for sources that have no GHG emissions and under the current rule.
The EPA disagrees with the comments that finalizing a GHG adjustment would inappropriately increase sources' financial burdens. The EPA has explained, both in the proposal notice and elsewhere in this preamble, the importance of the fee-related revisions to ensure that permitting authorities continue to collect sufficient revenue to cover the costs of addressing GHGs in title V permitting, which could include reviews for sources with low or no GHG emissions and reviews to ensure that sources have not failed to report GHG applicable requirements that apply to them. The EPA believes that the revisions being finalized will result in modest and reasonable fee increases that are necessary to ensure all programs costs are covered by fees for states using the presumptive minimum approach for part 70 and for the part 71 program. The requirement for title V sources to pay fees is not a new obligation under this rulemaking. CAA section 503(b)(3)(A) requires title V sources to pay fees to support the costs of the permitting programs and this obligation has applied to title V sources prior to this rulemaking action. Also, this rulemaking action does not directly address how part 70 sources, including sources with no GHG emissions, would be required by states to pay fees, which are at state discretion.   
One commenter (10660) stated that the EPA should complete an analysis of state fee structures to understand if SIP revisions are necessary to ensure that finalizing the current proposal does not trigger excessive permit fees. 
The EPA disagrees with the commenter. First, EPA notes that changes to a states' operating permit program are not required to occur through a SIP revision and do not generally occur through a SIP revision. Assuming that the commenter intends to state that EPA should analyze whether an individual state needs to revise its EPA-approved operating permit program rules in response to the final rule, certain states may need to revise their rules to add the GHG adjustment of the final rule or to revise the requirements for particular sources to pay fees, but the EPA is not required to conduct such a study and such a study is not needed to ensure smooth implementation of the final rule. The implementation of the GHG adjustment for states that implement the presumptive minimum will be straightforward. A bigger concern for states would be cases where the revised presumptive minimum calculation would result in a need for the state to raise additional revenue by revising state requirements for particular sources to pay fees. Such considerations are beyond the scope of this rulemaking action due to the discretion that the EPA has provided to states for how they charge fees to particular sources.
 
